10-Q

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TABLE OF CONTENTS
PART I—FINANCIAL INFORMATION

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2013
or
o	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: 001-34579

Cobalt International Energy, Inc.
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	27-0821169 (I.R.S. Employer Identification No.)
Cobalt Center 920 Memorial City Way, Suite 100 Houston, Texas (Address of principal executive offices)	77024 (Zip code)

(713) 579-9100
(Registrant's telephone number, including area code)

        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 ý    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 ý    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 ý Accelerated filer o Non-accelerated filer o
(Do not check if a
smaller reporting company) 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 ý

        Number of shares of the registrant's common stock outstanding at September 30, 2013: 411,288,613 shares.

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	37
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Mine Safety Disclosures	38
Item 5.	Other Information	38
Item 6.	Exhibits	39

2

Cautionary Note Regarding Forward-Looking Statements

        This Quarterly Report on Form 10-Q contains estimates and forward-looking statements, principally in "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our 2012 Annual Report on Form 10-K filed on February 26, 2013, may adversely affect our results as indicated in forward-looking statements. You should read this Quarterly Report on Form 10-Q and the documents that we have filed as exhibits hereto completely and with the understanding that our actual future results may be materially different from what we expect.

        Our estimates and forward-looking statements may be influenced by the following factors, among others:

•

the discovery and development of oil and gas reserves;

•

to what extent our and our partners' prospect development and drilling plans are successful;

•

the timing and success of our appraisal and development activities;

•

projected and targeted capital expenditures and other costs and commitments;

•

the availability, cost and reliability of drilling rigs, containment resources, production equipment and facilities, supplies, personnel and oilfield services;

•

current and future government regulation of the oil and gas industry and our operations;

•

changes in environmental laws or the implementation or interpretation of those laws;

•

our ability to obtain financing;

•

uncertainties inherent in making estimates of our oil and natural gas data;

•

our dependence on our key management personnel and our ability to attract and retain qualified personnel;

•

our and our partners' ability to obtain permits and licenses and drill in the U.S. Gulf of Mexico and offshore West Africa;

•

the costs and delays associated with complying with additional legislation and regulation of the oil and gas industry;

•

termination of or intervention in concessions, licenses, permits, rights or authorizations granted by the United States, Angolan and Gabonese governments to us;

•

competition;

•

the volatility of oil prices;

•

our ability to find, acquire or gain access to new prospects;

•

the ability of the containment resources we have under contract to perform as designed or contain or cap any oil spill, blow-out or uncontrolled flow of hydrocarbons;

•

the availability and cost of developing appropriate infrastructure around and transportation to our prospects;

•

military operations, terrorist acts, wars or embargoes;

3

•

our vulnerability to severe weather events, especially tropical storms and hurricanes in the U.S. Gulf of Mexico;

•

the cost and availability of adequate insurance coverage; and

•

other risk factors discussed in the "Risk Factors" section of our 2012 Annual Report on Form 10-K filed on February 26, 2013.

        The words "believe," "may," "will," "aim," "estimate," "continue," "anticipate," "intend," "expect," "plan" and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this Quarterly Report on Form 10-Q might not occur and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.

4

PART I—FINANCIAL INFORMATION

Item 1.    Financial Statements.

COBALT INTERNATIONAL ENERGY, INC.

Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	6
Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2013 and 2012, and for the period November 10, 2005 (Inception) through September 30, 2013	7
Condensed Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity for the Nine Months Ended September 30, 2013 and for the period November 10, 2005 (Inception) through September 30, 2013	8
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012, and for the period November 10, 2005 (Inception) through September 30, 2013	9
Notes to Condensed Consolidated Financial Statements	10

5

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Condensed Consolidated Balance Sheets

	September 30, 2013 (Unaudited)			December 31, 2012
	($ in thousands, except per share data)
Assets
Current assets:
Cash and cash equivalents	$	220,512		$	1,425,815
Joint interest and other receivables		109,853			61,592
Prepaid expenses and other current assets		26,423			23,941
Inventory		83,225			65,286
Short-term restricted funds		228,533			90,440
Short-term investments		1,221,552			789,668
Total current assets		1,890,098			2,456,742
Property, plant, and equipment:
Oil and gas properties, successful efforts method of accounting, net of accumulated depletion of $-0-		1,411,999			1,094,464
Other property and equipment, net of accumulated depreciation and amortization of $3,865 and $2,533, as of September 30, 2013 and December 31, 2012, respectively		11,627			5,292
Total property, plant, and equipment, net		1,423,626			1,099,756
Long-term restricted funds		166,701			395,652
Long-term investments		200,597			36,267
Other assets		34,809			23,042
Total assets	$	3,715,831		$	4,011,459
Liabilities and Stockholders' Equity
Current liabilities:
Trade and other accounts payable	$	10,418		$	67,876
Accrued liabilities		163,056			44,061
Short-term contractual obligations		49,019			49,019
Total current liabilities		222,493			160,956
Long-term debt		1,024,445			991,191
Long-term contractual obligations		124,901			168,238
Other long-term liabilities		2,686			1,856
Total long-term liabilities		1,152,032			1,161,285
Stockholders' Equity:
Common stock, $0.01 par value per share; 2,000,000,000 shares authorized, 406,943,582 and 406,596,884 issued and outstanding as of September 30, 2013 and December 31, 2012, respectively		4,069			4,066
Additional paid-in capital		3,631,977			3,612,987
Accumulated deficit during the development stage		(1,294,740	)		(927,835	)
Total stockholders' equity		2,341,306			2,689,218
Total liabilities and stockholders' equity	$	3,715,831		$	4,011,459

See accompanying notes.

6

Cobalt International Energy, Inc.

(a Development Stage Enterprise)

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,						For the Period November 10, 2005 (Inception) Through September 30, 2013
	2013			2012			2013			2012
	($ in thousands except per share data)
Oil and gas revenue	$	—		$	—		$	—		$	—		$	—
Operating costs and expenses:
Seismic and exploration		14,555			6,327			41,430			35,682			431,603
Dry hole expense and impairment		108,321			15,041			212,199			131,720			450,931
General and administrative		22,347			18,916			68,507			52,239			374,448
Depreciation and amortization		440			269			1,345			782			6,097
Total operating costs and expenses		145,663			40,553			323,481			220,423			1,263,079
Operating income (loss)		(145,663	)		(40,553	)		(323,481	)		(220,423	)		(1,263,079	)
Other income (expense):
Gain on sale of assets		—			—			2,993			—			2,993
Interest income		1,465			1,339			4,610			3,955			19,653
Interest expense		(15,802	)		—			(51,027	)		—			(54,307	)
Total other income (expense)		(14,337	)		1,339			(43,424	)		3,955			(31,661	)
Net income (loss) before income tax		(160,000	)		(39,214	)		(366,905	)		(216,468	)		(1,294,740	)
Income tax expense		—			—			—			—			—
Net income (loss)	$	(160,000	)	$	(39,214	)	$	(366,905	)	$	(216,468	)	$	(1,294,740	)
Basic and diluted income (loss) per share	$	(0.39	)	$	(0.10	)	$	(0.90	)	$	(0.54	)
Basic and diluted weighted average common shares outstanding		406,941,392			406,543,628			406,803,860			402,272,534

See accompanying notes.

7

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Condensed Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity

	General Partner		Class A Limited Partners			Class B Limited Partners			Class C Limited Partners			Common Stock			Additional Paid-in Capital			Accumulated Deficit During Development Stage			Total
	($ in thousands)
Balance, November 10, 2005 (Inception)	$	—	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Class A limited partners' contributions		—		1,256,738			—			—			—			—			—			1,256,738
Class B & C limited partners' equity compensation		—		—			6,984			734			—			—			—			7,718
Common stock issued upon corporate reorganization		—		(1,256,738	)		(6,984	)		(734	)		2,743			1,261,713			—			—
Common stock issued at initial public offering, net of offering costs		—		—			—			—			630			806,629			—			807,259
Common stock issued at private placement		—		—			—			—			32			42,156			—			42,188
Common stock issued at the closing of the over-allotment portion of initial public offering, net of offering costs		—		—			—			—			80			101,176			—			101,256
Common stock issued at public offering, net of costs		—		—			—			—			538			966,974			—			967,512
Common stock issued for restricted stock and stock options		—		—			—			—			44			(44	)		—			—
Equity based compensation		—		—			—			—			—			52,989			—			52,989
Common stock withheld for taxes on equity based compensation		—		—			—			—			(1	)		(360	)		—			(361	)
Exercise of stock options		—		—			—			—			—			338			—			338
Conversion option relating to 2.625% convertible senior notes, net of allocated costs		—		—			—			—			—			381,416			—			381,416
Net income (loss)		—		—			—			—			—			—			(927,835	)		(927,835	)
Balance, December 31, 2012		—		—			—			—			4,066			3,612,987			(927,835	)		2,689,218
Common stock issued for restricted stock and stock options		—		—			—			—			3			(3	)		—			—
Equity based compensation		—		—			—			—			—			18,795			—			18,795
Exercise of stock options		—		—			—			—			—			198			—			198
Net income (loss)		—		—			—			—			—			—			(366,905	)		(366,905	)
Balance, September 30, 2013 (Unaudited)	$	—	$	—		$	—		$	—		$	4,069		$	3,631,977		$	(1,294,740	)	$	2,341,306

See accompanying notes.

8

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
							For the Period November 10, 2005 (Inception) Through September 30, 2013
	2013			2012
	($ in thousands)
Cash flows provided from operating activities
Net income (loss)	$	(366,905	)	$	(216,468	)	$	(1,294,740	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization		1,345			782			6,097
Dry hole expense and impairment of unproved properties		212,199			131,720			450,931
Gain on sale of assets		(2,993	)		—			(2,993	)
Equity based compensation		18,795			16,650			79,501
Amortization of premium (accretion of discount) on investments		17,043			13,269			51,584
Amortization of debt discount		34,751			—			36,500
Other		—			—			558
Changes in operating assets and liabilities:
Joint interest and other receivables		(48,218	)		(32,171	)		(113,413	)
Inventory		(17,939	)		(3,627	)		(83,225	)
Prepaid expense and other current assets		(2,482	)		6,919			(26,423	)
Deferred charges		(13,264	)		2,769			(13,264	)
Trade and other accounts payable		(57,459	)		(53,892	)		10,418
Accrued liabilities and other		(14,856	)		(7,344	)		22,018
Net cash provided by (used in) operating activities		(239,983	)		(141,393	)		(876,451	)
Cash flows from investing activities
Capital expenditures for oil and gas properties		(80,439	)		(130,719	)		(927,387	)
Capital expenditures for other property and equipment		(7,689	)		(3,376	)		(17,733	)
Exploratory wells drilling in process		(356,764	)		(228,299	)		(956,846	)
Proceeds from sale of oil and gas properties		3,006			—			342,007
Change in restricted funds		90,372			51,076			(221,710	)
Proceeds from maturity of investment securities		1,003,020			768,230			3,602,074
Purchase of investment securities		(1,615,834	)		(970,709	)		(5,245,771	)
Net cash provided by (used in) investing activities		(964,328	)		(513,797	)		(3,425,366	)
Cash flows from financing activities
Capital contributions prior to IPO—Class A limited partners		—			—			1,256,180
Proceeds from initial public offering, net of costs		—			—			950,702
Proceeds from public offerings, net of costs		—			489,309			967,513
Proceeds from debt offering, net of costs		(1,190	)		—			1,347,760
Proceeds from stock option exercises		198			275			536
Payments for common stock withheld for taxes on equity based compensation		—			(170	)		(362	)
Net cash provided by (used in) financing activities		(992	)		489,414			4,522,329
Net increase (decrease) in cash and cash equivalents		(1,205,303	)		(165,776	)		220,512
Cash and cash equivalents, beginning of period		1,425,815			292,546			—
Cash and cash equivalents, end of period	$	220,512		$	126,770		$	220,512
Cash paid for interest	$	16,502		$	—		$	16,502
Non-Cash Disclosures
Changes in accrued capital expenditures	$	(92,534	)	$	270,031		$	135,389
Transfer of investment securities to and from restricted funds	$	26		$	178,830		$	178,804

See accompanying notes.

9

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements

(Unaudited)

1. Summary of Significant Accounting Policies

General

        Cobalt International Energy, Inc. (the "Company") is incorporated in the state of Delaware. The Company is an independent, oil-focused exploration and production company with an extensive below salt prospect inventory in the deepwater of the U.S. Gulf of Mexico and offshore Angola and Gabon in West Africa. All of the Company's prospects are oil-focused. To date, the Company's drilling efforts have resulted in discoveries in the U.S. Gulf of Mexico at North Platte, Heidelberg and Shenandoah, offshore Angola at Cameia, Lontra and Mavinga, and offshore Gabon at Diaman. The Company's plan is to continue to mature and drill what it believes are its most promising exploration prospects in the deepwater U.S. Gulf of Mexico and the deepwater offshore Angola and Gabon as it further appraises, evaluates and progresses its existing discoveries toward potential project sanction and development. The Company operates its business in two geographic segments: the U.S. Gulf of Mexico and West Africa.

        The terms "Company," "Cobalt," "we," "us," "our," "ours," and similar terms refer to Cobalt International Energy, Inc. unless the context indicates otherwise.

Basis of Presentation

        The accompanying unaudited condensed consolidated financial statements include the financial statements of Cobalt International Energy, Inc. and all of its wholly-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. Because the Company is a development stage enterprise, it has presented its financial statements in accordance with accounting guidance related to "Development Stage Entities."

        The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles ("GAAP") for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission ("SEC"). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for interim periods are not necessarily indicative of the results that may be presented for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company's Annual Report on Form 10-K for the year ended December 31, 2012.

Reclassifications

        Certain reclassifications have been made to prior periods' financial statements to conform to the current presentation in the unaudited condensed consolidated statements of cash flows.

Use of Estimates

        The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by the Company include (i) accruals related to expenses, (ii) assumptions used in estimating fair value of equity based awards and the fair value of the liability component of the convertible senior notes and (iii) assumptions used

10

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

in impairment testing. Although the Company believes these estimates are reasonable, actual results could differ from these estimates.

Investments

        The Company's policy on accounting for its investments, which consist entirely of debt securities, is based on the accounting guidance relating to "Accounting for Certain Investments in Debt and Equity Securities." The Company considers all highly liquid interest-earning investments with a maturity of three months or less at the date of purchase to be cash equivalents. Investments with original maturities of greater than three months and remaining maturities of less than one year are classified as short-term investments. Investments with maturities beyond one year are classified as long-term investments. The debt securities are carried at amortized costs and classified as held-to-maturity securities as the Company has the positive intent and ability to hold them until they mature. The net carrying value of held-to-maturity securities is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the securities. Held-to-maturity securities are stated at amortized cost, which approximates fair market value as of September 30, 2013 and December 31, 2012. Income related to these securities is reported as a component of interest income in the Company's condensed consolidated statement of operations. See Note 5—Investments.

        Investments are considered to be impaired when a decline in fair value is determined to be other-than-temporary. The Company conducts a regular assessment of its debt securities with unrealized losses to determine whether securities have other-than-temporary impairment ("OTTI"). This assessment considers, among other factors, the nature of the securities, credit rating or financial condition of the issuer, the extent and duration of the unrealized loss, market conditions and whether the Company intends to sell or whether it is more likely than not that the Company will be required to sell the debt securities. As of September 30, 2013 and December 31, 2012, the Company has no OTTI in its debt securities.

Capitalized Interest

        For exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 7—Property, Plant, and Equipment and Note 8—Long-term Debt.

Earnings (Loss) Per Share

        Basic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted income (loss) per share should include the potential dilutive impact of non-vested restricted shares, non-vested restricted stock units, outstanding stock options and 2.625% convertible senior notes due 2019, during the period, unless their effect is anti-dilutive. For the three months and nine months ended September 30, 2013, 6,744,278 shares of non-vested restricted stock, non-vested restricted stock units, outstanding stock options and 2.625% convertible senior notes due 2019, were excluded from the diluted income (loss) per share because they are anti-dilutive. For the

11

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

1. Summary of Significant Accounting Policies (Continued)

three months and nine months ended September 30, 2012, 5,594,092 shares of non-vested restricted stock, non-vested restricted stock units and outstanding stock options were excluded from the diluted income (loss) per share because they are anti-dilutive.

2. Cash and Cash Equivalents

        Cash and cash equivalents consisted of the following:

	September 30, 2013		December 31, 2012
	($ in thousands)
Cash at banks	$	34,001	$	65,935
Money market funds		89,497		1,105,148
Held-to-maturity securities(1)		97,014		254,732
	$	220,512	$	1,425,815

(1)

These securities mature three months or less from the date of purchase.

3. Restricted Funds

        Restricted funds consisted of the following:

	September 30, 2013		December 31, 2012
	($ in thousands)
Short-term:
Ensco 8503 escrow account	$	90,315	$	90,440
Collateral on letters of credit for Angola		138,218		—
	$	228,533	$	90,440
Long-term:
Ensco 8503 escrow account		—		90,440
Collateral on letters of credit for Angola		166,529		304,492
Other vendor restricted deposits		172		720
	$	166,701	$	395,652

12

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

4. Joint Interest and Other Receivables

        Joint interest and other receivables result primarily from billing shared costs under the respective operating agreements to the Company's partners. These are usually settled within 30 days of the invoice date.

	September 30, 2013		December 31, 2012
	($ in thousands)
Partners in the U.S. Gulf of Mexico	$	45,663	$	52,439
Partners in West Africa(1)		53,223		2,185
Accrued interest on investment securities		8,313		3,647
Vendors' receivables		1,582		1,526
Other		1,072		1,795
Total	$	109,853	$	61,592

(1)

The amount of $53.2 million as of September 30, 2013 includes $30.6 million related to our partners on Block 20 offshore Angola and $22.6 million related to our partners on Blocks 9 and 21 offshore Angola. Although we expect to collect these receivables in full, including $11.3 million that is currently past due, the allocation of the receivable amongst our partners on Blocks 9 and 21 offshore Angola may change as a result of the working interest transfers discussed below.

        On September 19, 2013, we received a letter from Sociedade Nacional de Combustíveis de Angola—Empresa Pública notifying us that Nazaki Oil and Gáz, S.A. had transferred a 15% working interest in each of Blocks 9 and 21 offshore Angola out of its 30% working interest in each block to Sonangol Pesquisa e Produção, S.A. ("Sonangol P&P"). The letter stated that these transfers were effective as of March 14, 2013 for Block 9 and February 18, 2013 for Block 21, corresponding to the dates of the executive decrees from the Angola Ministry of Petroleum authorizing such transfers. As a result of these transfers, Sonangol P&P now has a working interest of 35% and paying interest of 18.75% (which is applicable only during the exploration phase on Blocks 9 and 21) in each of Blocks 9 and 21. Our working interest of 40% and paying interest of 62.5% (which is applicable only during the exploration phase on Blocks 9 and 21) in each of Blocks 9 and 21 remains unchanged as a result of these transfers. We are the operator of Blocks 9 and 21.

5. Investments

        The Company's investments in held-to-maturity securities which are recorded at amortized cost and approximate fair market value as of September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013		December 31, 2012
	($ in thousands)
U.S. Treasury securities	$	394,690	$	483,775
Corporate securities		936,183		510,691
Commercial paper		512,981		562,975
Certificates of deposit		70,000		7,000
Total	$	1,913,854	$	1,564,441

13

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

5. Investments (Continued)

        The Company's condensed consolidated balance sheet included the following held-to-maturity securities:

	September 30, 2013		December 31, 2012
	($ in thousands)
Cash and cash equivalents	$	97,014	$	254,732
Short-term restricted funds		228,533		90,440
Short-term investments		1,221,552		789,668
Long-term restricted funds		166,158		393,334
Long-term investments		200,597		36,267
	$	1,913,854	$	1,564,441

        The contractual maturities of these held-to-maturity securities as of September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	($ in thousands)
Within 1 year	$	1,713,257	$	1,713,257	$	1,528,174	$	1,528,174
After 1 year		200,597		200,597		36,267		36,267
	$	1,913,854	$	1,913,854	$	1,564,441	$	1,564,441

6. Fair Value Measurements

        The fair values of the Company's cash and cash equivalents, joint interest and other receivables, restricted funds and investments approximate their carrying amounts due to their short-term duration. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. The Company categorizes each of its fair value measurements as applicable to one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. The levels are:

        Level 1—Quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities. This category includes the Company's cash and money market funds.

        Level 2—Quoted prices in non-active markets or in active markets for similar assets or liabilities, and inputs other than quoted prices that are observable, for the asset or liability, either directly or indirectly, for substantially the full contractual term of the asset or liability being measured. This category includes the Company's U.S. Treasury bills, U.S. Treasury notes, U.S. Government agency securities, commercial paper, corporate bonds, municipal bonds and certificates of deposits.

14

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

6. Fair Value Measurements (Continued)

        Level 3—Inputs that are generally unobservable and typically reflect management's estimate of assumptions that market participants would use in pricing the asset or liability. The Company does not currently have any financial instruments categorized as Level 3.

        The following tables summarize the Company's significant financial instruments as categorized by the fair value measurement hierarchy:

	Level 1				Level 2
									Balance as of September 30, 2013
	Carrying Value		Fair Value(1)		Carrying Value		Fair Value(1)
	($ in thousands)
Cash and cash equivalents:
Cash	$	34,001	$	34,001	$	—	$	—	$	34,001
Money market funds		89,497		89,497		—		—		89,497
Commercial paper		—		—		72,014		72,014		72,014
Certificate of deposits		—		—		25,000		25,000		25,000
Subtotal		123,498		123,498		97,014		97,014		220,512
Short-term restricted funds:
U.S. Treasury bills		—		—		90,315		90,315		90,315
U.S. Treasury notes		—		—		138,218		138,218		138,218
Subtotal		—		—		228,533		228,533		228,533
Short-term investments:
Corporate bonds		—		—		735,586		735,586		735,586
Commercial paper		—		—		440,966		440,966		440,966
Certificates of deposits		—		—		45,000		45,000		45,000
Subtotal		—		—		1,221,552		1,221,552		1,221,552
Long-term restricted funds:
Cash		172		172		—		—		172
Money market funds		371		371		—		—		371
U.S. Treasury notes		—		—		166,158		166,158		166,158
Subtotal		543		543		166,158		166,158		166,701
Long-term investments:
Corporate bonds		—		—		200,597		200,597		200,597
Subtotal		—		—		200,597		200,597		200,597
Total	$	124,041	$	124,041	$	1,913,854	$	1,913,854	$	2,037,895

15

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

6. Fair Value Measurements (Continued)

	Level 1				Level 2
									Balance as of December 31, 2012
	Carrying Value		Fair Value(1)		Carrying Value		Fair Value(1)
	($ in thousands)
Cash and cash equivalents:
Cash	$	65,935	$	65,935	$	—	$	—	$	65,935
Money market funds		1,105,148		1,105,148		—		—		1,105,148
Commercial paper		—		—		247,206		247,206		247,206
Corporate bonds		—		—		7,526		7,526		7,526
Subtotal		1,171,083		1,171,083		254,732		254,732		1,425,815
Short-term restricted funds:
U.S. Treasury bills		—		—		90,440		90,440		90,440
Subtotal		—		—		90,440		90,440		90,440
Short-term investments:
Corporate bonds		—		—		466,898		466,898		466,898
Commercial paper		—		—		315,769		315,769		315,769
Certificates of deposits		—		—		7,001		7,001		7,001
Subtotal		—		—		789,668		789,668		789,668
Long-term restricted funds:
Money market funds		2,318		2,318		—		—		2,318
U.S. Treasury bills		—		—		178,216		178,216		178,216
U.S. Treasury notes		—		—		215,118		215,118		215,118
Subtotal		2,318		2,318		393,334		393,334		395,652
Long-term investments:
Corporate bonds		—		—		36,267		36,267		36,267
Subtotal		—		—		36,267		36,267		36,267
Total	$	1,173,401	$	1,173,401	$	1,564,441	$	1,564,441	$	2,737,842

(1)

As of September 30, 2013 and December 31, 2012, the Company did not record any OTTI on these assets.

16

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

7. Property, Plant, and Equipment

        Property, plant, and equipment is stated at cost less accumulated depreciation/amortization and consisted of the following:

	Estimated Useful Life (Years)	September 30, 2013			December 31, 2012
		($ in thousands)
Oil and Gas Properties:
Unproved oil and gas properties		$	754,909		$	721,853
Less: accumulated valuation allowance			(110,017	)		(78,413	)
			644,892			643,440
Exploratory wells in process			767,107			451,024
Total oil and gas properties, net			1,411,999			1,094,464
Other Property and Equipment:
Computer equipment and software	3		4,386			3,166
Office equipment and furniture	3 - 5		2,132			2,093
Vehicles	3		265			268
Leasehold improvements	3 - 10		2,392			2,298
Running tools and equipment	5		6,317			—
			15,492			7,825
Less: accumulated depreciation and amortization(1)			(3,865	)		(2,533	)
Total other property and equipment, net			11,627			5,292
Property, plant, and equipment, net		$	1,423,626		$	1,099,756

(1)

During the year ended December 31, 2012, the Company wrote off $2.2 million of old computer equipment and leasehold improvements which were fully depreciated and which had no impact on the consolidated statements of operations and consolidated statements of cash flow.

        The Company recorded $0.4 million and $0.3 million for the three months ended September 30, 2013 and 2012, respectively, $1.3 million and $0.8 million for the nine months ended September 30, 2013 and 2012, respectively, and $6.1 million of depreciation and amortization for the period November 10, 2005 (inception) through September 30, 2013, respectively.

Unproved Oil and Gas Properties

        On December 20, 2011, the Company acquired a 40% working interest in Block 20 offshore Angola for a total consideration of $347.1 million, of which $337.1 million is contractually scheduled to be paid over five years commencing in January 2012. As of September 30, 2013, out of the $337.1 million, $165.7 million has been paid and the remaining $171.4 million was accrued in short-term and long-term contractual obligations. See Note 9—Contractual Obligations. In addition to the Block 20 interests, the Company has $10.8 million of unproved property acquisition costs relating to

17

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

7. Property, Plant, and Equipment (Continued)

its 40% interests in Blocks 9 and 21 offshore Angola and its 21.25% working interest in the Diaba block offshore Gabon.

        As of September 30, 2013, the Company also has $287.0 million of unproved property acquisition costs, net of valuation allowance for impairment, relating to its U.S. Gulf of Mexico properties. On February 26, 2013, the Company executed a Purchase and Sale agreement (the "PSA") to sell its ownership interests on an unproved oil and gas property on Mississippi Canyon Block 209 for a total consideration of $5.6 million. The Company received $1.5 million at closing and an additional $1.5 million in September 2013 when the buyer commenced operations on the property. Pursuant to the terms and conditions of the PSA, the Company will receive the remaining $2.6 million contingent upon the purchaser's commencement of production on this property in the future. For the nine months ended September 30, 2013, the Company recognized a gain of $3.0 million on the sale of assets as a result of this transaction. During the nine months ended September 30, 2013, the Company paid a total consideration of $37.6 million for acquisition of ownership interests in unproved oil and gas properties on Garden Banks Block 822, Mississippi Canyon Block 605 and Walker Ridge Block 232 in the U.S. Gulf of Mexico.

        As of September 30, 2013 and December 31, 2012, the Company has a net total of $644.9 million and $643.4 million, respectively, of unproved property acquisition costs on the condensed consolidated balance sheets.

        Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. There are no impairment indicators to date that would require the Company to impair the unproved properties in Blocks 9, 20, and 21 offshore Angola and in the Diaba block offshore Gabon. Oil and gas leases for unproved properties in the U.S. Gulf of Mexico with carrying value greater than $1.0 million are assessed individually for impairment based on the Company's current exploration plans and an allowance for impairment is provided if impairment is indicated. Leases that are individually less than $1.0 million in carrying value or are near expiration are amortized on a group basis over the average terms of the leases at rates that provide for full amortization of leases upon lease expiration. These leases have expiration dates ranging from 2013 through 2022. As of September 30, 2013 and December 31, 2012, the balance for unproved properties that were subject to amortization before impairment provision was $69.4 million and $69.1 million, respectively. The Company recorded a lease impairment allowance of $31.3 million and $2.3 million for the three months ended September 30, 2013 and 2012, respectively, $36.1 million and $57.8 million for the nine months ended September 30, 2013 and 2012, respectively, and $114.7 million for the period November 10, 2005 (inception) through September 30, 2013.

Capitalized Costs

        If an exploratory well provides evidence as to the existence of sufficient quantities of hydrocarbons to justify potential completion as a producing well, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas (generally, deepwater and international locations) depending upon,

18

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

7. Property, Plant, and Equipment (Continued)

among other things, (i) the amount of hydrocarbons discovered, (ii) the outcome of planned geological and engineering studies, (iii) the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan and (iv) the requirement for government sanctioning in international locations before proceeding with development activities.

        The following tables reflect the Company's net changes in and the cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs):

	September 30, 2013			December 31, 2012
	($ in thousands)
Beginning of period	$	451,024		$	178,338
Addition to capitalized exploratory and development costs:
U.S. Gulf of Mexico:
Exploratory well costs		111,724			178,295
Development and pre-development well costs		39,084			—
Capitalized interest		5,206			—
West Africa:
Exploratory well costs(1)		320,464			168,309
Pre-development well costs		9,988			—
Capitalized interest		5,685			—
Reclassifications to wells, facilities, and equipment based on determination of proved reserves		—			—
Amounts charged to expense(2)		(176,068	)		(73,918	)
End of period	$	767,107		$	451,024

(1)

This amount includes $116.0 million of total drilling costs associated with the Mavinga #1 exploratory well, of which $103.5 million has been capitalized as of September 30, 2013 and will remain suspended pending further evaluation of the well to determine possible utilization for the development of the Mavinga field.

(2)

The amount of $176.1 million for the nine months ended September 30, 2013 represents $64.1 million of impairment charges on the Ardennes #1 exploratory well which did not encounter commercial hydrocarbons, $82.4 million of impairment charges related to the lowest drilled interval evaluated by the Cameia #2 drill stem test, which failed to flow measurable hydrocarbons, $17.1 million of impairment charges on the Diaman #1 exploratory well which needed to be re-spud due to mechanical problems with the wellbore, and $12.5 million of impairment charges related to the lowest interval beneath the pay zone that was drilled by the Mavinga #1 exploratory well and determined to have no further utility. The amount of $73.9 million for the year ended December 31, 2012 represents impairment charges on exploratory wells, including $4.1 million for the Heidelberg #3 sidetrack well, $8.1 million for the Ligurian #1 exploratory well, $49.0 million for the Ligurian #2 exploratory well and $12.7 million for the Shenandoah #2 appraisal well.

19

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

7. Property, Plant, and Equipment (Continued)

	September 30, 2013		December 31, 2012
	($ in thousands)
Cumulative costs:
U.S. Gulf of Mexico
Exploratory well costs	$	215,395	$	208,275
Development and pre-development well costs		79,572		—
Capitalized interest		5,206		—
West Africa
Exploratory well costs		447,277		242,749
Pre-development well costs		13,972		—
Capitalized interest		5,685		—
	$	767,107	$	451,024
Well costs capitalized for a period greater than one year after completion of drilling (included in table above)	$	286,968	$	194,853

        As of September 30, 2013, capitalized well costs that have been suspended longer than one year are associated with the Shenandoah, Heidelberg, North Platte and Cameia discoveries. These well costs except for Heidelberg are suspended pending ongoing evaluation including, but not limited to, results of additional appraisal drilling, well-test analysis, additional geological and geophysical data and approval of a development plan. Management believes these discoveries exhibit sufficient indications of hydrocarbons to justify potential development and is actively pursuing efforts to fully assess them. If additional information becomes available that raises substantial doubt as to the economic or operational viability of these discoveries, the associated costs will be expensed at that time. The Heidelberg discovery has been sanctioned for development and the Heidelberg capitalized exploratory and appraisal well costs were reclassified to development well costs as of September 30, 2013.

8. Long-term Debt

        On December 17, 2012, the Company issued $1.38 billion aggregate principal amount of its 2.625% convertible senior notes due 2019 (the "Notes"). The Notes are the Company's senior unsecured obligations and interest is payable semi-annually in arrears on June 1 and December 1 of each year. For the nine months ended September 30, 2013, the Company paid $16.5 million in interest on the notes. The Notes will mature on December 1, 2019, unless earlier repurchased or converted in accordance with the terms of the Notes. The Notes may be converted at the option of the holder at any time prior to 5:00 p.m., New York City time, on the second scheduled trading day immediately preceding the maturity date, in multiples of $1,000 principal amount. The Notes are convertible at an initial conversion rate of 28.023 shares of common stock per $1,000 principal amount, representing an initial conversion price of approximately $35.68 per share for a total of approximately 38.7 million underlying shares. The conversion rate is subject to adjustment upon the occurrence of

20

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

8. Long-term Debt (Continued)

certain events, as defined in the indenture governing the Notes, but will not be adjusted for any accrued and unpaid interest except in limited circumstances. Upon conversion, the Company's conversion obligation may be satisfied, at the Company's option, in cash, shares of common stock or a combination of cash and shares of common stock.

        Holders of the Notes who convert their Notes in connection with a "make-whole fundamental change", as defined in the indenture governing the Notes, may be entitled to a make-whole premium in the form of an increase in the conversion rate. Additionally, in the event of a fundamental change, as defined in the indenture governing the Notes, holders of the Notes may require the Company to repurchase for cash all or a portion of their Notes equal to $1,000 or a multiple of $1,000 at a fundamental change repurchase price equal to 100% of the principal amount of Notes, plus accrued and unpaid interest, if any, to, but not including, the fundamental change repurchase date.

        Upon the occurrence of an Event of Default, as defined within the Indenture governing the Notes, the Trustee or the Holders of at least 25% in aggregate principal amount of the Notes then outstanding may declare 100% of the principal of, and accrued and unpaid interest on, all the Notes to be due and payable immediately.

        In accordance with accounting guidance relating to, "Debt with Conversion and Other Options", the Company separately accounts for the liability and equity conversion components of the Notes due to the Company's option to settle the conversion obligation in cash. The fair value of the debt excluding the conversion feature at the date of issuance was estimated to be approximately $989.5 million and was calculated based on the fair value of similar non-convertible debt instruments. The resulting value of the conversion option of $390.5 million was recognized as a debt discount and recorded as additional paid-in capital on the Company's consolidated balance sheets. Total debt issue cost on the Notes was $32.2 million of which $23.1 million was allocated to the liability component of the Notes and $9.1 million to the equity component of the Notes. The debt discount and the liability component of the debt issue costs are amortized over the term of the Notes. The effective interest rate used to amortize the debt discount and the liability component of the debt issue costs was approximately 8.40% based on the Company's estimated non-convertible borrowing rate as of the date the Notes were issued. Since the Company incurred losses for all periods, the impact of the conversion option would be anti-dilutive to the earnings per share and therefore was not included in the calculation.

        The carrying amounts of the liability components of the Notes were as follows:

	September 30, 2013							December 31, 2012
	Principal Amount		Unamortized discount(1)			Carrying Amount		Principal Amount		Unamortized discount			Carrying Amount
	($ in thousands)
Carrying amount of liability component
2.625% convertible senior notes	$	1,380,000	$	(355,555	)	$	1,024,445	$	1,380,000	$	(388,809	)	$	991,191

(1)

Unamortized discount will be amortized over the remaining life of the Notes which is 6.25 years.

21

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

8. Long-term Debt (Continued)

        The carrying amounts of the equity components of the Notes were as follows:

	September 30, 2013			December 31, 2012
	($ in thousands)
Debt discount relating to value of conversion option	$	390,540		$	390,540
Debt issue costs		(9,124	)		(9,124	)
Total	$	381,416		$	381,416

        Fair Value    The fair value of the Notes excluding the conversion feature was $1,028.8 million and $989.5 million as of September 30, 2013 and December 31, 2012, respectively, and was calculated based on the fair value of similar non-convertible debt instruments (level 2) since an observable quoted price of the Notes or a similar asset or liability is not readily available.

        Interest expense was as follows:

									For the Period November 10, 2005 (Inception) through September 30, 2013
	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in thousands)
Interest expense associated with accrued interest(1)	$	3,956	$	—	$	16,276	$	—	$	17,570
Interest expense associated with accretion of debt discount		11,307		—		33,254		—		35,165
Interest expense associated with amortization of debt issue costs		539		—		1,497		—		1,572
Total	$	15,802	$	—	$	51,027	$	—	$	54,307

(1)

The $4.0 million and $16.3 million for the three and nine months ended September 30, 2013, respectively, represent interest expense net of capitalized amount of $5.1 million and $10.9 million, respectively.

22

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

9. Contractual Obligations

        The short-term and long-term contractual obligations consist of the following:

	September 30, 2013		December 31, 2012
	($ in thousands)
Short-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	150	$	150
Social obligation payments for Block 21, offshore Angola		300		300
Social obligation and bonus payments for Block 20, offshore Angola(1)		48,569		48,569
	$	49,019	$	49,019
Long-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	668	$	848
Social obligation payments for Block 21, offshore Angola		1,382		1,684
Social obligation and bonus payments for Block 20, offshore Angola(1)		122,851		165,706
	$	124,901	$	168,238

(1)

The total amount of social obligation payments for Block 20 has been capitalized. See Note 7—Property, Plant, and Equipment.

10. Seismic and Exploration Expenses

        Seismic and exploration expenses consisted of the following:

									For the Period November 10, 2005 (Inception) through September 30, 2013
	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in Thousands)
Seismic costs	$	13,461	$	4,592	$	34,548	$	29,933	$	376,596
Seismic cost recovery(1)		—		—		—		—		(25,126	)
Leasehold delay rentals		944		1,184		4,050		4,062		36,953
Force Majeure expense(2)		—		—		—		—		13,549
Drilling rig and other exploration expenses		150		551		2,832		1,687		29,631
	$	14,555	$	6,327	$	41,430	$	35,682	$	431,603

(1)

This amount represents reimbursement from partners of past seismic costs incurred by the Company.

23

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

10. Seismic and Exploration Expenses (Continued)

(2)

This amount represents expenditures resulting from suspension of drilling activities in the U.S. Gulf of Mexico as a result of the explosion and sinking of the Deepwater Horizon drilling rig in the U.S. Gulf of Mexico, the resulting oil spill and the regulatory response thereto and other exploratory expenses.

11. Equity Based Compensation

        The Company accounts for stock-based compensation at fair value. The Company grants various types of stock-based awards including stock options, restricted stock and performance-based awards. The fair value of stock option awards is determined using the Black-Scholes-Merton option-pricing model. For restricted stock awards with market conditions, the fair value of the awards is measured using the asset-or-nothing option pricing model. Restricted stock awards without market conditions and the performance-based awards are valued using the market price of the Company's common stock on the grant date. The Company records compensation cost, net of estimated forfeitures, for stock-based compensation awards over the requisite service period except for performance-based awards. For performance-based awards, compensation cost is recognized over the requisite service period as and when the Company determines that the achievement of the performance condition is probable, using the per-share fair value measured at grant date.

        During the nine months ended September 30, 2013, the Company granted a total of 605,940 shares of restricted stock and 959,023 stock options to employees. During the nine months ended September 30, 2013, the Company also granted 11,056 shares of common stock as retainer awards to non-employee directors who elected to be compensated by stock in lieu of cash payments. In addition, the Company granted a total of 34,833 restricted stock units to non-employee directors during the nine months ended September 30, 2013.

        The Company recorded equity based compensation expense, net of forfeitures, of $6.5 million and $4.7 million for the three months ended September 30, 2013 and 2012, respectively, $18.8 million and $16.7 million for the nine months ended September 30, 2013 and 2012, respectively, and $79.5 million for the period November 10, 2005 (inception) through September 30, 2013.

12. Segment Information

        The Company currently has two geographic operating segments for its exploratory operations. The operating segments are focused in the deepwater U.S. Gulf of Mexico and offshore West Africa. The

24

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

12. Segment Information (Continued)

following tables provide the geographic operating segment information for the three and nine months ended September 30, 2013 and 2012:

	United States			West Africa			Total
	($ in thousands)
Three months ended September 30, 2013
Operating costs and expense	$	122,995		$	22,668		$	145,663
Operating income (loss)		(122,995	)		(22,668	)		(145,663	)
Other income (expense)								(14,337	)
Net income (loss)							$	(160,000	)
Additions to Property and Equipment, net(1)	$	1,329		$	148,262		$	149,591
Three months ended September 30, 2012
Operating costs and expense	$	(32,593	)	$	(7,960	)	$	(40,553	)
Operating income (loss)		(32,593	)		(7,960	)		(40,553	)
Other income (expense)								1,339
Net income (loss)							$	(39,214	)
Additions to Property and Equipment, net(1)	$	42,851		$	51,946		$	94,797

	United States			West Africa			Total
	($ in thousands)
Nine months ended September 30, 2013
Operating costs and expense	$	167,817		$	155,664		$	323,481
Operating income (loss)		(167,817	)		(155,664	)		(323,481	)
Other income (expense)								(43,424	)
Net income (loss)							$	(366,905	)
Additions to Property and Equipment, net(1)	$	93,657		$	230,212		$	323,869
Nine months ended September 30, 2012
Operating costs and expense	$	(189,171	)	$	(31,252	)	$	(220,423	)
Operating income (loss)		(189,171	)		(31,252	)		(220,423	)
Other income (expense)								3,955
Net income (loss)							$	(216,468	)
Additions to Property and Equipment, net(1)	$	(7,438	)	$	170,235		$	162,797

(1)

These amounts are net of accumulated allowance for impairment on oil and gas properties and accumulated depreciation and amortization on other property and equipment.

25

Cobalt International Energy, Inc.
(a Development Stage Enterprise)

Notes to Condensed Consolidated Financial Statements (Continued)

(Unaudited)

13. Contingencies

        The Company is not currently party to any legal proceedings. However, from time to time the Company may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. It is not presently possible to determine whether any such matters will have a material adverse effect on the Company's consolidated financial position, results of operations, or liquidity.

26

Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including, without limitation, those set forth in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements" and the other matters set forth in this Quarterly Report on Form 10-Q. The following discussion of our financial condition and results of operations should be read in conjunction with our financial statements and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2012.

Overview

        We are an independent, oil-focused exploration and production company with an extensive below salt prospect inventory in the deepwater U.S. Gulf of Mexico and offshore Angola and Gabon in West Africa. All of our prospects are oil-focused. To date, our drilling efforts have resulted in discoveries in the U.S. Gulf of Mexico at North Platte, Heidelberg and Shenandoah, offshore Angola at Cameia, Lontra and Mavinga and offshore Gabon at Diaman. Our plan is to continue to mature and drill what we believe are our most promising exploration prospects in the deepwater U.S. Gulf of Mexico and the deepwater offshore Angola and Gabon as we further appraise, evaluate and progress our existing discoveries toward potential project sanction and development. We operate our business in two geographic segments: the U.S. Gulf of Mexico and West Africa.

Operational Highlights

        We announced the results of drilling operations on four exploratory wells, including three discoveries at Lontra, Mavinga and Diaman, as set forth below:

•

Lontra.  On October 29, 2013, we announced that the Lontra #1 exploratory well had reached total depth and the drilling and evaluation results confirm an oil and gas discovery. Further evaluation, including a drill stem test, is required to assess Lontra's potential. We expect to be able to provide more information on the Lontra #1 exploratory well prior to year end. Upon completion of testing operations, we plan to mobilize the Petroserv SSV Catarina drilling rig to the Orca #1 pre-salt exploratory well (formerly the Baleia prospect), located approximately 25 kilometers (15.5 miles) northeast of Lontra in Block 20. We are the operator of Lontra and have a 40% working interest.

•

Mavinga.  On October 29, 2013, we announced that the Mavinga #1 exploratory well had reached total depth and encountered approximately 30 meters (100 feet) of net oil pay. This discovery was confirmed by the successful production of oil from mini drill stem tests, direct pressure and permeability measurements and log and core analysis. Efforts to establish a sustained flow rate from a full drill stem test were not successful. We are in the early stages of determining what operational issues may have prevented the production from the oil reservoir during the drill stem test. We estimate a gross oil column of up to 650 feet (200 meters) at the crest of the Mavinga structure updip of the Mavinga #1 exploratory well. Additional drilling will be required to confirm the ultimate gross thickness of the mound and its reservoir quality; however the Mavinga discovery is expected to be tied-back to and become part of the planned Cameia development complex in Block 21. We are the operator of Mavinga and have a 40% working interest.

•

Diaman.  On August 19, 2013, we announced that the Diaman #1B exploratory well was drilled to a total depth of 5,585 meters (18,323 feet), and encountered approximately 50-55 meters (160-180 feet) of net hydrocarbons in the objective pre-salt formations on the Diaba block offshore Gabon. The Diaman #1B exploratory well successfully confirmed the existence of a working petroleum system, a salt seal, and high-quality sandstone reservoirs. We and our

27

partners are conducting a full analysis of the Diaman #1B exploratory well results in order to determine our future exploratory and appraisal drilling activity on the Diaba block. We have a 21.25% working interest in the Diaman discovery.

•

Ardennes.  On August 19, 2013, we announced that the Ardennes #1 exploratory well had reached its objective total depth of 36,552 feet (11,141 meters) after having drilled through the targeted Miocene and Inboard Lower Tertiary formations. The well did not encounter commercial hydrocarbons and it was subsequently plugged and abandoned. We are the operator of Ardennes and have a 42% working interest.

        We continued drilling operations on two exploratory wells as set forth below:

•

Bicuar.  On October 20, 2013, we spud the Bicuar #1A exploratory well, which will target pre-salt horizons on Block 21 offshore Angola. We expect results from the Bicuar #1A exploratory well in the first half of 2014. We are the operator of Bicuar and have a 40% working interest.

•

Aegean.  On September 12, 2013, we spud the Aegean #1 exploratory well, which will target Inboard Lower Tertiary horizons in the deepwater U.S. Gulf of Mexico. We expect results from the Aegean #1 exploratory well in the first half of 2014. We are the operator of Aegean and have a 60% working interest.

        We also continued development efforts with respect to our Heidelberg, Cameia, North Platte and Shenandoah discoveries as set forth below:

•

The Heidelberg development project was formally sanctioned in May 2013 and work continues on schedule on hull fabrication and procurement of the long-lead equipment for the topsides, subsea and export system. Anadarko, as operator, has publicly indicated that it expects first production from the Heidelberg field in 2016. We have a 9.375% working interest in the Heidelberg development.

•

With respect to our Cameia discovery on Block 21 offshore Angola, we have continued to define our subsurface imaging by integrating the data from our newly acquired 3D seismic survey. We are also conducting static and dynamic reservoir modeling and performance simulations. This information will enable us to prepare estimates for the cost of and timeline associated with the procurement, fabrication and commissioning of equipment and materials, including an FPSO, as well as the drilling and completion of development wells. These estimates, combined with our subsurface description, will be used to generate an integrated field development plan for the Cameia field. The integrated field development plan must be approved by our partners, Sonangol and the Angola Ministry of Petroleum before the Cameia development may be formally sanctioned. We expect formal sanction of the Cameia development plan in 2014 and first production from Cameia in 2017, assuming continued alignment with our partners and Sonangol, among other things. We are the operator of and have a 40% working interest in the Cameia discovery.

•

With respect to our appraisal and pre-development efforts on our North Platte discovery, a 5,200 square mile 3D seismic survey over the greater North Platte area has been completed, of which we have licensed data covering approximately 1,350 square miles. Our initial processing of this 3D seismic data is underway. This 3D seismic survey is designed to further improve the sub-salt imaging of our North Platte discovery as well as several other Inboard Lower Tertiary prospects in which we have working interests. We will use this newly acquired and re-processed 3D seismic data to optimize potential appraisal and development well locations on North Platte. We are also currently conducting a number of studies to support our appraisal and pre-development efforts on North Platte, including reservoir fluids analyses and geo-mechanical and subsea studies. We have begun reservoir characterization and geo-cellular modeling studies in order to

28

better understand reservoir flow, productivity and recovery characteristics of the North Platte field. These studies will help us define and evaluate our development options for North Platte. We are the operator of and have a 60% working interest in the North Platte discovery.

•

With respect to our Shenandoah discovery, we anticipate that Anadarko, as operator, will spud an additional appraisal well in mid-2014. We have a 20% working interest in the Shenandoah discovery.

        Other operational highlights during the third quarter include the following:

•

On September 19, 2013, we received a letter from Sociedade National de Combustíveis de Angola—Empresa Pública ("Sonangol") notifying us that Nazaki Oil and Gáz, S.A. had transferred a 15% working interest in each of Blocks 9 and 21 offshore Angola (out of its 30% working interest in each block) to Sonangol Pesquisa e Produção, S.A. ("Sonangol P&P"). The letter stated that these transfers were effective as of March 14, 2013 for Block 9 and February 18, 2013 for Block 21, corresponding to the dates of the executive decrees from the Angola Ministry of Petroleum authorizing such transfers. As a result of these transfers, Sonangol P&P now has a working interest of 35% and paying interest of 18.75% (which is applicable only during the exploration phase on Blocks 9 and 21) in each of Blocks 9 and 21. Our working interest of 40% and paying interest of 62.5% (which is applicable only during the exploration phase on Blocks 9 and 21) in each of Blocks 9 and 21 remains unchanged as a result of these transfers. We are the operator of Blocks 9 and 21.

•

On August 5, 2013, we executed a drilling contract with Rowan Reliance Limited, an affiliate of Rowan Companies plc, for the Rowan Reliance, a new-build, ultra-deepwater dynamically positioned drillship that will support our U.S. Gulf of Mexico drilling campaign. The Rowan Reliance drillship will be capable of operating in water depths of up to 12,000 feet and drilling to measured depths of up to 40,000 feet. The drilling contract provides for a firm three-year commitment, expected to begin in early 2015, at a day rate of approximately $602,000 (inclusive of mobilization fees) and two one-year extension options at day rates to be mutually agreed. Such rates are subject to standard reimbursement and escalation contractual provisions.

Third Quarter 2013 Financial Highlights

•

We recorded a net loss of approximately $160.0 million, a 308% increase from the third quarter of 2012. Total operating expenses were approximately $145.7 million, a 259% increase from the third quarter of 2012. The increase in operating expenses for the three months ended September 30, 2013 was attributed primarily to higher impairment charge and dry hole expense of $108.3 million during the three months ended September 30, 2013, which relates primarily to impairment charges and dry hole expense on our Ardennes prospect, as compared to $15.0 million of impairment charge and dry hole expense during the three months ended September 30, 2012.

•

Capital and operating expenditures, including Block 20 contractual obligations, were approximately $288.6 million for the three months ended September 30, 2013.

•

Including our existing cash and investments on hand and restricted cash as of September 30, 2013, we have approximately $2.0 billion of liquidity.

Results of Operations

        We operate our business in two geographic segments: the United States and West Africa. The discussion of the results of operations and the period-to-period comparisons presented below for each operating segment and our consolidated operations analyzes our historical results. The following discussion may not be indicative of future results.

29

Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012

	Three Months Ended September 30,
	2013			2012			Increase (Decrease)			%
	($ in thousands)
United States Segment:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses:
Seismic and exploration		13,459			5,072			8,387			165	%
Dry hole expense and impairment		95,417			15,041			80,376			534	%
General and administrative		13,818			12,270			1,548			13	%
Depreciation and amortization		301			210			91			43	%
Total operating costs and expenses		122,995			32,593			90,402			277	%
Operating income (loss)		(122,995	)		(32,593	)		90,402			277	%
West Africa Segment:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses:
Seismic and exploration		1,096			1,255			(159	)		(13	)%
Dry hole expense and impairment		12,904			—			12,904			—
General and administrative		8,529			6,646			1,883			28	%
Depreciation and amortization		139			59			80			136	%
Total operating costs and expenses		22,668			7,960			14,708			185	%
Operating income (loss)		(22,668	)		(7,960	)		14,708			185	%
Consolidated Operations:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses:
Seismic and exploration		14,555			6,327			8,228			130	%
Dry hole expense and impairment		108,321			15,041			93,280			620	%
General and administrative		22,347			18,916			3,431			18	%
Depreciation and amortization		440			269			171			64	%
Total operating costs and expenses		145,663			40,553			105,110			259	%
Operating income (loss)		(145,663	)		(40,553	)		105,110			259	%
Other income (expense):
Interest income		1,465			1,339			126			9	%
Interest expense		(15,802	)		—			15,802			—
Total other income (expense)		(14,337	)		1,339			15,676			1171	%
Net income (loss) before income tax		(160,000	)		(39,214	)		120,786			308	%
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(160,000	)	$	(39,214	)	$	120,786			308	%

United States Segment:

        Oil and gas revenue.    We have not yet commenced oil production. Therefore, we did not realize any oil and gas revenue during the three months ended September 30, 2013 and 2012, respectively.

30

        Operating costs and expenses.    Our operating costs and expenses consisted of the following during the three months ended September 30, 2013 and 2012:

        Seismic and exploration.    Seismic and exploration costs increased by $8.4 million during the three months ended September 30, 2013, as compared to the three months ended September 30, 2012. The increase was primarily due to seismic data acquisition costs incurred over certain of our prospects in the U.S. Gulf of Mexico during the three months ended September 30, 2013.

        Dry hole expense and impairment.    Dry hole expense and impairment increased by $80.4 million during the three months ended September 30, 2013, as compared to the three months ended September 30, 2012. The increase is due primarily to the dry hole expense and impairment charge on the Ardennes #1 exploratory well and unproved leasehold on the Ardennes prospect during the three months ended September 30, 2013, as reflected in the following table:

	Three Months Ended September 30,
	2013		2012		Increase (Decrease)
	($ in thousands)
Impairment of Unproved Leasehold:
Ardennes prospect	$	29,122	$	—	$	29,122
Amortization of leasehold with carrying value under $1 million		2,179		2,325		(146	)
Dry Hole Expense:
Shenandoah #2 Appraisal well		—		12,716		(12,716	)
Ardennes #1 exploratory well		64,116		—		64,116
	$	95,417	$	15,041	$	80,376

        General and administrative.    General and administrative costs increased by $1.5 million during the three months ended September 30, 2013, as compared to the three months ended September 30, 2012. The increase in general and administrative costs during this period was attributed to an increase of $3.9 million in staff related expenses which includes equity compensation, a $4.7 million increase in contractor and consulting fees, and an increase of $1.1 million in office support costs, offset by an increase of $8.2 million in recoveries from partners due to increased operating activities.

        Depreciation and amortization.    Depreciation and amortization did not materially change from the three months ended September 30, 2013, as compared to the three months ended September 30, 2012.

West Africa Segment:

        Oil and gas revenue.    We have not yet commenced oil production. Therefore, we did not realize any oil and gas revenue during the three months ended September 30, 2013 and 2012, respectively.

        Operating costs and expenses.    Our operating costs and expenses consisted of the following during the three months ended September 30, 2013 and 2012:

        Seismic and exploration.    Seismic and exploration costs did not materially change during the three months ended September 30, 2013, as compared to the three months ended September 30, 2012.

        Dry hole expense and impairment.    The increase of $12.9 million in dry hole expense during the three months ended September 30, 2013 is primarily related to drilling costs associated with the lowest interval beneath the pay zone that was drilled by the Mavinga #1 exploratory well and determined to have no further utility as reflected in the table below. Of the $116.0 million of total drilling costs

31

associated with the Mavinga #1 exploratory well, $103.5 million has been capitalized as of September 30, 2013 and will remain suspended pending further evaluation of the well.

	Three Months Ended September 30,
	2013		2012		Increase (Decrease)
	($ in thousands)
Dry Hole Expense:
Cameia #2 drill stem test	$	384		—	$	384
Mavinga #1 exploratory well		12,520		—		12,520
	$	12,904	$	—	$	12,904

        General and administrative.    General and administrative costs increased by $1.9 million for the three months ended September 30, 2013, as compared to the three months ended September 30, 2012. The increase is attributed primarily to increase of $0.6 million in office support costs, a $0.5 million increase in staff related costs, contractors, consulting fees and insurance and a $0.8 million increase in technical support costs, all attributed to ongoing drilling activities offshore Angola and Gabon during the three months ended September 30, 2013.

        Depreciation and amortization.    Depreciation and amortization did not materially change from the three months ended September 30, 2013, as compared to the three months ended September 30, 2012.

Consolidated:

        Other income (expense).    Other expense, net of income, increased by $15.7 million during the three months ended September 30, 2013, as compared to the three months ended September 30, 2012. The increase was due primarily to $15.8 million in interest expense associated with our 2.625% convertible senior notes due 2019 that were issued in December 2012, offset by an increase of $0.1 million in interest income during the three months ended September 30, 2013.

        Income tax expense/benefit.    No income tax benefit has been reflected since a full valuation allowance has been established against the deferred tax asset that would have been generated as a result of the operating results.

32

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012

	Nine Months Ended September 30,
	2013			2012			Increase (Decrease)			%
	($ in thousands)
United States Segment:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses:
Seismic and exploration		23,622			21,805			1,817			8	%
Dry hole expense and impairment		100,246			131,720			(31,474	)		(24	)%
General and administrative		43,014			34,999			8,015			23	%
Depreciation and amortization		935			647			288			45	%
Total operating costs and expenses		167,817			189,171			(21,354	)		(11	)%
Operating income (loss)		(167,817	)		(189,171	)		(21,354	)		(11	)%
West Africa Segment:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses:
Seismic and exploration		17,808			13,877			3,931			28	%
Dry hole expense and impairment		111,953			—			111,953			—
General and administrative		25,493			17,240			8,253			48	%
Depreciation and amortization		410			135			275			203	%
Total operating costs and expenses		155,664			31,252			124,412			398	%
Operating income (loss)		(155,664	)		(31,252	)		124,412			398	%
Consolidated Operations:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses:
Seismic and exploration		41,430			35,682			5,748			16	%
Dry hole expense and impairment		212,199			131,720			80,479			61	%
General and administrative		68,507			52,239			16,268			31	%
Depreciation and amortization		1,345			782			563			72	%
Total operating costs and expenses		323,481			220,423			103,058			47	%
Operating income (loss)		(323,481	)		(220,423	)		103,058			47	%
Other income (expense):
Gain on sale of assets		2,993			—			2,993			—
Interest income		4,610			3,955			655			17	%
Interest expense		(51,027	)		—			51,027			—
Total other income (expense)		(43,424	)		3,955			47,379			1198	%
Net income (loss) before income tax		(366,905	)		(216,468	)		150,437			69	%
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(366,905	)	$	(216,468	)	$	150,437			69	%

United States Segment:

        Oil and gas revenue.    We have not yet commenced oil production. Therefore, we did not realize any oil and gas revenue during the nine months ended September 30, 2013 and 2012, respectively.

33

        Operating costs and expenses.    Our operating costs and expenses consisted of the following during the nine months ended September 30, 2013 and 2012:

        Seismic and exploration.    Seismic and exploration costs increased by $1.8 million during the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012. The increase is due to a $2.5 million increase in seismic data costs, offset by a decrease of $0.7 million in other exploration expenses during the nine months ended September 30, 2013. During the nine months ended September 30, 2013, we incurred $19.5 million in seismic data acquisition and related costs as compared to $17.0 million incurred during the nine months ended September 30, 2012.

        Dry hole expense and impairment.    Dry hole expense and impairment decreased by $31.5 million during the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012. The decrease is due primarily to more exploratory well costs and unproved leasehold prospects in the U.S. Gulf of Mexico being charged to dry hole and impairment expense during the nine months ended September 30, 2012, as reflected in the following table:

	Nine Months Ended September 30,
	2013		2012		Increase (Decrease)
	($ in thousands)
Impairment of Unproved Leasehold:
Ligurian prospect	$	—	$	41,861	$	(41,861	)
Ardennes prospect		29,122		—		29,122
Other leasehold		—		8,298		(8,298	)
Amortization of leasehold with carrying value under $1 million		7,008		7,642		(634	)
Dry Hole Expense:
Ligurian #1 exploratory well		—		8,100		(8,100	)
Ligurian #2 exploratory well		—		48,994		(48,994	)
Heidelberg #3 appraisal well side Track		—		4,109		(4,109	)
Shenandoah #2 appraisal well		—		12,716		(12,716	)
Ardennes #1 exploratory well		64,116		—		64,116
	$	100,246	$	131,720	$	(31,474	)

        General and administrative.    General and administrative costs increased by $8.0 million during the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012. The increase in general and administrative costs is attributed to an increase of $7.6 million in staff related costs including equity compensation, a $10.2 million increase in contractor and consulting fees, a $2.2 million increase in legal fees, and a $4.6 million increase in office support costs, offset by an increase of $16.6 million in recoveries from partners and technical services charge-out due to the increase in operating activities.

        Depreciation and amortization.    Depreciation and amortization did not materially change from the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012.

West Africa Segment:

        Oil and gas revenue.    We have not yet commenced oil production. Therefore, we did not realize any oil and gas revenue during the nine months ended September 30, 2013 and 2012, respectively.

34

        Operating costs and expenses.    Our operating costs and expenses consisted of the following during the nine months ended September 30, 2013 and 2012:

        Seismic and exploration.    Seismic and exploration costs increased by $3.9 million during the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012. The increase was due primarily to a $2.1 million increase in seismic data costs for Block 21 offshore Angola and a $1.8 million increase for standby costs of certain contractors and shorebase equipment and personnel offshore Angola charged to other exploration expenses.

        Dry hole expense and impairment.    Dry hole expense and impairment increased by $112.0 million during the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012. The increase is due to dry hole expense during the nine months ended September 30, 2013 as reflected in the following table:

	Nine Months Ended September 30,
	2013		2012		Increase (Decrease)
	($ in thousands)
Dry Hole Expense:
Cameia #2 drill stem test	$	82,367	$	—	$	82,367
Diaman #1 exploratory well		17,066		—		17,066
Mavinga #1 exploratory well		12,520		—		12,520
	$	111,953	$	—	$	111,953

        General and administrative.    General and administrative costs increased by $8.3 million for the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012. The increase is attributed to a $1.8 million increase in staff related costs, a $1.9 million increase in contractor and consulting fees and a $4.6 million increase in other office support costs in Luanda, Angola due to increased operating activities.

        Depreciation and amortization.    Depreciation and amortization did not materially change from the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012.

Consolidated:

        Other income (expense).    Other expense, net of income, increased by $47.4 million during the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012. The increase was due primarily to $51.0 million in interest expense associated with our 2.625% convertible senior notes due 2019 that were issued in December 2012, offset by an increase of $0.6 million in interest income and a $3.0 million gain on sale of assets during the nine months ended September 30, 2013.

        Income tax expense/benefit.    No income tax benefit has been reflected since a full valuation allowance has been established against the deferred tax asset that would have been generated as a result of the operating results.

Liquidity and Capital Resources

        We are a development stage enterprise and will continue to be so until commencement of substantial production from our oil properties or we have proved reserves. With respect to our non-operated U.S. Gulf of Mexico discoveries, the Heidelberg development has been formally sanctioned, and Anadarko, as operator, has publicly indicated that it expects first production from the Heidelberg field in 2016. With respect to our Cameia pre-salt discovery, we are currently conducting

35

pre-development activities and planning for a phased development approach. We currently estimate first production and cash flow from Cameia in 2017, assuming continued alignment with our partners and Sonangol, among other things. Our confidence in conducting pre-development activities and progressing our Cameia discovery toward development is based on the fact that the drilling results from our Cameia #1 exploratory well far exceeded our pre-drill estimates on feet of pay, reservoir rock properties, flow characteristics and fluid properties. Furthermore, our Cameia #2 appraisal well demonstrated lateral continuity within the reservoir originally encountered by our Cameia #1 exploratory well and provided additional assurance of sufficient areal extent to support our plans to proceed with the evaluation of development options.

        Until substantial production is achieved, our primary sources of liquidity are expected to be cash on hand, amounts paid pursuant to the terms of our Total alliance and funds from future equity and debt financings, asset sales and farm-out arrangements.

        We expect to incur substantial expenses and generate significant operating losses as we continue to:

•

conduct our current exploration and appraisal drilling program in the U.S. Gulf of Mexico and offshore Angola and Gabon;

•

develop our discoveries which we determine to be commercially viable;

•

purchase and analyze seismic data in order to assess current prospects and identify future prospects;

•

opportunistically invest in additional oil leases and concessional licenses; and

•

incur expenses related to operating as a public company and compliance with regulatory requirements.

        Our future financial condition and liquidity will be impacted by, among other factors, (i) the success of our exploration and appraisal drilling program, (ii) the number of commercially viable hydrocarbon discoveries made and the quantities of hydrocarbons discovered, (iii) the speed with which we can bring such discoveries to production, which for our Cameia discovery will depend upon continued alignment with our partners and Sonangol, among other things, (iv) whether and to what extent we invest in additional oil leases and concessional licenses, and (v) the actual cost of exploration, appraisal and development of our prospects.

        As of September 30, 2013, we had approximately $2.0 billion in liquidity, which includes cash and cash equivalents, short-term restricted cash, short-term investments, long-term restricted cash and long-term investments. This amount does not include the Total carry or any additional success payments Total is obligated to pay us pursuant to the terms of our U.S. Gulf of Mexico alliance. We expect to expend approximately $850 to $950 million for our ongoing operations and general corporate purposes in 2013. Our total expenditures, excluding changes in working capital but including the payment of accrued contractual obligations for Block 20, offshore Angola, were approximately $288.6 million and $671.2 million for the three and nine months ended September 30, 2013, respectively. We expect that our existing cash on hand will be sufficient to fund our planned exploration and appraisal drilling program and development activities at least through the end of 2014. However, we may require additional funds earlier than we currently expect in order to execute our strategy as planned. We may seek additional funding through asset sales, farm-out arrangements and future equity and debt financings. Additional funding may not be available to us on acceptable terms or at all. In addition, the terms of any financing may adversely affect the holdings or the rights of our existing stockholders. For example, if we raise additional funds by issuing additional equity securities, further dilution to our existing stockholders will result. If we are unable to obtain funding on a timely basis or on acceptable terms, we may be required to significantly curtail one or more of our exploration and appraisal drilling

36

programs. We also could be required to seek funds through arrangements with collaborators or others that may require us to relinquish rights to some of our prospects which we would otherwise develop on our own, or with a majority working interest.

Cash Flows

	Nine Months Ended September 30,
	2013			2012
	($ in thousands)
Net cash provided by (used in):
Operating Activities	$	(239,983	)	$	(141,393	)
Investing Activities		(964,328	)		(513,797	)
Financing Activities		(992	)		489,414

        Operating activities.    Net cash used in operating activities for the nine months ended September 30, 2013 was $240.0 million, compared with net cash used in operating activities of $141.4 million for nine months ended September 30, 2012. The increase was attributed primarily to increased drilling activities in the U.S. Gulf of Mexico and offshore Angola and Gabon during the nine months ended September 30, 2013.

        Investing activities.    Net cash used in investing activities for the nine months ended September 30, 2013 was $964.3 million, compared with net cash used in investing activities of $513.8 million for the nine months ended September 30, 2012. The increase in net cash used in investing activities for the nine months ended September 30, 2013 was primarily attributed to the investment of the net proceeds of $1.35 billion from the issuance of 2.625% convertible senior notes due 2019 that were issued in December 2012.

        Financing activities.    Net cash used in financing activities for the nine months ended September 30, 2013 was $1.0 million, compared with $489.4 million provided by financing activities for the nine months ended September 30, 2012. The $1.0 million used in financing activities for the nine months ended September 30, 2013 relates to payments of debt issue costs associated with the 2.625% convertible senior notes due 2019. The $489.4 million provided by financing activities for the nine months ended September 30, 2012 represents the net proceeds from our public offering of our common stock that closed on February 29, 2012.

Critical Accounting Policies

        Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our 2012 Annual Report on Form 10-K for the year ended December 31, 2012. Also refer to the Notes to the Condensed Consolidated Financial Statements included in Part 1, Item 1 of this Report.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

        There have been no material changes in market risk from the information provided under Part II, Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" in our 2012 Annual Report on Form 10-K for the year ended December 31, 2012.

Item 4.    Controls and Procedures

        We performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Securities Exchange Act of 1934,

37

as amended (the "Exchange Act"), Rules 13a-15 and 15d-15 as of the end of the period covered by this Report. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed by us in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

        There were no changes in our internal control over financial reporting during the quarter ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.    Legal Proceedings

        We are not currently party to any legal proceedings. However, from time to time we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated financial position, results of operations, or liquidity.

Item 1A.    Risk Factors

        There have been no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

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

        None.

38

Item 6.    Exhibits

Exhibit Number			Description of Document
	10.1	*+	Offshore Drilling Contract between Cobalt International Energy, L.P. and Rowan Reliance Limited dated August 5, 2013
	31.1	*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
	31.2	*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
	32.1	*	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	*	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	101.INS	**	XBRL Instance Document
	101.SCH	**	XBRL Schema Document
	101.CAL	**	XBRL Calculation Linkbase Document
	101.DEF	**	XBRL Definition Linkbase Document
	101.LAB	**	XBRL Labels Linkbase Document
	101.PRE	**	XBRL Presentation Linkbase Document

*

Filed herewith.

**

Furnished herewith.

+

Confidential treatment requested as to certain portions, which portions have been provided separately to the Securities and Exchange Commission.

39

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.

Cobalt International Energy, Inc.
By:	/s/ JOSEPH H. BRYANT
	Name:	Joseph H. Bryant
	Title:	Chairman of the Board of Directors and Chief Executive Officer
By:	/s/ JOHN P. WILKIRSON
	Name:	John P. Wilkirson
	Title:	Executive Vice President and Chief Financial Officer

Dated: October 29, 2013

40

EXHIBIT INDEX

Exhibit Number			Description of Document
	10.1	*+	Offshore Drilling Contract between Cobalt International Energy, L.P. and Rowan Reliance Limited dated August 5, 2013
	31.1	*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
	31.2	*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
	32.1	*	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	*	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	101.INS	**	XBRL Instance Document
	101.SCH	**	XBRL Schema Document
	101.CAL	**	XBRL Calculation Linkbase Document
	101.DEF	**	XBRL Definition Linkbase Document
	101.LAB	**	XBRL Labels Linkbase Document
	101.PRE	**	XBRL Presentation Linkbase Document

*

Filed herewith.

**

Furnished herewith.

+

Confidential treatment requested as to certain portions, which portions have been provided separately to the Securities and Exchange Commission.

EX-10.1

Exhibit 10.1

10-Q Filing

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Execution Version

OFFSHORE DRILLING CONTRACT

BETWEEN

COBALT INTERNATIONAL ENERGY, L.P.

(“OPERATOR”)

AND

ROWAN RELIANCE LIMITED

(“CONTRACTOR”)

FOR

ROWAN RELIANCE

NEW-BUILD DRILLSHIP

(THE “RIG”)

DATED

August 5, 2013

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

INDEX

ARTICLE I	DEFINITIONS	2
ARTICLE II	THE RIG	10
ARTICLE III	COMPENSATION	19
ARTICLE IV	INVOICES	23
ARTICLE V	EQUIPMENT, SERVICES, AND PERSONNEL	25
ARTICLE VI	PERFORMANCE OF THE WORK	31
ARTICLE VII	REPORTS TO BE FURNISHED BY CONTRACTOR	37
ARTICLE VIII	LIABILITY AND INDEMNIFICATION	37
ARTICLE IX	INSURANCE	51
ARTICLE X	INDEPENDENT CONTRACTOR	53
ARTICLE XI	GOVERNING LAW AND DISPUTE RESOLUTION	53
ARTICLE XII	FORCE MAJEURE	55
ARTICLE XIII	TERMINATION	55
ARTICLE XIV	UNSATISFACTORY PERFORMANCE	59
ARTICLE XV	NOTICES	60
ARTICLE XVI	SUCCESSOR AND ASSIGNS / ASSIGNMENT	61
ARTICLE XVII	CONFIDENTIALITY	62
ARTICLE XVIII	GENERAL	63

i

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDICES
APPENDIX A	RIG ACCEPTANCE AND PERFORMANCE CRITERIA
APPENDIX B	CONTRACTOR’S PERSONNEL
APPENDIX C	CONTRACTOR’S RIG AND EQUIPMENT
APPENDIX D	EQUIPMENT, SERVICES AND FACILITIES FURNISHED
APPENDIX E	INSURANCE
APPENDIX F	INTENTIONALLY OMITTED
APPENDIX G	DEED OF NOVATION
APPENDIX H	DEED OF GUARANTEE
APPENDIX I	REMUNERATION

ii

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

OFFSHORE DRILLING CONTRACT

THIS OFFSHORE DRILLING CONTRACT (this “Drilling Contract”) is made and entered into as of this 5th day of August, 2013 (the “Effective Date”), by and between COBALT INTERNATIONAL ENERGY, L.P., a Delaware limited partnership (“Operator”), and ROWAN RELIANCE LIMITED, a company formed under the laws of Gibraltar (“Contractor”).  Operator and Contractor may hereinafter be referred to individually as a “Party” or collectively as the “Parties”.

RECITALS

WHEREAS, Operator operates oil and gas leases in federal waters on the Outer Continental Shelf in the U.S. Gulf of Mexico (the “Area of Operations”) (and other areas as may be mutually agreed upon by the Parties by amendment hereto), for which Operator desires to contract an ultra-deepwater drillship for the purpose of drilling oil and gas exploration, appraisal and/or development wells;

WHEREAS, Contractor’s Affiliate, Rowan Deepwater Drilling (Gibraltar) Limited, a company formed under the laws of Gibraltar (“Rowan Gibraltar”), has under construction at Hyundai Heavy Industries, South Korea, a new-build, dynamically-positioned (“DP”) ultra-deepwater drillship of the GustoMSC P10000 design, to be known as ROWAN RELIANCE (as further described in Appendices hereto) and to be registered in the Republic of the Marshall Islands (the “Flag State”), with drilling and other equipment and personnel to drill wells for Operator as provided herein;

WHEREAS, the new-build, DP drillship ROWAN RELIANCE and associated equipment appurtenant thereto as set forth in Appendix C (collectively, the “Rig”), shall be capable of operating in the Area of Operations in conformity with all applicable laws and any requirements of Governmental Authorities, in water depths up to 12,000 feet and of drilling to a measured depth of 40,000 feet and shall be certified “DPS-3” “A1E” by the American Bureau of Shipping (“ABS”);

WHEREAS, no later than seven (7) days after the Effective Date, Operator, Contractor and Contractor’s novatee (as set forth in the Deed of Novation) (“Novatee”) shall execute and deliver an agreement substantially in the form of Appendix G, to be effective as of the date of the Rig’s arrival in the Area of Operations (the “Deed of Novation”), assigning and transferring specified Contractor’s rights, obligations and liabilities under this Drilling Contract in respect of the Work to be performed in the Area of Operations to Novatee;

WHEREAS, Operator has agreed to utilize the Rig for a term as specified herein;

WHEREAS, Contractor is agreeable to conduct drilling for Operator in accordance with the terms and conditions of this Drilling Contract; and

1

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

WHEREAS, to induce Operator to enter into this Drilling Contract, contemporaneously with the execution of this Drilling Contract, Contractor shall cause its parent entity, Rowan Companies plc, a company incorporated under the laws of England, to execute and deliver to Operator a deed of guarantee, in the form of Appendix H and effective as of the Effective Date (the “Deed of Guarantee”), guaranteeing all present and future obligations and liabilities of Contractor due, owing or incurred under this Drilling Contract or in connection with the transactions contemplated hereby.

NOW, THEREFORE, Operator and Contractor, for and in consideration of the mutual obligations, undertakings, premises and covenants herein contained, do hereby agree as follows:

ARTICLE I
DEFINITIONS

1.1Defined Terms

Capitalized terms used herein shall have the meanings set forth in this Section 1.1, unless the context requires otherwise.

(a)“ABS” has the meaning given in the recitals to this Drilling Contract.

(b)“Act” has the meaning given in Section 18.12(a).

(c)“Affiliate” means any Person that, directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with, another Person.  The term “control” and its derivatives with respect to any Person means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

(d)“API” means the American Petroleum Institute.

(e)“Area of Operations” has the meaning given in the recitals to this Drilling Contract.

(f)“BOP” or “BOPs” means any or both of the Rig’s blowout preventers manufactured by Cameron Drilling Systems.

(g)“BOP Unavailability” has the meaning given in Appendix I, Section B(3)(A).

(h)“Builder” means Hyundai Heavy Industries, South Korea.

(i)“Claim” or “Claims” has the meaning given in Section 8.1(a).

2

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(j)“Compliant” means, with respect to a BOP, that a Third Party engaged by Operator has issued a written verification that such BOP is fit for service in all respects.

(k)“Consequential Damages” has the meaning given in Section 8.13.

(l)“Contractor” has the meaning given in the preamble to this Drilling Contract.

(m)“Contractor Group” means (i) Contractor and its Affiliates, and its and their respective contractors and subcontractors, (ii) [***], and (iii) the directors, officers, employees, representatives, invitees, and agents of any entities described in parts (i) and (ii) of this definition (excluding any member of Operator Group).

(n)“Contractor’s Items” means with respect to the provision of the Work, the Rig, equipment, spare parts, materials, expendables and other supplies and facilities related thereto owned, leased or hired by Contractor or to be provided by Contractor, as specified in Appendix C and Appendix D (except those items which are Operator’s Items).

(o)“Contractor’s Personnel” has the meaning given in Section 5.2(a).

(p)“contractors” and “subcontractors” of a Party mean, respectively, such Party’s own contractors or subcontractors of any tier; provided that the terms “contractor” or “subcontractor” shall not, insofar only as used in relation to Operator, include Contractor or any of Contractor’s subcontractors or contractors.

(q)“Critical Item” means an item from Contractor’s Items that, without repair or remediation, prevents the safe performance of the Work.

(r)“Deed of Guarantee” has the meaning given in the recitals to this Drilling Contract.

(s)“Deed of Novation” has the meaning given in the recitals to this Drilling Contract.

(t)“Delay Damages” has the meaning given in Section 2.2(e)(i).

(u)“Demobilization Fee” has the meaning given in Appendix I, Section A(1)(B).

(v)“Demobilization Point” means a location within the Area of Operations that is one (1) nautical mile from the location of the last Designated Well.

(w)“Designated Well” means any well designated by Operator to be drilled, tested, completed or, as necessary, plugged and abandoned by Contractor in accordance with the terms and conditions of this Drilling Contract, including any sidetrack or re-drill or re-completion thereof.

3

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(x)“drill” or “drilling” or “drilled” means drilling, running casing, geological or mechanical sidetracking, completing, working-over, intervention, deepening, testing, pre-drilling surface holes, a relief well, batch setting casing strings, installation of sub-sea equipment, or plugging, abandonment and related activities, as appropriate, unless specified otherwise.

(y)“DP” has the meaning given in the recitals to this Drilling Contract.

(z)“Drilling Contract” has the meaning given in the preamble to this Drilling Contract.

(aa)“dual activity” has the meaning given in Section 8.15(b).

(bb)“Early Termination Fee” has the meaning given in Section 13.3(a).

(cc)“Effective Date” has the meaning given in the preamble to this Drilling Contract.

(dd)“Earliest Acceptance Date” has the meaning given in Section 2.2(b).

(ee)“Extension Term” has the meaning given in Section 2.6.

(ff)“First Extension Term” has the meaning given in Section 2.6.

(gg)“Flag State” has the meaning given in the recitals to this Drilling Contract.

(hh)“Force Majeure” means any event that: (1) renders a Party unable to comply with its obligations under this Drilling Contract, and/or renders Operator unable to drill a Designated Well; (2) is beyond the reasonable control of the affected Party; (3) does not result from the fault, negligence or intentional act of the affected Party or such Party’s failure to comply with applicable law or Good Industry Practices; and (4) could not have been avoided by the affected Party through the exercise of proper diligence including the expenditure of reasonable monies and/or taking reasonable precautionary measures, including (to the extent that such events satisfy the foregoing criteria), the following:

(i)acts of God or the public enemy;

(ii)war, terrorism, hostilities, rebellion, sabotage, riot, civil commotion, or insurrection;

(iii)earthquakes, floods, hurricanes, tornados, microbursts or other natural catastrophes and/or other natural physical disasters;

(iv)fires or explosions (other than fires or explosions on the Rig, except to the extent caused by an event that would otherwise constitute a Force Majeure);

4

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(v)actions or inaction of Governmental Authorities that render(s) illegal performance required in connection with the Work;

(vi)strikes at a national or regional level or industrial disputes at a national or regional level, or strikes or industrial disputes by labor not employed by the affected Party, including any subcontractor or suppliers and which affect a substantial or essential portion of the Work;

(vii)actions or inactions of Governmental Authorities that cause the inability to obtain, maintain, renew, or Work under any permit, license, consent, authorization, or approval, and such inability is also experienced by other parties in the Area of Operations similarly situated to the affected Party; and

(viii)confiscation or expropriation on orders of any Governmental Authorities;

provided, however, that Force Majeure shall not include:

(A)lack of finances;

(B)strikes or labor disturbances of any employer performing any of the Work, unless, as a result of any such strike or labor disturbance, there is no other Person capable and reasonably available to Contractor to perform such Work;

(C)shortages or price fluctuations with respect to Contractor’s Items;

(D)late delivery of Contractor’s Items, except to the extent caused by an event that would otherwise constitute a Force Majeure;

(E)economic hardship;

(F)shortages of manpower, except to the extent caused by an event that would otherwise constitute a Force Majeure;

(G)delay or failure to perform of a subcontractor, except to the extent caused by an event that would otherwise constitute a Force Majeure;

(H)machinery or equipment breakdown, or damage to Contractor’s Items, except to the extent caused by an event that would otherwise constitute a Force Majeure; or

(I)unavailability at any Work site of necessary water and other utilities, except to the extent caused by an event that would otherwise constitute a Force Majeure.

5

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(ii)“Force Majeure Rate” has the meaning given in Appendix I, Section A(2)(E).

(jj)“Good Industry Practices” means, in respect of the Work:  (a) the exercise of that degree of skill, diligence, prudence and foresight that reasonably would be expected from a reputable and prudent deepwater offshore drilling contractor in performing the Work or providing services similar to the Work and under conditions comparable to those applicable during performance of the Work in accordance with good deepwater oilfield practice; and (b) acting in accordance and compliance with all applicable laws and regulations.

(kk)“Governmental Authority” means any government and any political, judicial, administrative, executive or legislative subdivision thereof, including (a) any national, federal, state, provincial, county, municipal, local or other governmental body, authority or agency, and (b) any governmental, regulatory, administrative, executive and judicial departments, courts, commissions, boards, bureaus, ministries, agencies or other instrumentalities exercising any administrative, regulatory, executive, judicial, legislative, police, arbitral or taxing authority or power having authority over any Party, any subcontractor or any officer or other official representative of any of the foregoing Persons.

(ll)“Gross Negligence” means any act or failure to act (whether sole, joint or concurrent) by any Person which was in reckless disregard of or wanton indifference to, harmful consequences such act or failure would have on the safety or property (excluding intangible property) of another Person or on the environment.

(mm)“Group” means Operator Group or Contractor Group, as applicable.

(nn)“HSSE Bridging Agreement” has the meaning given in Section 6.5(b).

(oo)“Key Personnel” means those personnel designated with a double-asterisk in Appendix B.

(pp)“Latest Delivery Date” has the meaning given in Section 2.2(b).

(qq)“LCIA” has the meaning given in Section 11.2(c).

(rr)“Load-Out Period” has the meaning given in Section 2.2(c).

(ss)“Management System” means the Rowan Management System.

(tt)“Mobilization Fee” has the meaning given in Appendix I, Section A(1)(A).

(uu)“NOI” has the meaning given in Section 8.8(d).

6

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(vv)“Non-critical Item” means an item from Contractor’s Items relating to the performance of the Work other than Critical Items.

(ww)“Novatee” has the meaning given in the recitals to this Drilling Contract.

(xx)“Offshore Installation Manager” has the meaning given under 46 CFR 10.107.

(yy)“Operating Rate” has the meaning given in Appendix I, Section A(2)(A).

(zz)“Operator” has the meaning given in the preamble to this Drilling Contract.

(aaa)“Operator Group” means (i) Operator and its Affiliates, and its and their respective contractors and subcontractors, (ii) Operator’s co-lessees, co-license holders, joint venturers and any of their respective Affiliates, and (iii) the directors, officers, employees, representatives, invitees, and agents of any entities described in parts (i) and (ii) of this definition (excluding any member of Contractor Group).

(bbb)“Operator’s Items” means the equipment, material and services owned, leased or hired by Operator or to be provided by Operator, as specified in Appendix D (except those items which are Contractor’s Items).

(ccc)“Party” and “Parties” has the meaning given in the preamble to this Drilling Contract.

(ddd)“Person” means any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Authority or any other entity.

(eee)“Primary Term” has the meaning given in Section 2.5(c).

(fff)“regardless of fault” has the meaning given in Section 8.1(b).

(ggg)“Repair Rate” has the meaning given in Appendix I, Section A(2)(C).

(hhh)“Rig” has the meaning given in the recitals to this Drilling Contract.

(iii)“Rig Acceptance Criteria” means the criteria set forth on Appendix A.

(jjj)“Rig Acceptance Period” has the meaning given in Section 2.2(d).

(kkk)“Rig Acceptance Testing” means those procedures, maneuvers, tests and other actions Contractor shall perform at Operator’s direction to evidence the Rig’s satisfaction of the Rig Acceptance Criteria.

(lll)“Rig Modification Cost” has the meaning given in Appendix I, Section B(4).

7

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(mmm)“Rig Ready Condition” means that the Rig is fully equipped and outfitted, in all material respects pursuant to the requirements of Appendix C and the requirements of Contractor specified in Appendix D, and satisfies and is in full conformity with the requirements of Sections 2.4(a)(iii) and 2.4(a)(vii) and Sections 2.5(b)(vi) and 2.5(b)(vii) (provided that Operator has accommodated Contractor’s first crew change after the Rig’s arrival at the Operator’s designated location in the Area of Operations, has provided transportation services for Contractor’s Items as specified in Appendix D, Part B(12) and has fueled the Rig in accordance with Appendix D, Part D(3)), and Contractor has satisfied and is in full conformity with the requirements of Sections 2.5(b)(iv) and 2.5(b)(v).

(nnn)“Rig Release” means that time when Operator provides notice to Contractor that all of the Work on the last Designated Well is ended and Operator’s Items have been offloaded from the Rig, and the Rig is underway at least one (1) nautical mile from the location of the last Designated Well.

(ooo)“Rowan Gibraltar” has the meaning given in the recitals to this Drilling Contract.

(ppp)“Second Extension Term” has the meaning given in Section 2.6.

(qqq)“Senior Supervisory Personnel” means, with respect to Contractor, any director or officer of Contractor or one of its Affiliates, and any individual who functions for Contractor or one of its Affiliates at a management level equivalent or superior to any individual functioning as Contractor’s Offshore Installation Manager (as required by applicable law), but excluding all individuals functioning at a level below such Offshore Installation Manager.

(rrr)“Specifications” means the specifications set forth on Appendix C.

(sss)“Standby Rate” has the meaning given in Appendix I, Section A(2)(B).

(ttt)“subsea equipment” means Contractor Group’s subsea equipment listed in Appendix C (including the riser with relevant components, slip joint, gimbal, spider, riser gas handling equipment, upper flex joint, choke and kill lines, flexible hoses and guidelines, lower marine riser package, shackles, blow out preventers and related components).

(uuu)“Term Commencement Date” has the meaning given in Section 2.5(b).

(vvv)“Third Party” means a Person other than any member of Operator Group and Contractor Group.

(www)“Transocean’s dual-activity patents” has the meaning given in Section 8.15(b).

(xxx)“Weather Rate” has the meaning given in Appendix I, Section A(2)(F).

8

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(yyy)“well” has the meaning given in Section 2.5(c)(ii).

(zzz)“Well-Control Bridging Agreement” has the meaning given in Section 6.5(c).

(aaaa)“Well Control Costs” has the meaning given in Section 8.6.

(bbbb)“Willful Misconduct” means any act or failure to act (whether sole, joint or concurrent) by any Person which was intended to harm or cause damage to the safety or property (excluding intangible property) of any other Person or on the environment, but shall not include any act or failure to act made in the exercise of good faith of any function, authority or discretion vested in or exercisable by such Person.

(cccc)“Work” means the drilling and all other services, material, equipment, supplies, and personnel required to be performed, provided or furnished by Contractor pursuant to this Drilling Contract.

(dddd)“Zero Rate” has the meaning given in Appendix I, Section A(2)(D).

1.2References and Rules of Construction

(a)All references in this Drilling Contract to Appendices, Articles, Sections, subsections and other subdivisions refer to the corresponding Appendices, Articles, Sections, subsections and other subdivisions of or to this Drilling Contract unless expressly provided otherwise.  The Appendices referred to herein are attached hereto and by this reference incorporated herein for all purposes.

(b)Headings and titles appearing at the beginning of any Articles, Sections, subsections and other subdivisions of this Drilling Contract are for convenience only, do not constitute any part of this Drilling Contract, and shall be disregarded in construing the language hereof.

(c)The words “this Drilling Contract,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Drilling Contract as a whole and not to any particular Article, Section, subsection or other subdivision unless expressly so limited.

(d)Wherever the words “include,” “includes” or “including” are used in this Drilling Contract, they shall be deemed to be followed by the words “without limiting the foregoing in any respect.”

(e)All references to “$” or “dollars” shall be deemed references to United States dollars.

(f)Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined

9

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires.

ARTICLE II
THE RIG

2.1Rig Construction

(a)Contractor warrants that the Rig shall be constructed and delivered by Builder in accordance with the Specifications.

(b)If, after the Effective Date, ABS or a Governmental Authority makes any revisions or additions to its requirements applicable to the Rig, compliance with which is required to preserve the Rig in the class certification of “DPS-3” “Maltese Cross A1E” or for the continued efficient use of the Rig under this Drilling Contract, Contractor undertakes to notify Operator of (i) the nature and extent of such change, (ii) the latest date (taking into account, with respect to Governmental Authority or classification society requirements, any extension available to Contractor) by which such compliance with such change will be necessary, and (iii) the estimated time which will be required for carrying out such change.

(c)Contractor shall notify Operator of any request by Builder, Rowan Gibraltar or Contractor to make any material change in Specifications for the Rig.  Contractor shall prepare a request which describes (i) the nature and extent of such change, (ii) the estimated time which will be required for carrying out such change, and (iii) the impact such change is reasonably likely to have on the Earliest Acceptance Date and/or the Latest Delivery Date.  Such changes shall be carried out only with the consent of Operator (such consent not to be unreasonably withheld, conditioned or delayed) and shall not reduce or modify any of Contractor’s obligations hereunder with respect to delivery or performance of the Rig unless otherwise agreed upon by Operator.

(d)During the construction period (including during all sea trials and DP trials), Operator’s representatives shall be entitled to access the Rig, at Operator’s risk, cost and expense, except to the extent prohibited by the contract governing the construction and delivery of the Rig by Builder, including attendance at all tests and trials of the Rig, her equipment, appurtenances, and components.  Contractor shall promptly notify Operator of all such tests and trials and cause Builder and Rowan Gibraltar to provide Operator’s representatives with access to attend.  Operator’s representatives shall not interfere with such tests or trials.  All communications between Operator and Builder shall be through Contractor or Rowan Gibraltar.  Contractor shall also provide Operator’s representatives with access to the worksites and representatives of the BOP manufacturer at Operator’s risk, cost and expense.

10

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(e)Contractor shall provide Operator with periodic progress reports advising of progress on the planning and construction of the Rig and the BOPs.  The first such report shall be provided within three (3) months after the Effective Date.  Thereafter, Contractor shall provide Operator with progress reports at least once every month until Contractor accepts delivery, respectively, of the Rig from Builder and the owner-furnished BOP from the BOP manufacturer.  Each progress report shall be in writing in a form from time to time proposed by Contractor and approved by Operator and shall include statements of any events or circumstances which may cause the Earliest Acceptance Date and/or the Latest Delivery Date to be delayed and the estimated period of such delay.  Contractor shall also deliver to Operator from time to time copies of construction progress certificates (i) of Builder (which certificates shall include percentages of completion of the Rig and other major components) as and when issued by Builder and (ii) of the BOP manufacturer (which certificates shall include percentages of completion of the Builder-furnished BOP and the owner-furnished BOP) as and when issued by the BOP manufacturer.

(f)Not later than the Earliest Acceptance Date, Contractor will provide to Operator, at no cost to Operator, a Builder’s model (with a scale of no less than 1:200) of the Rig.

(g)As and when requested in writing by Operator, Contractor shall meet with Operator at Contractor’s facilities or at Builder’s shipyard (or such other place mutually acceptable to the Parties) for the purpose of evaluating the progress of the Rig’s construction.  Contractor shall cause Builder and Rowan Gibraltar to permit Operator and a reasonable number of Operator’s representatives to be present at Builder’s shipyard for such purposes at Operator’s risk, cost and expense; provided that any such meetings at Builder’s shipyard shall occur during ordinary working hours and shall not obstruct the normal or orderly construction of the Rig.

(h)Notwithstanding anything to the contrary in this Drilling Contract (but subject always to Section 17.3), the rig construction contract for the Rig, or the procurement contracts for the BOPs, neither the exercise nor the non-exercise (nor anything done or not done in the exercise or non-exercise) by Operator of any respective right to monitor the Rig or her construction, or the BOPs or their construction, or any right of inspection or attendance or otherwise (including the receipt and review of any plans, drawings or instruction manuals relating to the Rig or any parts thereof, including the BOPs) in relation thereto shall (i) create or impose any obligation or liability whatsoever on any member of Operator Group with respect to the Rig or her construction, or the BOPs or their construction, (ii) in any way affect or alter Operator’s obligations or liabilities under this Drilling Contract, or (iii) in any way affect Contractor’s responsibility and liability under this Drilling Contract; provided, however, that Operator agrees to keep any such plans, drawings and manuals confidential in accordance with Section 17.3.

11

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

2.2Arrival of Rig on Location

(a)Rowan Gibraltar intends to take delivery of the Rig ex-Builder’s yard in South Korea on or about October 31, 2014.  Contractor shall then cause the mobilization of the Rig to the Area of Operations.  No later than seven (7) days after the Effective Date, Contractor, Novatee and Operator shall execute and deliver the Deed of Novation, to be effective as of the date of the Rig’s arrival in the Area of Operations, assigning and transferring specified Contractor’s rights, obligations and liabilities under this Drilling Contract in respect of the Work to be performed in the Area of Operations to Novatee.  Contractor shall obtain and maintain, and cause Novatee to obtain and maintain, any permits, approvals and authorizations from Governmental Authorities necessary or desirable to import the Rig into, and export the Rig out of, the Area of Operations and to move and operate the Rig within the Area of Operations which are to be obtained by Contractor in its name and by Novatee in its name under applicable laws, rules and regulations.

(b)Contractor shall provide the Rig to Operator, at the Operator’s designated location in the Area of Operations, in Rig Ready Condition, and ready to commence the Rig load-out on or after December 1, 2014 (the “Earliest Acceptance Date”), but on or before August 1, 2015 (the “Latest Delivery Date”), unless otherwise mutually agreed by the Parties in writing.  The Latest Delivery Date shall be extended for documented periods of Force Majeure, delays caused solely by Operator Group, and changes to the Rig requested by Operator.

(c)After the Rig has arrived in the Area of Operations and is presented in Rig Ready Condition, Contractor shall conduct the Rig load-out (the “Load-Out Period”) at a suitable location within the Area of Operations determined by Operator in its sole discretion.  The Load-Out Period shall be no longer than [***] days, unless extended by Operator in its sole discretion.  Contractor shall be paid the Standby Rate for each day during the Load-Out Period; provided that Contractor does not cause any interruption to or suspension of the Rig load-out, in which case the Zero Rate shall apply during any such interruption or suspension.

(d)After the Load-Out Period is complete, Operator shall have [***] days (the “Rig Acceptance Period”) to perform the Rig Acceptance Testing.  The Rig Acceptance Testing will be conducted at a suitable location within the Area of Operations determined by Operator in its sole discretion.  Contractor shall provide Operator’s representatives with all access rights to the Rig and her equipment necessary for Operator to conduct the Rig Acceptance Testing.  Contractor shall be paid the Zero Rate for each day of the Rig Acceptance Period.  If Operator fails to complete the Rig Acceptance Testing during the Rig Acceptance Period, Contractor shall be paid the Standby Rate for such additional time Operator requires to complete the Rig Acceptance Testing; provided that if (i) Operator has not received sufficient access to the Rig or her equipment to conduct the Rig Acceptance Testing, or (ii) Contractor fails to assist Operator as necessary to

12

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

complete the Rig Acceptance Testing, or otherwise causes any undue delay or hindrance to the Rig Acceptance Testing, then Contractor shall receive the Zero Rate during the period that the Rig Acceptance Testing has been delayed due to any such delay or hindrance.  Operator shall notify Contractor as soon as reasonably practical of each Critical Item and Non-critical Item that requires repair or remediation by Contractor.  All repairs and remediation for Critical Items shall be at Contractor’s cost.  Prior to the Term Commencement Date, Contractor shall repair or remediate all Critical Items to the Specifications and prepare a plan to repair or remediate all Non-critical Items to the Specifications.  For the avoidance of doubt, prior to the Term Commencement Date, Contractor shall be paid the Standby Rate only during (x) the Load-Out Period, in accordance with Section 2.2(c), and (y) any such time in excess of the Rig Acceptance Period if Operator fails to complete the Rig Acceptance Testing during the Rig Acceptance Period for reasons other than those stated in Section 2.2(d)(i) and (ii) above.  Subject to the foregoing and without prejudice to payment of the Mobilization Fee pursuant to Section 2.7(a), Contractor shall be paid the Zero Rate at all other times prior to the Term Commencement Date, including the time required to repair or remediate Critical Items to the Specifications and prepare a plan to repair or remediate Non-critical Items to the Specifications.  To the extent practicable, Operator agrees to conduct certain aspects of the Rig Acceptance Testing during the trials and testing to be carried out by Builder and Rowan Gibraltar in conjunction with Rowan Gibraltar’s acceptance of the Rig from Builder.

(e)Delay in Arrival

(i)Should the Rig not arrive and be in Rig Ready Condition at the Operator’s designated location in the Area of Operations on or before the Latest Delivery Date, Operator will have the right to terminate this Drilling Contract in accordance with Section 13.2(c) at any time thereafter; provided, however, that Operator’s right to terminate pursuant to this Section 2.2(e)(i) shall expire (if not previously exercised) upon the Rig’s arrival and presentment in Rig Ready Condition at the Operator’s designated location in the Area of Operations.  If the Rig has not arrived and been presented in Rig Ready Condition at the Operator’s designated location in the Area of Operations on or before May 1, 2015 (which date shall be extended for documented periods of Force Majeure, delays caused solely by Operator Group, and changes to the Rig requested by Operator), then for each period of seven (7) days thereafter until the Term Commencement Date, Contractor shall grant Operator one (1) free Rig day when the Operating Rate would otherwise apply following the Term Commencement Date (any such free Rig days, collectively, the “Delay Damages”).  The Parties agree that Delay Damages are not a penalty and shall apply as a limitation on Contractor’s liability for failure of the Rig to

13

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

arrive and be in Rig Ready Condition at the Operator’s designated location in the Area of Operations on or before May 1, 2015 (as may be extended pursuant to this Section 2.2(e)(i)), regardless of fault.  The Parties hereby acknowledge and agree that the amounts fixed pursuant to this Section 2.2(e)(i) are a genuine and reasonable estimation of the losses and damages that Operator will incur in the event of Contractor’s failure to procure the Rig’s arrival and presentment in Rig Ready Condition at the Operator’s designated location in the Area of Operations on or before May 1, 2015 (as may be extended pursuant to this Section 2.2(e)(i)) in accordance with this Drilling Contract.  If such provisions (or any part thereof) in this Section 2.2(e)(i) are found for any reason to be void, invalid or otherwise inoperative, such provisions (or any part thereof) shall be deleted from this Drilling Contract and the balance of this Drilling Contract shall remain in full force and effect.  Without prejudice to the foregoing, in such an event Contractor shall be liable for damages at law for any failure to comply with its obligations to procure the Rig’s arrival and presentment in Rig Ready Condition at the Operator’s designated location in the Area of Operations on or before May 1, 2015 (as may be extended pursuant to this Section 2.2(e)(i)) in accordance with this Drilling Contract; provided that such damages shall, regardless of fault, be limited to the amount which would have been payable had these provisions (or part thereof) in this Section not been void, invalid or otherwise inoperative.

(ii)Should Operator terminate this Drilling Contract pursuant to Section 2.2(e)(i), then such termination shall be the sole and exclusive remedy of Operator under this Drilling Contract for such delay in delivery.

(iii)Contractor’s delivery and provision of the Rig to Operator in accordance with Section 2.2(b) is a condition of this Drilling Contract and a fundamental obligation of Contractor and, except as expressly provided in this Drilling Contract, Contractor shall not be excused from performance of its obligations in Section 2.2(b) for any reason whatsoever.

2.3Drill Site Access and Bottom Survey

(a)Operator shall provide Contractor with sufficient rights of ingress to and egress from the Designated Well locations, subject to reasonable procedures and any requirements of Governmental Authorities.  In the event of any restrictions or limitations on Operator which inhibit or impair such rights, Operator shall promptly advise Contractor in writing of the same.

(b)All drilling sites shall be subject to the approval of underwriters’ surveyors and within the specifications of the Rig.  Operator shall be responsible for (i) selecting, (ii) surveying and marking the drill sites and routes of ingress and

14

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

egress, if required, in a timely manner in accordance with Contractor’s underwriters’ requirements and (iii) clearing drilling locations.  Operator shall also provide Contractor with soil analysis (if required by Contractor or surveyors), sea/Metocean conditions and bathymetry charts specified by Contractor or its underwriters for Contractor’s riser analysis.  Contractor shall be solely responsible for determining that the bottom or seabed conditions at the drill site are satisfactory to properly position the Rig for operations under this Drilling Contract.  Operator shall furnish Contractor any relevant information relating to seabed, soil or subsurface conditions (including pipelines, cables, subsea wells, and umbilicals) which may be an impediment to positioning or drilling that Operator possesses or which may be reasonably requested by Contractor.  It shall be Contractor’s obligation to determine whether soil and sea bottom condition surveys and subsurface boring surveys are necessary to assure proper placement of the Rig for operations under this Drilling Contract, and, if so, Operator shall employ a competent marine surveyor to perform the surveys.  Contractor shall arrange for performance of a riser analysis at each location by a company with expertise.  Operator shall pay all costs incurred by Contractor in connection with each riser analysis.

2.4Contractor’s Rig

(a)The Rig shall be capable of operating in the Area of Operations in an efficient and safe manner, and in conformity with all applicable laws and the requirements of all relevant Governmental Authorities, in water depths of up to 12,000 feet and of drilling to a measured depth of 40,000 feet.  At the Term Commencement Date, and throughout the term of this Drilling Contract, Contractor warrants that the Rig shall:

(i)comply with the Specifications;

(ii)be registered under the flag of the Flag State and in the ownership of Contractor or any of its Affiliates;

(iii)be classed by ABS and certified “DPS-3” “A1E” without any recommendations or conditions affecting her class;

(iv)be maintained by Contractor with original equipment manufacturer parts or other spare parts as approved by Contractor’s engineering department;

(v)be tight, staunch, and strong; and be in thoroughly efficient order and condition, and in every way fit, equipped and supplied for deepwater drilling operations and the uses and services contemplated in this Drilling Contract, with her machinery, pumps, and navigational equipment fully functional and in good working order and condition;

15

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(vi)have a full complement of marine crew and drilling personnel for a rig of her type and capabilities, in the number required by the laws of all applicable Governmental Authorities, and who shall have the knowledge, skills and abilities and who shall all be trained to operate the Rig and her equipment competently and safely and in accordance with Good Industry Practices; and

(vii)shall have on board all certificates, documents, approvals, permits, permissions and equipment required by ABS and any Governmental Authority as may be necessary to enable her to carry out all required operations under this Drilling Contract without delay or hindrance.

(b)In performing the Work, Contractor shall utilize the Rig and the Rig shall be furnished in good condition for performance of the Work in accordance with the Management System at the time of commencement of operations hereunder and throughout the term of this Drilling Contract.  If Contractor fails to provide the Rig in compliance with the requirements of this Drilling Contract, Contractor will be in default of this Drilling Contract, and Operator may exercise all contractual remedies pursuant to Article XIII.

(c)Contractor hereby acknowledges and agrees that, during and throughout the Primary Term and any Extension Term, for so long as no default by Operator has occurred and is continuing hereunder, neither Operator nor any permitted assign shall be disturbed or interfered with by Contractor or any of its Affiliates in Operator’s or such permitted assign’s quiet and peaceful use and enjoyment of the Rig (including, without limitation, Operator’s ability to use the Rig in deepwater offshore drilling operations) other than as required by Governmental Authorities and inspections and trials required by ABS or the Flag State.  Contractor and/or Contractor’s Affiliates shall be permitted by Operator to mortgage or otherwise encumber the Rig with third-party financing arrangements, whereby secured lenders, arrangers, or other financiers shall have a first security interest in the Rig; provided always that (i) Contractor causes any such Affiliates to agree to the provisions set forth in this Section 2.4(c) respecting Operator’s (or its assign’s, as applicable) quiet and peaceful use and enjoyment of the Rig, and (ii) the relevant secured lenders, arrangers, or other financiers provide to Operator a letter of quiet enjoyment in a form reasonably acceptable to Operator in accordance with industry practice.

2.5Effective Date, Acceptance and Commencement of Operations

(a)Effective Date.  This Drilling Contract shall become effective upon the Effective Date, and the term of this Drilling Contract shall commence on the Term Commencement Date and continue until the completion of the Primary Term and any Extension Term, as applicable, or the earlier termination of this Drilling Contract.

16

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(b)Term Commencement Date.  The “Term Commencement Date” shall be that date on which the Rig is presented in Rig Ready Condition at the Operator’s designated location in the Area of Operations, and all of the following conditions have been satisfied in full conformity with this Drilling Contract or otherwise waived by Operator (in writing, and in its sole discretion):

(i)the completion of the Rig Acceptance Testing to determine compliance with the Rig Acceptance Criteria to Operator’s satisfaction;

(ii)the completion of the repair or remediation by Contractor to the Specifications of any Critical Items identified by Operator;

(iii)the preparation of a written plan by Contractor to repair or remediate any Non-critical Items identified by Operator to the Specifications with such plan to be subject to Operator’s agreement, such agreement not to be unreasonably withheld, conditioned or delayed;

(iv)all customs clearances, visa requirements, permits, consents, approvals and authorizations required of Contractor and any of its Affiliates from all Governmental Authorities in order to operate in the Area of Operations and perform the Work have been obtained by Contractor and such Affiliate(s);

(v)Contractor shall have obtained office and shorebase facilities sufficient to perform the Work in the Area of Operations, in accordance with Good Industry Practices;

(vi)the Rig is in compliance with all applicable laws and regulations; and

(vii)the Rig is fully manned in accordance with Section 2.4(a)(vi) and Section 5.2.

(c)Primary Term and Termination Date.

(i)The primary term of this Drilling Contract shall be for a firm period of three (3) years beginning on the Term Commencement Date (the “Primary Term”), except as may be extended or terminated by the provisions of this Drilling Contract.  Unless extended or terminated pursuant to the other provisions of this Drilling Contract, the term of this Drilling Contract shall automatically end upon the latest to occur of (A) the expiration of the Primary Term, (B) the expiration of any Extension Term, or (C) completion of Operator’s last Designated Well (drilled to its planned total depth, unless otherwise modified by Operator in its sole discretion) commenced during the Primary Term, or any Extension Term, as applicable, when the Rig is moved to the Demobilization Point and all of

17

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Contractor’s Items have been loaded and all of Operator’s Items have been off-loaded, whereupon this Drilling Contract shall terminate.

(ii)The Primary Term and any Extension Term shall be extended automatically from day to day for the time necessary to complete any single particular well (drilled to its planned total depth, unless otherwise modified by Operator in its sole discretion) or related operation in progress.  A “well” is a single hole drilled to a predefined final spatial target (provided that multiple holes may be drilled in pursuit of the same target).  Any remedial deviations, re-drilling or sidetracking of the hole shall be restricted to operations required to reach such target.  Any such action taken to achieve a new spatial target or any re-spudding after reaching the initial target to reach such new target shall be considered a new well, unless otherwise agreed by Contractor in writing.  Operator shall not commence Work on a new well or perform operations on an existing well (including, but not limited to, multilaterals, sidetracks, completions, workovers, well tests, abandonments, etc.) that is expected to take longer than sixty (60) days to complete beyond the Primary Term, or any Extension Term, as applicable, without Contractor’s prior consent.  For purposes of this paragraph, “commencement of Work” on a new well or “performance of operations” on an existing well shall not be deemed to have occurred until the date and time the Rig is on the relevant location and the bottom hole assembly is ready to spud in at the mud line.

2.6Extension

At Operator’s option, this Drilling Contract may be extended for a further term of one (1) year (from the expiry of the Primary Term) (the “First Extension Term”), plus at Operator’s option, a further term (from the expiry of the First Extension Term, if opted for by Operator) of one (1) additional year (the “Second Extension Term”) (the First Extension Term and Second Extension Term, each an “Extension Term”).  Operator’s option for the First Extension Term must be exercised by written notice to Contractor on or before the date that is seven hundred and thirty (730) days after the Term Commencement Date.  Operator’s option for the Second Extension Term must be exercised by notice to Contractor on or before the start of the First Extension Term.  During the Primary Term and any Extension Terms, Contractor shall not contractually commit the Rig to any other party while this Drilling Contract is in effect unless the relevant time period for Operator to exercise its respective options pursuant to this Section 2.6 has expired.  The terms of this Drilling Contract shall remain in effect and shall apply during any Extension Term; provided, however, that the Operating Rate applicable to the First Extension Term and the Second Extension Term, as applicable, shall be mutually agreed upon through negotiations by the Parties prior to the date of expiration of the respective option exercise.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

2.7Mobilization and Demobilization

(a)Contractor shall mobilize the Rig and Contractor’s Personnel to the location designated by Operator pursuant to Section 2.2(b).  Contractor shall pay and be responsible for all risks, costs and expenses associated with the Rig and such mobilization, unless otherwise specified in this Drilling Contract, until the arrival of the Rig and her presentment in Rig Ready Condition at the Operator’s designated location in the Area of Operations (and following such arrival and presentment at the Operator’s designated location in the Area of Operations, Operator’s obligations to provide supplies and services to the Rig under Exhibit D in the Area of Operations shall commence (except that Operator shall have already accommodated Contractor’s first crew change after the Rig’s arrival at the Operator’s designated location in the Area of Operations, provided transportation services for Contractor’s Items as specified in Appendix D, Part B(12), and fueled the Rig in accordance with Appendix D, Part D(3)).  Operator shall be entitled to place at its risk, cost and expense its Operator’s Items and its designated representative(s) aboard the Rig for such mobilization, and Contractor shall make available to Operator’s representative(s) all accommodations, provisions and requisites as Contractor supplies to the senior marine crew of the Rig.  Operator shall be entitled to conduct certain aspects of the Rig Acceptance Testing during mobilization; provided that such Rig Acceptance Testing does not interfere with the mobilization or safe operation of the Rig.  Contractor shall invoice Operator for the Mobilization Fee on or after the Term Commencement Date, and such Mobilization Fee shall be due and payable by Operator in accordance with the terms of Article IV.

(b)Contractor shall demobilize the Rig and Contractor’s Personnel at the Demobilization Point upon the earlier to occur of (i) the expiration of the Primary Term or, if applicable, any Extension Term, or (ii) the termination of this Drilling Contract pursuant to Section 13.1 or Section 13.2.  Contractor shall pay and be responsible for all risks, costs and expenses, unless otherwise specified in this Drilling Contract, necessary to move and demobilize the Rig at the Demobilization Point upon Operator’s notification to Contractor of Rig Release.

ARTICLE III
COMPENSATION

3.1Rates and Payment Amounts

Operator shall pay, or cause to be paid, to Contractor the amounts provided in Appendix I at the times and in the manner specified therein and in Article IV in accordance with the terms and conditions of this Drilling Contract.

3.2Change in Locale

(a)As of the Effective Date, Operator contemplates that the wells to be drilled hereunder during the term of this Drilling Contract will be located within the

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

bounds of the U.S. Gulf of Mexico outer-continental shelf lease blocks; however, at any time during the Primary Term or any Extension Term, Operator may request to change the Area of Operations (including, for example, the waters offshore Angola) and the relocation and movement of the Rig to such new Area of Operations and subject to the approval of Contractor; provided that such change does not result in a breach of the American Institute Trade Warranties of the American Institute of Marine Underwriters (dated July 1, 1972) or the Institute Warranties of the Insurance Institute of London, as applicable, or violate the laws, rules and regulations applicable to Contractor or its Affiliates; provided further that Contractor is able to obtain all insurance required by this Drilling Contract, and any other insurance typically carried by Contractor, for operations in the new Area of Operations.  In the event of such a request by Operator, Contractor and Operator shall review this Drilling Contract to determine any changes needed that result from:

(i)any adjustments to address costs and expenses incurred in connection with any change in the Area of Operations or change in the shorebase location, with such adjustments to be reflected in the applicable day rates;

(ii)where the Rig will then be located or positioned at the end of the term of this Drilling Contract; and/or

(iii)changes proposed by either Party to the terms or conditions of this Drilling Contract that are appropriate for the new locale (including any local content requirements).

For the avoidance of doubt, the Area of Operations shall not be changed without a written agreement of the Parties.

(b)Any mutually agreed changes shall be included in an amendment to this Drilling Contract (or the issuance of a new, restated Drilling Contract, as may be applicable) prior to the commencement of Work in the new Area of Operations.  Any such amendment (or new, restated contract) shall cover the period of Work in the new Area of Operations under comparable terms and conditions to the then-existing Drilling Contract and with a term equal to the remaining term of this Drilling Contract, with such other changes as mutually agreed upon during the review.  It is intended by both Parties that any changes to this Drilling Contract for the purposes of this Section 3.2 shall be structured such that Contractor is neither financially advantaged nor adversely affected by the change of locale.

(c)Contractor warrants that, as of the Effective Date, the Rig can be relocated and moved to, and operated in, the waters offshore Angola without breaching any applicable trading or navigation warranties or violating any applicable laws, rules and regulations.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

3.3Day Rate Adjustments and Additional Compensation

(a)After the Term Commencement Date, Operator may request that Contractor outfit the Rig with additional equipment or make other modifications to Contractor’s Items.  Any such request by Operator shall be subject to the approval of Contractor, which shall not be unreasonably conditioned, withheld or delayed.  Any increase in Contractor’s costs (as documented by Contractor to Operator’s reasonable satisfaction) associated with Contractor’s implementation of such request by Operator shall, upon Operator’s agreement of such costs, be paid by Operator to Contractor on a lump-sum, reimbursable basis (notwithstanding any application of the Zero Rate); provided that Operator shall be entitled to elect to amortize such reimbursable amount over the number of days remaining in the Primary Term, or any Extension Term, as applicable, and in that event for any such remaining days such amortized amount shall be separately payable to Contractor regardless of the application of any day rates hereunder (including the Zero Rate).

(b)Provided that no adjustment of the day rates listed in Appendix I shall occur more than once during any twelve (12) month period, from and after the first anniversary of the Term Commencement Date, such day rates (except the Zero Rate) shall be revised (up or down, as applicable) by the actual aggregate amount of the changes (other than those cost changes, if any, caused by changes in applicable laws and regulations and/or actions or inaction of Governmental Authorities, which cost changes shall be exclusively governed by Section 3.3(c)) in the following Contractor’s costs (as documented by Contractor to Operator’s reasonable satisfaction) from their respective values as of the Effective Date (or as later annually adjusted):

(i)Contractor’s labor costs, including all payroll burden, for Contractor’s Personnel:  $[***] per day;

(ii)Contractor’s cost of premiums for the insurance coverages required of Contractor under this Drilling Contract:  $[***] per day;

(iii)Contractor’s cost of catering on board the Rig:  $[***] per day; and

(iv)Contractor’s costs for repair and routine and scheduled maintenance of Contractor’s Items, as increased or decreased based upon the Producer Price Index for “Oilfield Drilling Machinery and Equipment Wholesale Price Index” (Code 1191-02) published by the U.S. Department of Labor, Bureau of Labor Statistics:  $[***] per day.

(c)Day Rate Adjustments for Change of Law

(i)The day rates under this Drilling Contract are based upon enacted applicable laws and regulations of Governmental Authorities and the interpretations thereof by Governmental Authorities, affecting the Work

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

contemplated hereunder in force as of the Effective Date.  The day rates due to Contractor pursuant to this Drilling Contract shall be revised or adjusted by the actual amount of any increase or decrease in Contractor’s aggregate costs

(X)if such enacted applicable laws and regulations are modified and such modifications have become effective or have been entered into force,

(Y)if the Governmental Authorities have interpreted such enacted applicable laws and regulations differently (such difference being evidenced by written documentation from such Governmental Authorities), or

(Z)if new laws and regulations are enacted and have become effective or have been entered into force,

in each case of clause (X), (Y) or (Z), taking effect from and after the Effective Date and subjecting Contractor (and all other similarly situated deepwater offshore drilling contractors) and/or the Rig (and all other drillships of similar type and characteristics) to new tax, operating, manning, maintenance, equipment or structural requirements; provided that

(A)any such aggregate cost increase does not exceed five percent (5%) of the amount of the affected day rate, and is documented by Contractor to Operator’s reasonable satisfaction,

(B)any such cost increase is due solely to Contractor’s necessary efforts to comply with the modified (including new interpretations by Governmental Authorities) or new laws and regulations,

(C)any such modified (including new interpretations by Governmental Authorities) or new laws and regulations does not increase Contractor’s profits,

(D)any such new tax requirements shall be limited to those that relate to taxes that are directly levied upon Contractor in connection with its performance of the Work hereunder and shall exclude any income tax requirement (or any increase thereof), and

(E)upon Operator’s request, the Parties shall meet to discuss and agree upon when such rate increase shall be applicable given the particular facts and circumstances of the modified (including new interpretations by Governmental Authorities) or new laws and

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

regulations, failing such agreement, the applicable date of such rate increase shall be the date on which Contractor achieves compliance with such modified (including new interpretations by Governmental Authorities) or new laws and regulations, in each case, giving rise to such rate increase.

(ii)Except as provided below in Section 3.3(c)(iii), for any change described in Section 3.3(c)(i) that may result in an increase of Contractor’s costs in an amount that is more than five percent (5%) of the amount of the affected day rate, the Parties shall meet to discuss and agree in good faith the particular facts and circumstances of such change.

(iii)For any change described in Section 3.3(c)(i) that requires capital expenditures by Contractor for purposes of the physical or structural improvement, modification, or upgrade to the Rig or her equipment (including the addition of equipment), any such expenditure (documented to the reasonable satisfaction of Operator) shall be reimbursed by Operator at the amount that is equal to the amount of such expenditure times the ratio of (x) the remaining term of this Drilling Contract as of the time of such expenditure to (y) the remaining operating life of the Rig (based upon the total operating life of twenty (20) years) as of the time of such expenditure, and such reimbursable amount shall be amortized over the number of days remaining in the Primary Term, or any Extension Term, as applicable, and be separately payable to Contractor regardless of the application of any day rates hereunder (including the Zero Rate).  In no event shall Operator be required to make any payments for any change in costs due to any modified or new laws that are determined after termination of this Drilling Contract.

ARTICLE IV
INVOICES

4.1Contractor Invoices

Contractor shall endeavour to present invoices, accompanied by copies of vouchers, records, receipts or other evidence as may reasonably be requested by Operator, to Operator at Operator’s office for each month during the Primary Term, or any Extension Term, as applicable, on or before the fifteenth (15th) day of the following month, and in any case within ninety (90) days of conclusion of the Work on a Designated Well.  Contractor’s final invoice statement shall be presented by Contractor to Operator’s office within ninety (90) days following the date of expiration or earlier termination of this Drilling Contract.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

4.2Payment

(a)Subject to the terms and conditions of this Drilling Contract, payment shall be made to Contractor, by wire transfer in accordance with the bank instructions to be provided by Contractor, within thirty (30) days following receipt of a properly supported invoice from Contractor.  Payment of any invoice shall not prejudice the right of Operator to question, in good faith, the correctness of any charges therein.  If Operator disputes an item, Operator shall promptly notify Contractor of the item disputed, specifying the reason therefor, and payment of the disputed amount may be withheld until settlement of the dispute.  Or, at Operator’s sole option, any disputed amount may be paid without waiver of the right to seek reimbursement for such amounts.  However, timely payment shall be made of any undisputed portion.  Subject to this right, any undisputed payments or payments of disputed amounts resolved in Contractor’s favor which are not made within thirty (30) days as aforesaid shall bear interest at LIBOR plus [***] on the date the invoice was due for payment from the end of the thirty (30) day period until paid.  Operator and Contractor shall endeavour to resolve any disputed item in a timely manner, and when resolved, payment shall be made forthwith.  Payment of any amounts by Operator shall not be deemed a waiver of Operator’s or Contractor’s rights under this Drilling Contract.

(b)Operator shall have the right to offset payments due to Contractor against liquidated and undisputed sums owed to Operator by Contractor under this Drilling Contract.  If Operator, at any time, incurs costs which, under the provisions of this Drilling Contract, are for Contractor’s account or Operator is otherwise entitled to recover from Contractor, Operator may invoice Contractor for such costs and Contractor shall pay Operator within thirty (30) days following receipt of a properly supported invoice from Operator.

(c)None of the presentation, payment or non-payment of an individual invoice shall constitute a settlement of a dispute, an accord and satisfaction, or a remedy of account stated, or otherwise waive or affect the rights of the Parties hereunder.

4.3Contractor’s Records; Audit

Contractor shall maintain a complete and accurate set of records pertaining to all aspects of this Drilling Contract.  Operator, in order to verify that all the terms and conditions of this Drilling Contract have been complied with, shall have the right, upon reasonable advance notice and during normal business hours and at Operator’s sole expense, to inspect and audit at Contractor’s place of business, any and all such records within a period of twenty-four (24) months after the year of termination of this Drilling Contract; provided that Contractor shall have the right to exclude any trade secrets, formulae, or processes from such inspection and audit, except to the extent they relate directly to payments or reimbursements in accordance with this Drilling Contract; in such case, Operator agrees to hold such information confidential.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

4.4Operator’s Invoices; Payments to Operator

All amounts and sums due and payable hereunder by Contractor to Operator shall be payable by wire transfer in accordance with the bank instructions to be provided by Operator.

ARTICLE V
EQUIPMENT, SERVICES, AND PERSONNEL

5.1Contractor’s Rig and Equipment

(a)Contractor shall, at its own expense, furnish Contractor’s Items.  Additionally, Contractor shall provide, at its own cost, materials, equipment, services, personnel, consumables, spares and facilities not identified herein, but which are required for the Work and which are customarily or necessarily provided by a deepwater drilling contractor furnishing a deepwater drilling rig in the Area of Operations, in accordance with Good Industry Practices and on a non-reimbursable basis and in order to allow uninterrupted operations in a timely manner and in full compliance with this Drilling Contract.

(b)In support of the Work to be performed by Contractor in the Area of Operations, and in consideration for the remuneration to be paid by Operator hereunder, Contractor shall be responsible for providing, at its sole cost and expense (subject to the uplift provisions at Section 3.3), all supporting services, supplies, and other logistical items whatsoever which may be required, by the laws, regulations, orders and other directives of any Governmental Authority, to be procured from local vendors, suppliers, and other Persons as necessary for the performance of Work in accordance with this Drilling Contract.

(c)Prior to the Term Commencement Date, Contractor, at its expense, shall provide manufacturer and Third Party inspection certificates for Contractor’s furnished drill pipe, HWDP, drill pipe pup joints, inside BOPs, lower kelly valves, drill collars, subs, and similar items in new condition, delivered in accordance with inspection standards to be mutually agreed upon by the Parties.  All such new drill pipe and items shall be in accordance with API Spec 5D and API Spec 7.  Operator may, at its expense, have a Third Party quality assurance representative present during any inspections of such drill pipe and items.  Any new drill pipe or items failing the initial inspection shall be repaired or replaced at Contractor’s expense.

Prior to the Term Commencement Date, Contractor, at its expense, shall provide manufacturer and Third Party inspection certificates for Contractor’s furnished drill pipe, HWDP, drill pipe pup joints, inside BOPs, lower kelly valves, drill collars, subs, and similar items in used condition, delivered in accordance with T. H. Hill & Associates Drill Pipe Inspection Standards, DS-I, Category 5.  All such used drill pipe and items shall be in accordance with API Spec 5D, API Spec 7, and API RP7G.  Operator may, at its expense, have a Third Party quality

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

assurance representative present during any inspections of such drill pipe and items.  Any used drill pipe or items failing the initial inspection shall be repaired or replaced at Contractor’s expense.

(d)Prior to the Term Commencement Date, Contractor, at its expense, shall provide manufacturer and Third Party inspection certificates for Contractor’s furnished riser, delivered in accordance with API RP16Q.  Contractor shall provide Operator with a copy of the results of the inspection.  Any riser failing the initial inspection shall be repaired or replaced at Contractor’s expense.

(e)Contractor shall furnish two (2) BOPs as specified in Appendix C.  Prior to the Term Commencement Date and periodically thereafter, as requested by Operator and pursuant to laws or regulations of the applicable Governmental Authority, Contractor shall inspect and test each BOP, with said inspection and test to be performed in accordance with any governmental regulation or interpretation thereof for API S53 (and as updated or amended) as of the date of said inspection and test.  In the event that a BOP fails to pass its initial inspection and test following arrival of the Rig and her presentment in Rig Ready Condition at the Operator’s designated location in the Area of Operations, Contractor shall, at Contractor’s sole cost, repair or replace the BOP and/or the BOP’s consumables (including rubber goods, operating piston, bonnet gaskets, and other sealing elements), as necessary, so that the BOP finally passes such inspection and test.

Following the initial BOP inspection and test described above, in the event that a BOP fails to pass any subsequent inspection and test, Contractor shall, at Contractor’s cost, repair or replace the BOP and/or the BOP’s consumables, as necessary, so that the BOP finally passes such inspection and test, but Contractor’s costs of all such repaired or replaced BOP consumables shall be reimbursed by Operator pursuant to Appendix D, Part D(13).  Operator, at its expense, may have a Third Party quality assurance representative present at the time of any inspection and test of a BOP hereunder.

(f)Except as otherwise provided in this Drilling Contract, if, during the drilling of any Designated Well, Contractor’s drill string (inclusive of drill pipe, HWDP, drill collars, subs and similar items) should have excessive failures due to any cause, Operator shall have the right to require Contractor, at Contractor’s expense, to have failed components, in use or to be used, inspected according to the aforementioned standards.  Contractor shall provide Operator with a copy of the results of the inspections.

(g)Contractor shall procure shorebase space, to facilitate the performance of the Work, at Port Fourchon, Louisiana, or such other location, as mutually agreed upon by the Parties.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(h)Following the Term Commencement Date, Contractor shall arrange and conduct all subsequent inspections of the in-hole equipment, including but not limited to the regularly scheduled inspections at intervals specified in Contractor’s policies and procedures, inspections requested by Operator, and a final inspection at the end of the term of this Drilling Contract.  Operator shall designate the inspection level which shall meet or exceed the level specified by Contractor’s policies and procedures, and shall pay all expenses related to such inspections (including transportation costs).

(i)Except as otherwise provided, Contractor shall arrange and pay for the initial inspection and certification of Contractor’s subsea equipment and for subsequent inspections during the Primary Term, or any Extension Term, as applicable, in accordance with Contractor’s policies and procedures; provided that Contractor shall use commercially reasonable efforts to conduct all such inspections in a manner that minimizes the impact to the operational continuity of the Work.  Any additional inspections and/or certifications of Contractor’s subsea equipment requested by Operator shall be arranged by Contractor but at Operator’s expense.

(j)Contractor shall arrange and pay for the initial inspection and certification of the Rig’s drawworks and other hoisting/lifting equipment and for subsequent inspections during the Primary Term, or any Extension Term, as applicable, in accordance with Contractor’s policies and procedures; provided that Contractor shall use commercially reasonable efforts to conduct all such inspections in a manner that minimizes the impact to the operational continuity of the Work.  Any additional inspections and/or certifications of the Rig’s drawworks and other hoisting/lifting equipment requested by Operator that are in excess of Contractor’s policies and procedures shall be arranged by Contractor but at Operator’s expense.

5.2Contractor Personnel

(a)Contractor shall furnish, at Contractor’s cost, the personnel in the numbers, classifications and work schedules as set forth in Appendix B (“Contractor’s Personnel”).

(b)Contractor’s Personnel shall have the knowledge, skills and abilities to perform their assigned tasks and shall be trained, licensed and certified as required by all applicable laws, rules and regulations.  Contractor represents and warrants that it and its contractors and subcontractors performing the Work have and will maintain all applicable licenses and certifications necessary for the performance of the Work.  Contractor shall verify all relevant qualifications of Contractor’s Personnel.

(c)Contractor shall have roustabout crews available on the Rig to load and unload boats from the Rig and perform other labor on a twenty-four (24) hour basis,

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

together with a catering crew sufficient to provide room and board for all persons on board the Rig.

(d)Operator may, at any time, with Contractor’s approval, not to be unreasonably withheld, require Contractor to increase the number of Contractor’s Personnel.  Such additional personnel shall be provided at the rates per day specified in Appendix B (which such rates may be subject to adjustment annually effective the anniversary of the Term Commencement Date pursuant to Section 3.3(b)(i)).  Other than resignation or discharge, Contractor shall seek approval of Operator prior to changing out Key Personnel which shall not be unreasonably withheld, delayed or conditioned.

(e)If, with Operator’s consent, Contractor’s Personnel are reduced, Operator shall be credited with the savings resulting therefrom.

(f)For any day for which Contractor fails to provide the numbers and classification of Contractor’s Personnel specified in Appendix B, the rate at which Contractor is being paid for such day shall be reduced by an amount equivalent to the amount of wages and employee benefits which would have otherwise been paid for such personnel, subject to Contractor being allowed a reasonable period of time to replace Contractor’s Personnel, which shall not exceed forty-eight (48) hours (except in the case of Force Majeure or other severe weather which would prevent reasonable means of transportation); provided, however, that no reduction shall apply in the case of missing Contractor’s Personnel due to medical reasons or reasons of compassion.

(g)Contractor shall promptly replace, at Contractor’s expense, any Contractor’s Personnel that Operator reasonably considers detrimental to normal operational efficiency, safety, good order or discipline at the Designated Well site.  Such decision, specifying the reason thereof, shall be made in writing by Operator’s designated representative.

(h)Subject to the provisions set forth in Section 3.3, Contractor shall comply, at its sole cost and expense, with any and all laws, regulations, orders, directives or other requirements of any applicable Governmental Authority for the hiring of citizens of any applicable country to perform technical, labor or other services for Contractor in conjunction with the Work to be performed hereunder.  Contractor shall promptly provide, upon Operator’s request, details on such Contractor’s Personnel employed by Contractor and their respective residences when employed as necessary to comply with requirements of Governmental Authorities.

(i)Contractor shall make its own arrangements for the engagement of Contractor’s Personnel, local or otherwise, and for their compensation and onshore transport, housing, maintenance, board and lodging, and all other associated costs and support.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(j)Contractor shall notify Operator immediately of any proposed or actual stoppages of work, industrial disputes or other labor matters affecting or likely to affect the carrying out or completion of the Work.

(k)In the event Operator requires Contractor’s Personnel to attend courses or training classes in excess of Contractor’s training program specified in the Management System, Operator will reimburse Contractor for all expenses incurred by Contractor in connection with such attendance, including but not limited to the costs of all such courses or training classes, the labor costs for Contractor’s Personnel during their travel to and attendance at such courses or training classes, and the transportation, lodging and food costs for Contractor’s Personnel.

(l)In the event Operator requires Contractor’s Personnel to attend meetings (other than courses or training classes) in excess of their normal twelve (12)-hour shift or Contractor’s required meetings such as crew meetings prior to helicopter transport to the Rig or while aboard the Rig, Operator will reimburse Contractor for all labor costs incurred by Contractor for Contractor’s Personnel during their attendance at such meetings in connection with such attendance.

5.3Contractor Services

(a)At the written request of Operator, and with Contractor’s concurrence, Contractor shall provide, for the account of Operator, any of the materials, supplies, or services that Operator is obligated to furnish hereunder on a reimbursable basis plus a handling fee as specified in Appendix I.  Items and services so provided shall continue to be classified as Operator’s Items pursuant to the provisions of this Drilling Contract.

(b)If Operator requests services pursuant to Section 5.3(a), Contractor agrees that it will obtain the written approval of Operator before contracting any Work at rates in excess of those charged for comparable Work on similar operations.

5.4Operator Items, Services, Personnel and Facilities

(a)Operator shall furnish at its cost (or shall reimburse Contractor for furnishing), the equipment, facilities, materials or supplies to be furnished by Operator as specified in Appendix D for the duration of the term of this Drilling Contract.

(b)Insofar as reasonably possible, Contractor shall visually examine, before using, all equipment, facilities, materials, or supplies furnished or obtained by Operator for the operations herein and shall report to Operator any obvious defects therein, and Contractor shall not use any such defective equipment, facilities, materials or supplies.

(c)Upon termination of this Drilling Contract, Contractor shall return to Operator all equipment, facilities, materials or supplies received by Contractor from Operator

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

or purchased by Contractor for Operator’s account and not consumed, lost or damaged in the operations in the same condition as received, ordinary wear and tear excepted, and Contractor shall be reimbursed by Operator for any shipping costs incurred and paid by Contractor to deliver such equipment, facilities, materials or supplies.

(d)Operator shall be responsible, at its cost, for the maintenance and repair of all Operator’s Items on board the Rig that Contractor cannot maintain or repair with Contractor’s normal complement of Contractor’s Personnel within their competency and Contractor’s Items.  Operator shall also be responsible for the cost of any overtime paid by Contractor to Contractor’s Personnel in respect of the maintenance or repair on board the Rig of Operator’s Items or other overtime required by Operator.

(e)Operator acknowledges that all personnel aboard the Rig are subject to applicable law, rules and regulations, including without limitation the International Ship & Port Facility Security (ISPS) Code, and Contractor’s implementation and enforcement thereof, including the Rig’s Ship Security Plan.  In particular, all of Operator-supplied personnel shall be: (i) prepared to present a valid photographic identification prior to embarking for the Rig, (ii) required to undergo security awareness training aboard the Rig, (iii) subject to tests and verification of identification while aboard the Rig, and (iv) subject to search of their person and personal effects upon embarking and disembarking the Rig.  In addition, at least seven (7) days prior to the commencement of operations under this Drilling Contract, Operator will provide Contractor with the contact information in respect of any Operator-provided helicopter and vessel support services in order that Contractor may prepare any required declaration of security documentation.  In order to minimize the risk of transportation delays, Operator, as soon as practical, and in any event prior to presenting Operator-supplied personnel for travel to the Rig, will provide the Rig’s master/security officer with the names and employers of such personnel.

(f)Operator shall promptly replace, at Operator’s expense, any Operator-supplied personnel aboard the Rig that Contractor reasonably considers detrimental to normal operational efficiency, safety, good order or discipline on board the Rig.  Such decision, specifying the reason thereof, shall be made in writing by Contractor’s designated representative.

(g)Operator shall provide deckhands to man all supply vessels and, in no case, shall Contractor’s roustabouts be required to board such supply vessels for loading or unloading operations.

(h)The Parties shall measure and record the amount of fuel aboard the Rig upon her arrival at the Operator’s designated location in the Area of Operations, and Operator shall pay Contractor for such fuel at the documented cost of such fuel.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

The Parties shall also measure and record the amount of fuel aboard the Rig on the commencement of demobilization, and Contractor shall pay Operator for such fuel at the documented cost of such fuel.  Operator shall remain obligated throughout the duration of the Primary Term, or any Extension Term, as applicable, to supply and pay for diesel fuel, including any periods when the Zero Rate or a reduced day rate applies to the Work.  All fuel so supplied shall meet Contractor’s fuel quality specifications set forth in the Management System and be in accordance with applicable laws, rules and regulations.

ARTICLE VI
PERFORMANCE OF THE WORK

6.1General

Contractor shall carry out the Work and conduct the drilling operations, as well as tasks normally associated therewith, in accordance with the requirements of this Drilling Contract and according to the specifications and instructions issued by Operator from time to time, consistent with the HSSE Bridging Agreement, the Well-Control Bridging Agreement, the Management System, and all applicable laws and regulations.  Contractor shall notify Operator if performance of the Work according to the specifications and instructions issued by Operator would exceed the capabilities of the Rig and/or would be contrary to Contractor’s standards, policies and procedures and all applicable laws and regulations.  The drilling of each well shall be commenced without delay (unless such delay is ordered by Operator) after operations are completed at the previous well, if any.  Contractor shall be responsible for the operation of the Rig, including moving operations and positioning on drilling locations as required by Operator.  Operations under this Drilling Contract will be performed on a twenty-four (24) hour per day basis.

6.2Drilling of Wells

Contractor agrees to drill each well to the depth specified by Operator, and to perform other operations pursuant thereto.  Contractor agrees to use all reasonable efforts at all times to keep the wells under control and for the prevention and control of blowouts in accordance with Good Industry Practices.

6.3Drilling Fluids

Operator shall have the right to specify the type and characteristics of drilling fluids.  Without prejudice to Article VIII, Contractor agrees to take reasonable care in the handling of the drilling fluids.  During the drilling of any well, and as often as it desires, Operator shall have the right to have made any test of drilling fluids.  Without prejudice to Article VIII, Contractor shall use reasonable efforts to comply with the drilling fluid program of Operator.  Contractor shall maintain adequate and serviceable working solids equipment on board the Rig in accordance with Appendix C.  Operator shall provide

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Contractor with Operator’s drilling fluid program reasonably in advance of the spud date of each well to be drilled hereunder.

6.4BOP Maintenance and Testing

Contractor shall maintain blowout preventer assemblies and control equipment, as described in Appendix C, in good operating condition and in accordance with all applicable laws, regulations, API standards and recommendations and the Management System.  Contractor shall test blowout preventer assemblies, surface control equipment and accessories, such as flow lines, valves, choke manifolds and connections, to pressures as required by Operator’s representatives (but not to exceed the applicable manufacturer’s recommended field test pressures), and not less frequently than as required by current regulations in effect.

6.5Environmental, Health and Safety

(a)Contractor shall observe all applicable environmental, health and safety laws, rules and regulations for the Work issued by Governmental Authorities.  Contractor shall inform its contractors and subcontractors, and all members of Contractor Group, regarding all such environmental, health and safety rules and regulations, and all safety meetings and drills conducted shall be entered on the IADC-API Daily Drilling Report.  Contractor shall furnish such additional safety reports and records as Operator may request.  It is Contractor’s responsibility to adopt, implement and enforce policies, plans and procedures that affect Contractor’s employees, representatives and agents, and those of its contractors and subcontractors.  Contractor shall provide safety performance evaluations to Operator and, as required, to applicable Governmental Authorities.  Contractor shall, throughout the term of this Drilling Contract, maintain a safety Management System and provide same to Operator.

(b)Operator and Contractor shall execute a mutually agreeable bridging document to address the interface of Contractor’s safety Management System with Operator’s environmental, health and safety requirements and Operator’s Safety and Environmental Management System program for its facilities and operations in the Area of Operations (the “HSSE Bridging Agreement”).  The HSSE Bridging Agreement must be executed prior to the commencement of any offshore activity under this Drilling Contract (and not later than November 1, 2014) and, when Contractor is performing Work in the Area of Operations, Contractor shall operate according to the HSSE Bridging Agreement.

(c)Operator and Contractor shall execute a mutually agreeable bridging document to address the interface of Contractor’s well-control policy and procedures with those of Operator for its facilities and operations in the Area of Operations (the “Well-Control Bridging Agreement”).  The Well-Control Bridging Agreement must be executed prior to the commencement of any offshore activity under this

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Drilling Contract (and not later than November 1, 2014) and, when Contractor is performing Work in the Area of Operations, Contractor shall operate according to the Well-Control Bridging Agreement.

6.6Samples of Cuttings and Cores

Contractor shall save and identify cuttings and cores, as designated by Operator, free from contamination, and place them in separate containers which will be furnished by Operator, with such cuttings and cores to be treated in a confidential manner and delivered only to the designated representatives of Operator.

6.7Abnormal Drilling Conditions and Well Control

(a)In the event of any difficulty arising which precludes either drilling ahead under reasonably normal procedures or the performance of any other operations planned for a well, Contractor shall suspend the work in progress and shall immediately notify the representative of Operator, in the meantime exerting all reasonable efforts in accordance with Good Industry Practices to overcome any such difficulty.

(b)In the event of loss of or damage to the hole, the provisions of Section 8.6 will apply.  In the event it is impossible to overcome any such difficulty or if, for any reason in Operator’s or Contractor’s opinion, further drilling operations cannot proceed under normal conditions, Contractor will, upon notice to Operator, discontinue further drilling and plug and abandon such well, or complete same at any specified lesser depth.  In each instance where difficulties or conditions referred to in this Section 6.7 have been encountered and overcome, drilling under normal conditions shall be resumed.

6.8Installations of Wellhead Equipment

Contractor, at Operator’s request, shall install, in accordance with Good Industry Practices and in a manner satisfactory to Operator, subsea wellheads and all other usual and customary associated equipment and connections furnished at the wells by Operator, and Operator shall pay the Operating Rate for such Work, including Rig time for testing the wells to the satisfaction of Operator.

6.9Producing Formations

Contractor shall notify Operator’s representatives immediately upon discovery of any oil or gas bearing formation that becomes known to Contractor.

6.10Measurement of Pipe

Contractor shall measure with a steel tape the total length of drill pipe in service before setting each string of casing or liner at total depth of the hole and at other times as

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

specified by Operator, and Contractor shall promptly record all such measurements in Contractor’s IADC-API Daily Drilling Report.

6.11Additional Obligations of Contractor

Contractor shall:

(a)Use and operate the Rig and Contractor’s Items within the applicable manufacturer’s recommended operating limits in order to maintain safety and Good Industry Practices.

(b)Use kelly saver sub protectors and use Operator-provided drill pipe casing protectors for surface casing.

(c)Preserve all thread protectors on casing, tubing, rental tools or other equipment furnished by Operator.  All threads shall be cleaned and pipe thread grease shall be used in making all pipe connections.

6.12Rig Operational Limits

(a)The Rig shall comply with all applicable laws, rules and regulations in effect on the Term Commencement Date, and during the term hereof, including those promulgated by the Flag State and Governmental Authorities.

(b)Contractor shall allow all of Contractor’s Items to be operated within the limits allowed in accordance with the Management System.

(c)Contractor shall be solely responsible for the operation and control of the Rig, and shall have final authority regarding the safety and operation of all systems and Contractor’s Personnel, including the supervision of moving operations, the positioning of the Rig at any Designated Well site (with Operator solely responsible for positioning of the Designated Well on the seabed), and the movement of the Rig.  The exercise of Contractor’s authority shall include making the final decisions regarding:

(i)Sea and wind or other conditions which permit safely positioning the Rig on location, departing the location, and conducting operations at the location.

(ii)Preparing the Rig for moving.

(iii)Sea and wind or other conditions under which the Rig may be prepared for moves conducted between locations.

(iv)Sea and wind or other conditions existing or impending under which the Rig shall be moved to sheltered waters.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(v)Selection and/or approval of necessary acoustic and/or underwater station keeping devices and services and the utilization thereof.

(vi)Existing or impending wind, wave and current conditions or any combination thereof which will cause normal operations to be suspended and require the well or riser to be secured in order to ready the Rig for moving to a safe location, or to prevent pollution.

(vii)Evacuation or movement of the Rig due to weather conditions or pending weather conditions; provided that the well then being drilled is secured.

(d)The exercise of Contractor’s authority under this Section 6.12 shall not affect Contractor’s right to be paid at the applicable rate for any waiting time or other Rig time in which Contractor’s judgment is in accordance with the Management System and reasonable under the circumstances for preservation of the Rig and safety of personnel thereon.  Contractor agrees to consult with Operator and give reasons for any action that causes delays and waiting time.  However, Contractor’s judgment in such matters shall be final.

6.13The Drilling Program

Subject to Section 6.12, Contractor shall follow Operator’s instructions with respect to Operator’s drilling program or the written instructions provided by Operator.  Operator shall provide Contractor with a copy of Operator’s drilling program, and any other information reasonably requested in writing by Contractor, reasonably in advance of the spud date of each Designated Well to be drilled hereunder.  Each drilling program shall include (but not necessarily be limited to) hole sizes, casing program, mud control program, positive and negative pressure test procedures, and Operator’s deviation policy.  Operator may modify these programs prior to or during the Work, and shall promptly notify Contractor of all such modifications.

6.14Standards and Compliance with Law

Contractor warrants:

(a)that Contractor, Contractor’s contractors and subcontractors, and its and their respective employees will adhere to all posted safety rules and regulations and the matters set forth in the HSSE Bridging Agreement and the Well-Control Bridging Agreement;

(b)that it has established written safety rules and regulations and that Contractor, Contractor’s contractors and subcontractors, and its and their respective employees will be fully informed of and will adhere to such safety rules and regulations;

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(c)that it (i) has provided its employees and the employees of Contractor’s contractors and subcontractors with the knowledge, skills and abilities to perform the Work in a safe and competent manner before any such employee performs the Work hereunder, (ii) will provide continuance training for its employees and the employees of Contractor’s contractors and subcontractors to perform the Work in a safe and competent manner, (iii) will institute a methodology to verify the knowledge, skills and abilities of each of its employees and the employees of Contractor’s contractors and subcontractors, and (iv) will provide verification of such knowledge, skills and abilities to Operator upon request;

(d)that Contractor will deliver to its employees and the employees of Contractor’s contractors and subcontractors copies of Contractor’s policies and procedures, the HSSE Bridging Agreement, and the Well-Control Bridging Agreement, as may be applicable to the respective services provided by such employees, and all of Contractor’s contractors and subcontractors utilized in the performance of the Work will be formally assessed and approved regarding compliance with the HSSE Bridging Agreement and the Well-Control Bridging Agreement prior to accessing the Rig;

(e)that its business will be conducted in English;

(f)that Key Personnel and all supervisors can read, write and speak fluent English;

(g)that its invoices, procedures and operating manuals will be in English;

(h)that all Contractor’s Personnel act in accordance with all applicable laws and regulations (including immigration laws) and are in possession of any required valid work permit for the duration of this Drilling Contract, and that copies of all such permits will be submitted to Operator upon request; and

(i)that Contractor for itself and on behalf of its Affiliates, agents, employees and subcontractors will comply with the terms and provisions of the HSSE Bridging Agreement, the Well-Control Bridging Agreement and the Management System.  In the event that Operator at any time requests adherence or observance of any other standard, policy or procedure (except that stipulated by any applicable law, rule or regulation with which Contractor shall comply) which sets out standards different from those embodied within the Management System, then in the absence of any agreed bridging or interface document including the HSSE Bridging Agreement and the Well-Control Bridging Agreement entered into between the Parties, the Management System shall prevail and be deemed to be the standard with which Contractor is to comply.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

ARTICLE VII
REPORTS TO BE FURNISHED BY CONTRACTOR

7.1Drilling Reports

Contractor shall each day furnish Operator’s designated representative two (2) signed copies of daily drilling reports in detail on standard IADC-API Daily Drilling Report form, or equivalent, furnished by Contractor, and Contractor agrees to maintain copies of the Daily Drilling Reports for a minimum of two (2) years.  This report shall specifically include details of time breakdown on all operations and a clear description of all operations, including lost time, repairs, difficulties, accidents, measurements of pipe, mud material used each day (both bulk and sack), diesel inventory, complete bit information, bulk cement used each day, and tests and properties of drilling fluids each tour.  Contractor shall also furnish such additional data as may be reasonably required by Operator.

7.2Accident Reports

Contractor shall notify Operator promptly of and report all accidents and/or occupational illnesses on a written report, as soon as possible following any accident resulting in injury and/or occupational illness or death to any member of Contractor Group, during the Work hereunder.

ARTICLE VIII
LIABILITY AND INDEMNIFICATION

8.1Indemnity Definitions

In this Drilling Contract, specifically including this Article VIII:

(a)“Claim” or “Claims” means, unless specifically provided otherwise, all claims (including those on account of loss of or damage to property, bodily injury, personal injury, illness, disease, maintenance, cure, loss of consortium (parental or spousal), loss of support, death, and wrongful termination of employment), damages, liabilities, losses, demands, liens, encumbrances, causes of action of any kind or nature (including actions in rem or in personam), obligations, costs, expenses, judgments, interest and awards (including payment of attorneys’ fees and costs of litigation) or amounts, of any kind or character (excluding any fines and penalties), whether created by law (including statute), contract, tort, voluntary settlement or otherwise, or under judicial proceedings, administrative proceedings or otherwise, or conditions in the premises of or attributable to any person or persons or any party or parties, regardless of fault.

(b)The phrase “regardless of fault” means without regard to cause and notwithstanding:

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(i)any tort, including negligence of any degree or character (whether sole, joint, concurrent, comparative, contributory, active, or passive), Gross Negligence, strict liability, Willful Misconduct, or other fault or any other theory of legal liability of the Party seeking indemnity (or exclusion of liability as the case may be) or any other Person;

(ii)pre-existing defect or condition, whether patent or latent, of the premises of Operator or Contractor, of the Rig, Contractor’s Items or Operator’s Items;

(iii)the unseaworthiness of the Rig or any vessel or unairworthiness of any aircraft of a Party whether chartered, owned, or otherwise provided by the Party or other Person seeking indemnity (or exclusion or limitation of liability, as the case may be) or by any other Person; or

(iv)breach of contract (including core or fundamental breach of contract, including this Drilling Contract) or quasi-contract, misrepresentation (other than fraudulent misrepresentation), breach of warranty (express or implied), breach of duty (whether statutory, contractual or otherwise), or any other theory of liability, breach of any laws, regulations, rules or orders of any government or other authority having jurisdiction, or otherwise, on the part of the Party or other Person seeking indemnity (or exclusion or limitation of liability, as the case may be) or of any other Person.

(c)Notwithstanding anything to the contrary in this Drilling Contract, the indemnities, obligations, and allocation of risks and liabilities contained in this Article VIII, as well as in Section 13.4 and Section 17.2, shall not apply in respect of any Claim to the extent such Claim is caused by the Willful Misconduct of the Party or other Person seeking to be protected, defended, indemnified, released, held harmless and/or compensated pursuant to the provisions hereof.

8.2Indemnity Obligation

(a)The indemnities, obligations, and allocation of risks and liabilities contained in this Article VIII, as well as in Section 13.4 and Section 17.2, shall exclusively govern the allocation of risks and liabilities of the Parties and shall control, notwithstanding any other provision contained elsewhere in this Drilling Contract, regardless of fault unless otherwise specifically stated.

(b)A Party’s responsibilities, obligations, and liabilities for the indemnities, obligations, and allocation of risks and liabilities contained in this Article VIII, as

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

well as in Section 13.4 and Section 17.2, shall also extend to actions in rem or in personam.

(c)The indemnities, obligations, and allocation of risks and liabilities contained in this Article VIII, as well as in Section 13.4 and Section 17.2, are effective to the maximum extent permitted by law, even if such indemnity obligation is held to be invalid or unenforceable, such holding shall not affect the remaining indemnity obligations between the Parties.

(d)Each Party agrees to promptly notify the other Party after receipt of any Claim for which it may seek indemnification.

(e)The indemnities, obligations, and allocation of risks and liabilities contained in this Article VIII, as well as in Section 13.4 and Section 17.2, shall be applicable only in respect of the Claims directly or indirectly arising out of, incident to or in connection with this Drilling Contract, the performance, defective performance or non-performance of the Work (including without limitation Work involving ingress and egress, loading and unloading, presence on any platform, vessel, aircraft or other premises leased, chartered, owned, provided or rented by any Party), or any obligation under this Drilling Contract.

(f)Notwithstanding anything in Section 8.2(e), but without prejudice to and subject to Sections 8.4(c), 8.4(d)(i), and 8.4(d)(ii), the indemnities and obligations of Operator contained in Section 8.7 and Section 8.8(b) shall not apply to any Claims directly or indirectly arising out of, incident to, or in connection with an allision or collision between any of Contractor’s Items and any platform, vessel, premises or property not leased, chartered, owned, rented or otherwise provided by Operator.  The limitation on Operator’s indemnities and obligations set forth in the preceding sentence shall not apply to (i) any such Claims directly or indirectly arising out of, incident to, or in connection with any such allision or collision that occurs when the Rig is drilling a Designated Well or is otherwise over or performing Work on Operator’s wells or facilities, or (ii) any contamination or pollution emanating from a Designated Well.

8.3Loss of or Damage to Contractor’s Rig and Equipment

Subject to Section 8.4 below, Contractor shall assume liability at all times for any loss or destruction of, or damage to, the property of Contractor Group and Contractor’s Items (including the Rig, and Contractor Group’s in-hole equipment when such equipment is above the rotary table) and shall protect, defend, indemnify, release and hold harmless Operator Group from and against all Claims for any such damage, loss or destruction, regardless of fault; provided, however, that Contractor’s obligation to indemnify and hold harmless Operator’s other contractors providing helicopter services from and against all Claims for any loss or destruction of, or damage to, the property of

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Contractor Group shall exclude such Claims to the extent caused by the negligence or fault of such helicopter service providers (except where Operator’s contract with its helicopter service provider requires Operator to indemnify such helicopter service provider for any loss or destruction of, or damage to, the property of Contractor Group, then the full terms of the indemnity in this Section 8.3 shall apply).

8.4Loss of or Damage to Contractor’s In-Hole and Subsea Equipment

(a)In-Hole Equipment.  Operator shall assume liability for any loss or destruction of, or damage to, Contractor’s Items while below the rotary table, not including normal wear and tear, and regardless of fault (but except to the extent caused by the sole negligence, Gross Negligence or Willful Misconduct of any member of Contractor Group), Operator shall be responsible for all losses which are not reimbursable by Contractor’s insurance or warranty, including the applicable deductible.  For any such loss or destruction of, or damage to, Contractor’s in-hole equipment while below the rotary table during the performance of the Work, which shall include damage caused by exposure to highly corrosive, abrasive or other destructive elements, including those introduced into the drilling fluid, Operator agrees to be responsible for the lowest amount of (i) the actual repair cost, (ii) the actual replacement cost (less depreciation), or (iii) reimbursement of Contractor at current replacement cost (less depreciation) FOB the Rig or other location designated by Contractor at no greater shipping/handling cost, as follows: (x) for drill pipe, at the rate of one and one-half percent (1.5%) per month of use during the term hereof; (y) for heaviwate, drill collars and subs, at two and one-half percent (2.5%) per month of use during the term hereof, (z) with maximum allowable depreciation of twenty-five percent (25%) for items (x) and (y) and maximum depreciation of zero percent (0%) for fishing and other in-hole equipment; and depreciation will commence on the date of first use when new, subject to a credit for insurance and warranty proceeds actually received by Contractor in respect of such in-hole equipment.

(b)Subsea Equipment.

(i)In the event of any loss or destruction of, or damage to, Contractor’s subsea equipment while below the water line during the performance of the Work (including blowout preventers, risers and riser accessories, and tensioner wires), not including normal wear and tear, and regardless of fault (but except to the extent caused by the sole negligence, Gross Negligence or Willful Misconduct of any member of Contractor Group), Operator shall be responsible for all losses which are not reimbursable by Contractor’s insurance or warranty, including the applicable deductible.  Except as provided in Section 8.4(b)(ii), upon the occurrence of any loss or damage described in this Section 8.4(b), Operator shall pay the Standby Rate in each case up to a maximum of

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

thirty (30) days per occurrence, after which the Zero Rate shall apply until the Rig is in condition to continue the Work.

(ii)In the event of any loss or destruction of, or damage to, a BOP while below the water line during the performance of the Work, not including normal wear and tear, and regardless of fault (but except to the extent caused by the sole negligence, Gross Negligence or Willful Misconduct of any member of Contractor Group) then the Standby Rate shall apply to the period from the time at which the Work is stopped hereunder in preparation to pull and retrieve the BOP, including the time needed to secure any Designated Well in progress, until the time that the second BOP is deployed and the point where such Work or drilling was stopped is reached again and operations resumed, at which time the Standby Rate shall continue to apply.  If, for any reason, the second BOP is not fully operational or fails any test or inspection prior to the time such Work or drilling is resumed, then Contractor shall be entitled to any repair allowances provided in Appendix I, Section B(2)(C), after which the Zero Rate shall apply until the second BOP is restored to a fully operational and Compliant condition, deployed, and the point where such Work or drilling was stopped is reached again and operations resumed.  The Operating Rate shall not apply until the lost, destroyed, or damaged BOP has been replaced or restored and the Rig is again equipped with two (2) fully operational and Compliant BOPs.

(c)Notwithstanding anything in Section 8.4(a), Operator’s liability in respect of any loss or destruction of, or damage to, Contractor’s in-hole equipment under Section 8.4(a) shall be limited to Ten Million Dollars ($10,000,000) per event.  Notwithstanding anything in Section 8.4(b), Operator’s liability in respect of any loss or destruction of, or damage to, Contractor’s subsea equipment under Section 8.4(b) shall be limited to Thirty Five Million Dollars ($35,000,000) per event.

(d)Notwithstanding anything in Section 8.4(b) and Section 8.4(c),

(i)should Operator provide written request to Contractor to keep Contractor’s subsea equipment deployed while the Rig is being moved from one well location to another, then Operator shall reimburse Contractor at replacement cost (less depreciation) for such equipment delivered to the Rig, or the repair cost, whichever is the lesser amount, for any damage to Contractor’s subsea equipment that results, regardless of fault.  In addition, the Standby Rate shall apply with respect to any delays in the Work that may occur or result from such damage.  In the event that Contractor, without Operator’s written request, keeps Contractor’s subsea equipment deployed while the Rig is being moved from one well location to another, then Contractor assumes sole responsibility and liability for

41

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

any damage to Contractor’s subsea equipment that results therefrom, regardless of fault.  In addition, the Zero Rate shall apply with respect to any delays in the Work that may occur or result from such damage;

(ii)should Operator provide written request to Contractor to keep Contractor’s subsea equipment deployed and to drift into location due to environmental conditions, then Operator shall reimburse Contractor at replacement cost (less depreciation) for such equipment delivered to the Rig, or the repair cost, whichever is the lesser amount, for any damage to Contractor’s subsea equipment that results due to contact with the sea floor or any object or obstruction or if normal operating parameters are exceeded, regardless of fault.  In addition, the Standby Rate shall apply with respect to any delays in the Work that may occur or result from such damage.  In the event that Contractor, without Operator’s written request, keeps Contractor’s subsea equipment deployed and drifts into location due to environmental conditions, then Contractor assumes sole responsibility and liability for any damage to Contractor’s subsea equipment that results, regardless of fault.  In addition, the Zero Rate shall apply with respect to any delays in the Work that may occur or result from such damage; and

(iii)it is acknowledged that Contractor’s operating practices require the BOP stack to be set at one (1) degree or less from the vertical to avoid abnormal wear and damage.  Thus, in the event that the stack angle exceeds one (1) degree from vertical, and Operator instructs Contractor to continue the Work, Operator agrees to assume all responsibility for the full cost to repair or replace any damage which may result therefrom, regardless of fault.  Operator shall reimburse Contractor for the full cost to repair or replace such subsea equipment delivered to the Rig less an allowance for depreciation of five percent (5%) per annum from the date placed in service of Contractor’s original purchase price.  In addition, the Standby Rate shall apply with respect to any repair downtime that may occur or result from such damage.

8.5Loss of or Damage to Operator’s Items

Operator shall assume liability at all times for any loss or destruction of, or damage to, property and equipment of Operator Group and Operator’s Items, including any platform, pipelines, cables, subsea wells, and umbilicals or other structure of Operator Group, and shall protect, defend, indemnify, release and hold harmless Contractor Group and Builder from and against all Claims for any such damage, loss or destruction, regardless of fault.

42

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

8.6Loss of or Damage of the Hole

In the event of loss of or damage to the hole or the well, or in the event any well being drilled by Contractor under this Drilling Contract shall blowout or crater from any cause whatsoever, by whomsoever, during the Work, Operator shall bear the entire cost and expense of killing the well or otherwise bringing the well under control, including relief wells (“Well Control Costs”), and also shall protect, defend, indemnify, release and hold harmless Contractor Group for all Claims for Well Control Costs and loss or damage to the hole, including without limitation, the casing therein, regardless of fault, provided that, if loss of or damage to the hole results from the sole negligence or Gross Negligence of any member of Contractor Group, Contractor shall, at the request of Operator, as Operator’s exclusive remedy (in addition only to Operator’s rights under Section 6.13), re-drill the same or an equivalent hole to such depth as such lost hole had been drilled at the time the loss or damage occurred or repair the hole to the same condition prior to such damage, or drill a relief well if required, at the day rate of [***]; provided, further, that if loss of or damage to the hole results from the Willful Misconduct of any Senior Supervisory Personnel, Contractor shall, at the request of Operator, as Operator’s exclusive remedy (in addition only to Operator’s rights under Section 6.13), re-drill the same or an equivalent hole to such depth as such lost hole had been drilled at the time the loss or damage occurred, repair the hole to the same condition prior to such damage, or drill a relief well if required, in each case, at the day rate of [***].

8.7Liability for Underground Damage

Operator assumes all liability for and shall protect, defend, indemnify, release and hold harmless Contractor Group from and against all Claims, including Claims of Third Parties, for the loss of or damage to any geological formation, strata, or oil, gas or other reservoirs beneath the surface of the earth, which shall also include the loss of any such oil, gas or other substance which escapes above or below the surface, regardless of fault.

8.8Pollution Liability and Oilfield Waste Handling Procedure

(a)Contractor.  Contractor shall assume all responsibility for and shall protect, defend, indemnify, release and hold harmless Operator Group from and against all Claims, including Claims of Third Parties, regardless of fault (including Claims for the cost of control, clean-up, removal, restoration and remediation) caused by contamination (including radioactive contamination) or pollution, including fines or penalties directly assessed against Contractor and levied by any Governmental Authority, from the discharge, dispersal, release or escape of any pollutants, including waste oil or other petroleum substance or derivative (including any waste oil, refuse, or waste oil mixed with water), pipe dope, paints, solvents, ballasts, bilge, garbage, sewage, hazardous waste, solid waste, disposal, release or escape of oil emulsion, oil based or chemically treated drilling fluids, contaminated cuttings (excluding such cuttings disposed at Operator’s direction), lost circulation and fish recovery materials and fluids in the

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

possession and control of any member of Contractor Group including, mud returns after the drilling solids treatment equipment, and other such materials, the discharge of which (i) originated above or below the surface of the water and (ii) immediately prior to the discharge the pollutant was in the possession or control of any member of Contractor Group and/or emanated or originated from the Rig (excepting the Rig’s subsea equipment).

The assumptions of liability by Contractor under this Section 8.8(a) do not apply to loss or destruction of, or damage to, the property of, or injuries to or death of, any member of Contractor Group or Operator Group caused by such contamination or pollution, and shall, in no event, alter, lessen, or affect the liabilities or responsibilities of Contractor specified in Sections 8.3, 8.4, 8.9, 8.12 and 8.14 herein.

(b)Operator.  Except with respect to the liabilities assumed by Contractor under Section 8.8(a), Operator shall assume all responsibility for and shall protect, indemnify, defend, release and hold harmless Contractor Group from and against all Claims, including Claims of Third Parties, regardless of fault, (including Claims for the cost of control, clean-up, removal, restoration and remediation) caused by contamination (including radioactive contamination) or pollution, including fines or penalties directly assessed against Operator and levied by any Governmental Authority, from:

(i)the discharge, disposal, release or escape of oil emulsion, oil based or chemically treated drilling fluids, contaminated cuttings, lost circulation and fish recovery materials and fluids not in the possession and control of any member of Contractor Group, including mud returns before the drilling solids treatment equipment; and

(ii)fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas, water or other substance emanating from a well or a reservoir.

The assumptions of liability by Operator under this Section 8.8(b) do not apply to loss or destruction of, or damage to, the property of, or injuries to or death of, any member of Operator Group or Contractor Group caused by such contamination or pollution, and shall, in no event, alter, lessen, or affect the liabilities or responsibilities of Operator specified in Sections 8.4, 8.5, 8.6, 8.7, 8.10 and 8.14 herein.

(c)Operator’s Participation

Without relieving Contractor of any of its obligations herein provided, the Parties agree that Operator may take part, to any extent it deems necessary, in the control and removal of any contamination or pollution which is the responsibility of Contractor under the foregoing provisions; and Contractor shall reimburse

44

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Operator for the reasonable and customary documented cost thereof, subject to any limitation above provided, within thirty (30) days of receipt of a statement from Operator.

(d)Oilfield Waste Handling Procedure

Contractor shall comply with all applicable laws, rules and regulations regarding the handling of oilfield waste for which it is responsible pursuant to the HSSE Bridging Agreement.  Contractor shall be responsible for used engine oil, oil filters, empty drums and hazardous waste generated by its operations, including without limitation, the proper handling of the used oil and the manifesting, reclaiming/recycling or disposal of the oil.  The oil is to be transported in U.S. Coast Guard approved containers, not in used drums.  Used drums are to be empty per specifications of the U.S. Department of Transportation, properly labeled, and have bungs in place prior to shipping to shore.  Contractor will pick up and properly recycle or dispose of the empty drums.  Oil filters, after being totally and properly drained, shall be disposed of as trash.  Without prejudice to this Section 8.8, including without limitation, Operator’s indemnity obligation in Section 8.8(b) above, Contractor shall release, defend, indemnify and hold harmless Operator Group from any penalties or fines directly assessed against Contractor resulting from Contractor’s failure to comply with the obligations it has expressly assumed in this Section 8.8(d).  Except as expressly assumed by Contractor in this Section 8.8(d), Operator assumes sole responsibility for the transport and disposal of all other waste as required in the HSSE Bridging Agreement, and Operator shall defend, indemnify and hold harmless Contractor Group from and against any penalties or fines directly assessed against Operator resulting from Operator’s failure to comply with its obligations in this Section 8.8(d).  Notwithstanding anything to the contrary set forth elsewhere in this Drilling Contract, Contractor shall be solely responsible for obtaining coverage (including, but not limited to, submitting the Notice of Intent (“NOI”) and supplemental NOI) and complying with all applicable requirements of the National Pollutant Discharge Elimination System permit, including but not limited to all regulated discharges from the Rig such as the cooling water intake structure, maintenance wastes such as blasting and painting, deck drainage and domestic/consumer waste.

8.9Contractor Indemnification — Personnel

Contractor shall protect, defend, indemnify, release and hold harmless Operator Group from and against all Claims for bodily injury, illness, disease, or death of any member of Contractor Group, regardless of fault; provided, however, that Contractor’s obligation to indemnify and hold harmless Operator’s other contractors providing helicopter services from and against all Claims for any loss or destruction of, or damage to, the property of Contractor Group shall exclude such Claims to the extent caused by the negligence or fault of such helicopter service providers (except where Operator’s

45

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

contract with its helicopter service provider requires Operator to indemnify such helicopter service provider for any loss or destruction of, or damage to, the property of Contractor Group, then the full terms of the indemnity in this Section 8.9 shall apply).

8.10Operator Indemnification — Personnel

Operator shall protect, defend, indemnify, release and hold harmless Contractor Group and Builder from and against all Claims for bodily injury, illness, disease, or death of any member of Operator Group, regardless of fault.

8.11Personnel and Property of Third Parties

(a)Subject to Sections 8.7, 8.8 and 8.15, Contractor shall protect, defend, indemnify, release and hold harmless Operator Group from and against all Claims (including those for bodily injury, personal injury, illness, disease, maintenance, cure, loss of consortium, loss of support, death, property damage, and wrongful termination of employment) by or in favor of or incurred or sustained by any Third Party, directly or indirectly arising out of, or incident to or in connection with this Drilling Contract, or the performance or non-performance of the Work (including without limitation Work involving ingress and egress, loading and unloading, presence on any platform, vessel, aircraft or other premises leased, chartered, owned, provided or rented by any Party), or any obligation under this Drilling Contract, to the extent such Claim is the result of the negligence (whether sole, joint, or concurrent), Gross Negligence, strict liability, Willful Misconduct, or other legal fault or breach of legal duty of any member of Contractor Group.

(b)Subject to Sections 8.7, 8.8 and 8.15, Operator shall protect, defend, indemnify, release and hold harmless Contractor Group from and against all Claims (including those for bodily injury, personal injury, illness, disease, maintenance, cure, loss of consortium, loss of support, death, property damage, and wrongful termination of employment) by or in favor of or incurred or sustained by any Third Party, directly or indirectly arising out of, or incident to or in connection with this Drilling Contract, or the performance or non-performance of the Work (including without limitation Work involving ingress and egress, loading and unloading, presence on any platform, vessel, aircraft or other premises leased, chartered, owned, provided or rented by any Party), or any obligation under this Drilling Contract, to the extent such Claim is the result of the negligence (whether sole, joint, or concurrent), Gross Negligence, strict liability, Willful Misconduct, or other legal fault or breach of legal duty of any member of Operator Group.

46

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

8.12Gross Negligence

Notwithstanding anything in this Drilling Contract to the contrary, where Operator is required to protect, defend, indemnify, release and hold harmless Contractor Group from and against any Claims pursuant to the provisions of Sections 8.6 and/or 8.8(b), Contractor shall be responsible for and protect, defend, indemnify, release and hold harmless Operator Group from and against all such Claims to the extent caused by the Gross Negligence of any member of Contractor Group, up to a total amount of Fifty Million Dollars ($50,000,000) in the annual aggregate (and including, in relation to Claims pursuant to the provisions of Section 8.6, an amount equal to (x) the difference between the Operating Rate and the reduced day rate set out in Section 8.6, multiplied by (y) the number of days in respect of Section 8.6 applied in the event of such Gross Negligence).

8.13Consequential Damages

Notwithstanding anything in this Drilling Contract to the contrary (excepting Section 8.1(c)), each Party shall at all times be responsible for and protect, defend, indemnify, release, and hold harmless the other Party from and against the Party’s own (and its respective Group’s) Consequential Damages suffered in connection with this Drilling Contract, regardless of fault.  “Consequential Damages” means (i) special, indirect or consequential losses and damages, and (ii) whether direct or indirect, any and all loss and/or deferral or diminution of or the benefit of profit or revenue; loss of profit or revenue resulting from business interruptions; overheads, loss of or delay in production; loss of or damage to the leasehold, concession, production sharing contract or other similar rights; loss of or delay in drilling or operating rights; Operator’s spread costs (including hire and other charges payable to owners of vessels or suppliers of equipment or services and the costs of keeping vessels and equipment on location); or the cost of hiring a replacement rig; in each case whether or not foreseeable or disclosed at inception of this Drilling Contract; provided always that Consequential Damages shall never be construed as including (x) compensation due and payable to Contractor pursuant to this Drilling Contract, including termination payments pursuant to Section 13.3, and (y) any damages suffered or incurred by Operator arising or resulting from Contractor’s breach in repudiation of this Drilling Contract to contract the Rig with another customer.

8.14Debris and Wreck Removal

Contractor shall promptly remove all debris and/or wreckage of the Rig or other Contractor’s Items to the extent compulsorily required by legally constituted authority.  Contractor shall protect, defend, indemnify, release and hold harmless Operator Group for the costs of removal of such debris and/or wreckage and from and against Claims arising out of Contractor’s obligation to remove said debris and/or wreckage as described above, regardless of fault.

If any debris and/or wreckage of the Rig is not compulsorily required by legally constituted authority, but constitutes an impediment or interference to any operations of Operator (in Operator’s sole reasonable opinion), then Contractor shall remove such

47

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

debris and/or wreckage at Operator’s written request.  In the event of such request, Contractor’s responsibility and liability shall not in any event exceed Fifty Million Dollars ($50,000,000), and Operator shall be responsible for and shall protect, defend, indemnify, release and hold harmless Contractor Group from and against all Claims arising out of the removal of any such debris and/or wreckage of the Rig in excess of such amount.

8.15Patent Infringement

(a)Contractor hereby represents to Operator Group that any and all tools, equipment, and services which may be used, constructed, or provided by Contractor Group hereunder, do not, to the best of Contractor’s knowledge, infringe any patent, copyright, or trademark or misappropriate any trade secrets, and with respect to any such tools, equipment, and services which are used, constructed, or so provided, Contractor shall protect, defend, indemnify, release and hold harmless Operator Group from and against any and all Claims, made by a claimant with regard thereto.  Operator hereby represents to Contractor Group that any and all tools, equipment, and services which may be used, constructed, or provided by Operator Group hereunder, do not, to the best of Operator’s knowledge, infringe any patent, copyright, or trademark or misappropriate any trade secrets, and with respect to any such tools, equipment, and services which are used, constructed, or so provided, Operator shall protect, defend, indemnify, release and hold harmless Contractor Group from and against any and all Claims, made by a claimant with regard thereto.

(b)The Rig to be provided pursuant to this Drilling Contract will have a primary and an auxiliary drill center.  Operator acknowledges that some potential uses of two drill centers may relate to the claims of Transocean’s United States Patent Nos. 6,085,851, 6,068,069, 6,056,071, and 6,047,781 and related Transocean patents in other jurisdictions (“Transocean’s dual-activity patents”).  Notwithstanding any provision to the contrary, Contractor will not deliver the Rig to Operator in a condition that would infringe the valid and enforceable claims of Transocean’s dual-activity patents, if any, in effect in the jurisdiction(s) in which the Rig is contracted to Work, unless Contractor obtains a license from Transocean to operate in such jurisdiction(s), as described further below.  Operator acknowledges that it may be necessary to install a “casing sleeve” in the auxiliary drill center or otherwise limit the capabilities of the Rig in order to avoid the coverage of Transocean’s dual-activity patents in the jurisdiction(s) in which the Rig is contracted to perform the Work, and that such casing sleeve or other limitations may be required to remain in place during certain operations unless the Work is performed in a jurisdiction which is not covered by Transocean’s dual-activity patents or where Transocean’s dual-activity patents are no longer in force.  In the event that Operator desires to receive the Rig or use the Rig in a manner that would infringe upon Transocean’s dual-activity patents, Operator understands that it will be required to obtain a license from Transocean, and the Parties will

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

use commercially reasonable efforts to obtain such license.  If Operator desires Contractor to enable the dual activity capability of the Rig, such dual activity shall only be enabled on the basis of the Parties entering into a written agreement that provides for the payment by Operator of (i) all costs incurred to enable the dual activity and (ii) all on-going royalties payable by Contractor under the patent license agreement from and after the date that such dual activity is activated, regardless of whether or not Operator discontinues the use of the dual activity after it is enabled.  For the purpose of this Drilling Contract, “dual activity” shall be defined as a rig that has a derrick or superstructure supporting two well centers, both of which are capable of running tubulars to the seabed.

8.16Right to Participate in Defense

The indemnifying Party shall, at its sole cost and expense, investigate, handle, respond to and provide defense for any Claim for which it gives indemnity herein, provided that, at its expense, the Party being indemnified shall be afforded the right and opportunity to participate in any such investigation, defense or litigation regarding a Claim for which it is indemnified through counsel of its own choosing.

8.17Attorneys’ Fees to Enforce Contract

In the event a Party, after receipt of notice of a Claim, fails to furnish a defense and indemnity as provided for herein or in the event either Party breaches an obligation in this Drilling Contract, the other Party shall be entitled to receive from the offending Party reasonable attorneys’ fees, costs, and expenses incurred in the enforcement of this Drilling Contract, including Claims for contractual indemnity and insurance coverage.

8.18Taxes

(a)Except as provided herein, each Party shall be responsible for any taxes imposed on such Party by any Governmental Authority.

(b)If Operator requests Contractor to perform Work in state or territorial waters, other than as contemplated by this Drilling Contract, Operator shall assume all responsibility for and shall protect, defend, indemnify, release and hold harmless Contractor Group and the Rig from and against all Claims for any State, County or Parish, and/or other municipal or local tax or similar levy and attendant costs and expenses which may be applicable to or arise from operations or revenues earned by Contractor under this Drilling Contract, including the Rig and other Contractor’s Items; provided, however, that Contractor shall take all commercially reasonable steps to minimize any such taxes, and any reimbursement, indemnification or other payment made by Operator pursuant to this Section 8.18(b) shall be reduced to the extent that such Claim would result in a tax benefit to Contractor.  Contractor shall notify Operator if (i) Contractor anticipates that a request made by Operator will result in taxes (and the extent of

49

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

such taxes) described in the preceding sentence, or (ii) any member of Contractor Group receives a notice from any Governmental Authority with regard to any such taxes.  Contractor shall cooperate fully with Operator and Operator’s representatives at Operator’s expense should Operator choose to contest any such tax or levy.

(c)Except as otherwise provided in Section 3.3(c)(i) and Section 8.18(b), Contractor shall assume all responsibility for and shall protect, defend, indemnify, release and hold harmless Operator Group from and against all Claims relating to:

(i)all taxes, duties, levies, charges and contributions (and any interest or penalties thereon) for which Contractor (or any subcontractor or any other Person employed by Contractor or providing services relating to or in connection with this Drilling Contract to Contractor) is liable as imposed by any Governmental Authority; and

(ii)any statutory obligation imposed on Contractor (or any subcontractor or any other Person employed by Contractor or providing services relating to or in connection with this Drilling Contract to Contractor) to make deductions on account of tax and remit the required amounts to any Governmental Authority, including, but not limited to, income tax, national insurance, employee taxes, charges, social security costs, levies and contributions, whether or not they are measured by the wages, salaries or other remuneration or benefits paid to Persons employed by Contractor or providing services relating to or in connection with this Drilling Contract to Contractor.

(d)Operator shall assume all responsibility for and shall protect, defend, indemnify, release and hold harmless Contractor Group from and against all Claims relating to:

(i)all taxes, duties, levies, charges and contributions (and any interest or penalties thereon) for which Operator (or any subcontractor or any other Person employed by Operator or providing services relating to or in connection with this Drilling Contract to Operator, excluding any member of Contractor Group) is liable as imposed by any Governmental Authority; and

(ii)any statutory obligation imposed on Operator (or any subcontractor or any other Person employed by Operator or providing services relating to or in connection with this Drilling Contract to Operator, excluding any member of Contractor Group) to make deductions on account of tax and remit the required amounts to any Governmental Authority, including, but not limited to, income tax, national insurance, employee taxes, charges, social

50

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

security costs, levies and contributions, whether or not they are measured by the wages, salaries or other remuneration or benefits paid to Persons (excluding any member of Contractor Group) employed by Operator or providing services relating to or in connection with this Drilling Contract to Operator.

8.19Liens

Contractor shall keep Operator’s Items, the well(s), licenses and interest therein or production therefrom and the Work free and clear of all liens, claims, assessments, fines and levies created or committed by Contractor or by subcontractors or contractors of Contractor; provided that Operator makes payments of all liquidated and undisputed amounts due Contractor in accordance with Article IV (failing which Contractor may have the right to assert a lien against Operator’s Items, the well(s), licenses or interests therein or production therefrom or the Work, but only to the extent of any liquidated and undisputed amounts then past-due and payable by Operator hereunder).  Operator may, subject to the prior written approval of Contractor, post on Contractor’s Items such notices as Operator and Contractor may mutually agree in order to ensure the reasonable protection of Operator against any liens, claims, assessments, fines and/or levies upon Operator’s assets.  In the event any such liens are improperly filed by Contractor, its subcontractor or contractors against Operator or any of its wells, property or equipment, Contractor shall assume all responsibility for and shall protect, defend, indemnify, release and hold harmless Operator Group from and against all Claims relating thereto.

ARTICLE IX
INSURANCE

9.1Contractor’s Insurance

To support its indemnification obligations in this Drilling Contract, but as a separate and independent obligation, Contractor agrees to procure and maintain throughout the term of this Drilling Contract, at its sole cost and expense, insurance coverages of the type and in the amounts (through insurance, including self-insured retentions and/or deductibles in reasonable amounts consistent with customary industry practice) set forth in Appendix E, Part A.

9.2Certificates

Contractor will furnish Operator, on request, with certificates indicating that the required insurance is in full force and effect and that the same shall not be cancelled or materially and adversely changed without thirty (30) days prior written notice to Operator (seven (7) days for cancellation due to war risk).

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

9.3Insurance in Support of Mutual Indemnity Obligations

(a)The indemnity obligations of Contractor, as set out in this Drilling Contract, are independent of any insurance requirements as set out in Article IX and Appendix E, Part A, and such indemnity obligations shall not be lessened or extinguished by reason of Contractor’s failure to obtain the required insurance coverage or by any defenses asserted by Contractor’s insurers.  Moreover, the indemnity obligations of Operator, as set out in this Drilling Contract, are independent of any insurance requirements as set out in Article IX and Appendix E, Part B, and such indemnity obligations shall not be lessened or extinguished by reason of Operator’s failure to obtain the required insurance coverage or by any defenses asserted by Operator’s insurers.

(b)In the event that this Drilling Contract is interpreted under the laws of the State of Texas for a particular occurrence, then Article VIII shall apply, but for the purposes of Title 6, Chapter 127 of the Texas Civil Practice and Remedies Code, commonly known as the Texas Oilfield Anti-Indemnity Act, the indemnity and insurance provisions of this Drilling Contract applicable to property damage and the indemnity and insurance provisions applicable to personal injury, bodily injury, and death shall be deemed separate for interpretation, enforcement, and other purposes.  If the laws of the State of Texas govern this Drilling Contract, then the Parties incorporate Title 6, Chapter 127 of the Texas Civil Practice and Remedies Code, and agree to the limits of that statute.

(c)In the event that this Drilling Contract is interpreted under the laws of the State of Louisiana for a particular occurrence, then Article VIII shall apply, but for the purposes of LA. R.S. 9:2780, commonly known as the Louisiana Oilfield Anti-Indemnity Act, the indemnity and insurance provisions of this Drilling Contract applicable to personal injury, bodily injury, and death shall be deemed separate for interpretation, enforcement, and other purposes.  If the laws of the State of Louisiana govern this Agreement, then the Parties incorporate La. R.S. 9:2780 and agree to the limits of that statute.

9.4Subcontractors

Contractor shall use all commercially reasonable efforts to cause its subcontractors to obtain, maintain and keep in force during the time in which they are performing services hereunder, insurance deemed necessary to cover the Work, and furnish Operator evidence of such insurance coverage upon request.

9.5Failure to Provide Insurance

In the event a Party fails to obtain or maintain any insurance that it is obligated to provide hereunder, said Party shall nevertheless bear all responsibility for liabilities and losses it assumes under this Drilling Contract.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

9.6Financial Responsibility

Contractor shall maintain, throughout the term of this Drilling Contract, evidence of financial responsibility as may be required by any applicable law or regulation relating to drillship operations in the U.S. Gulf of Mexico, including the U.S. Outer Continental Shelf Lands Act (as same may be amended from time to time), and the U.S. Oil Pollution Act of 1990 (as same may be amended from time to time).

9.7Operator Insurance

To support its indemnification obligations in this Drilling Contract, but as a separate and independent obligation, Operator agrees to procure and maintain throughout the term of this Drilling Contract, at its sole cost and expense, insurance coverages of the type and in the amounts (through insurance, including self-insured retentions and/or deductibles in reasonable amounts consistent with customary industry practice) set forth in Appendix E, Part B.  Certificates of insurance evidencing the required insurance of Operator shall be provided to Contractor, on request.

ARTICLE X
INDEPENDENT CONTRACTOR

10.1It is expressly understood that Contractor is an independent contractor and neither Contractor, its contractors or subcontractors, nor any of their respective employees, representatives, or agents, are or shall be employees, representatives, or agents of Operator.  The actual performance and superintendence of all Work hereunder shall be by Contractor, under the control and direction of Contractor, as to the details of the Work and Contractor shall take responsibility for the adequacy, stability and safety of all of its operations and methods necessary for the performance of the Work; provided, however, that Operator, being interested in the results to be obtained, is authorized to designate a representative or representatives who shall at all times have access to the Rig and related equipment for the purposes of observing tests or inspecting the Work performed hereunder by Contractor in furtherance of its interest.

ARTICLE XI
GOVERNING LAW AND DISPUTE RESOLUTION

11.1This Drilling Contract (and all non-contractual obligations which may arise out of or in connection with it) shall be governed by and construed in accordance with the laws of England, not including any of its conflicts of law rules that would direct or refer to the laws of another jurisdiction.  The Parties have allocated liability risk pursuant to this Drilling Contract and therefore intend and agree that no anti-indemnity law, rule or regulation apply hereto.

11.2In the event of a dispute between the Parties hereto, including a commercial dispute or a dispute connected with a personal injury or property damage claim, disputes as to its existence, validity or termination or the consequences of its nullity, and disputes relating

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

to non-contractual obligations, arising out of or relating to this Drilling Contract, or the breach thereof, then:

(a)the Parties agree that Operator’s Chief Operating Officer and Contractor’s President or Chief Operating Officer, or their respective designees, will promptly consult and negotiate with each other and, recognizing their mutual interests, attempt to reach a prompt, just and equitable resolution satisfactory to the Parties;

(b)if no resolution satisfactory to the Parties has been reached within three (3) business days, either Party may make a written demand to submit the dispute to non-binding mediation.  Such mediation shall be conducted at Houston, Texas, in an expedited manner by a mediator jointly appointed and agreed to by the Parties; and

(c)in the event the Parties are unable to resolve their dispute through mediation pursuant to Section 11.2(b), within thirty (30) days from the failure to reach a satisfactory resolution pursuant to Section 11.2(a), such dispute shall be settled exclusively and finally by arbitration under the Arbitration Rules of the London Court of International Arbitration (“LCIA”) current at the time when the arbitration proceedings are commenced, which rules are deemed to be incorporated by reference into this Article XI.  There shall be three (3) arbitrators, one nominated by the claimant Party, one nominated by the respondent Party within fourteen (14) days of the claimant Party’s nomination, and one nominated by the two Party-nominated arbitrators.  If the two arbitrators fail to agree on the nomination of the third arbitrator within ten (10) days of the nomination of the respondent Party’s arbitrator, the LCIA Court shall make such appointment only.  The inclusion of such nomination mechanism shall not exclude the powers of the LCIA Court under Article 9 of the LCIA Rules.  Article 13.1 of the LCIA Rules shall be disapplied to the extent that each Party may communicate (without copy to any other Party) with its nominated arbitrator regarding the nomination of the chairman only, up until such time as agreement is reached on the nomination of the chairman.  The seat and place of the arbitration shall be London, England.  The language to be used in the arbitration shall be English.  All arbitration notices and requests for arbitration shall be deemed properly given if sent in accordance with Section 15.1.

11.3Any award shall be final and binding on the Parties and may be confirmed in, and judgment upon the award entered by, any court having jurisdiction.

11.4Reference to specific articles of the LCIA Rules in this clause are references to the 1998 edition of such rules — should a subsequent edition of such rules be in force at the time any arbitration is commenced hereunder, then the references to specific articles should be updated mutatis mutandis to achieve the same result.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

11.5In any mediation or other legal proceeding arising out of or relating to this Drilling Contract, each Party agrees that all exemplary and punitive damages are expressly waived, except to the extent the same may be included in any Claim by a Third Party.

ARTICLE XII
FORCE MAJEURE

12.1(a)A Party shall not be in default of its obligations hereunder to the extent its delay in performance results from an event of Force Majeure; provided that the Party affected by the Force Majeure uses all commercially reasonable efforts to: (i) proceed with its obligations under this Drilling Contract to the extent that it is not prevented from doing so by the event of Force Majeure; (ii) remove or relieve any event of Force Majeure and its consequences and minimize the effects of the delay caused thereby; and (iii) resume performance as soon as practicable after the event of Force Majeure.  The occurrence of an event of Force Majeure shall not relieve the affected Party of its obligations to mitigate the effects thereof.

(b)Each Party shall exercise reasonable diligence to overcome any Force Majeure delaying the Work herein but shall not be obligated to settle any labor dispute except on terms acceptable to it and all such disputes shall be handled within the sole discretion of the affected Party.  Notwithstanding anything to the contrary in this Drilling Contract, the Force Majeure Rate shall not be applicable until the Rig has arrived in the Area of Operations.

(c)The Force Majeure Rate shall be payable to Contractor during any period in which the Work is not being performed because of Force Majeure up to a maximum number of [***] consecutive days per occurrence.  Following the expiry of such [***] day period, the Standby Rate shall apply until the earliest of such time as (i) this Drilling Contract is terminated in accordance with Article XIII (provided that Operator shall use commercially reasonable endeavours to procure a new Area of Operations before exercising its termination right pursuant to Section 13.2(b)), or (ii) the Rig commences mobilization to a new Area of Operations in accordance with a new agreement pursuant to Section 3.2, or (iii) the Force Majeure condition is abated.

ARTICLE XIII
TERMINATION

13.1Termination Conditions for Contractor

(a)Subject to the provisions of Article IV, in the event that any liquidated and undisputed payments due by Operator are not paid when due, Contractor shall notify Operator of nonpayment and shall give Operator ten (10) days from receipt of said notice to pay amounts due with applicable interest.  In the event Operator fails to pay within the said ten (10) day period, Contractor may terminate this

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Drilling Contract by notifying Operator in writing to that effect and this Drilling Contract shall terminate fifteen (15) days after receipt of the notice unless payment with interest, of all invoices then overdue and not in dispute is received by Contractor prior to the expiration of said fifteen (15) day period.  In this instance, Contractor shall not be obligated to finish any well or Work in progress by Operator, but shall be obligated to perform such further Work as may reasonably be required to secure the well in accordance with Good Industry Practices and all applicable laws, rules and regulations, in which case, the aforesaid termination shall be effective upon completion of such Work.

(b)This Drilling Contract shall terminate upon total loss or constructive total loss of the Rig.

(c)In the event of Operator becoming bankrupt or making a composition or arrangement with its creditors, or of a winding-up order of Operator being made, or (except for the purposes of amalgamation or reconstruction) a resolution for its voluntary winding-up being passed, or a receiver or other officer with like powers being appointed for Operator or any of its properties or assets, or should any equivalent act or thing be done or suffered under any applicable laws, this Drilling Contract shall terminate.  In the event of termination under this Section 13.1(c), Contractor shall be entitled to payment of the Early Termination Fee under Section 13.3(a).

(d)Contractor shall have the right to terminate this Drilling Contract in the event of Force Majeure as provided in Section 12.1; provided that such event of Force Majeure has continued for at least [***] consecutive days; provided, further, that the right to terminate this Drilling Contract pursuant to this Section 13.1(d) shall not be available to Contractor if (i) Operator has procured a new Area of Operations to utilize the Rig at or prior to the expiration of such [***]-day period or (ii) Operator continues to pay the Standby Rate to Contractor from and after the expiration of such [***]-day period.

(e)Contractor shall have the right to terminate this Drilling Contract pursuant to Appendix E, Part B.

(f)Contractor shall have the right to terminate this Drilling Contract in the event that any of the representations and warranties of Operator in Sections 18.13(d), 18.13(e) and 18.13(f) are not true at and as of the Effective Date and the Term Commencement Date (as if made at and as of such time) which has, or would reasonably be expected to have, materially affected the ability of Operator to perform its obligations under this Drilling Contract.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

13.2Termination Conditions for Operator

Operator shall have the right to terminate this Drilling Contract, or to terminate all or any part of the Work at such time or times as Operator may consider necessary, effective upon delivery to Contractor of written notice of such termination, for any or all of the following reasons:

(a)solely to suit the convenience of Operator, to the exclusion of any of the other events hereinafter described in this Section 13.2, provided that the payments under Section 13.3(a) are delivered to Contractor;

(b)in the event of Force Majeure as provided in Section 12.1; provided that such event of Force Majeure has continued for at least [***] consecutive days and that Operator has used commercially reasonable endeavours to procure a new Area of Operations before exercising its termination right;

(c)pursuant to Section 2.2(e)(i);

(d)pursuant to Section 14.1;

(e)if any breakdown or damage to the Rig, unless caused by the sole fault or sole negligence of any member of Operator Group, results in Contractor being unable to perform the Work and its obligations hereunder for a total period of [***] days, plus reasonable transit times to and from the nearest available shipyard capable of repairing such breakdown, or more;

(f)in the event of Contractor becoming bankrupt or making a composition or arrangement with its creditors, a winding-up order of Contractor being made, (except for the purposes of amalgamation or reconstruction) a resolution for its voluntary winding-up being passed, the foreclosure upon or seizure of the Rig by creditors, or a receiver or other officer with like powers being appointed for Contractor or any of its properties or assets, or should any equivalent act or thing be done or suffered under any applicable laws;

(g)in the event that Contractor breaches any of its material obligations hereunder which has affected the safe or efficient performance of the Work and, having received written notice from Operator, Contractor fails or refuses, within seven (7) days of receiving such notice, to commence action to ensure that the matter complained of is remedied, in accordance with the provisions of this Drilling Contract, as soon as practicable or within such longer period as is reasonable in the circumstances and consistent with Good Industry Practices;

(h)pursuant to Appendix E, Part A; or

(i)in the event that any of the representations and warranties of Contractor in Sections 18.13(a), 18.13(b) and 18.13(c) are not true at and as of the Effective Date and the Term Commencement Date (as if made at and as of such time)

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

which has, or would reasonably be expected to have, materially affected (A) the ability of Contractor to perform its obligations under this Drilling Contract or (B) the ability of Novatee to perform its obligations under the Deed of Novation and this Drilling Contract.

Notwithstanding anything in this Drilling Contract to the contrary, the Parties agree that termination of this Drilling Contract shall not be effective until the Designated Well in progress at the time of Operator’s written notice of termination has been secured and demobilization of the Rig has been completed.

13.3Payments

In the event of termination in accordance with Section 13.1 or Section 13.2, Contractor and Operator, as applicable, shall be entitled to payment as follows:

(a)For termination in accordance with Section 13.1(a), Section 13.1(c), Section 13.1(e), Section 13.1(f) or Section 13.2(a), or for any repudiation or termination by Operator other than properly pursuant to the other events described in Section 13.2, Contractor shall be entitled to payment as set out in Appendix I for the Work performed up to the date of such termination, together with the Demobilization Fee as set forth in Appendix I, any other sums due or payable in relation to the period prior to the date of termination (including any such amortized amounts as provided under Section 3.3(a) and any Rig Modification Cost (less any payments made in accordance with Section 3.3(a) and Appendix I, Section B(4)), which shall become payable on a lump-sum basis), and an amount equal to the application of the then-applicable Standby Rate for each remaining day of the Primary Term or any Extension Term, as applicable, as of the date of termination, as settlement in full for the termination of this Drilling Contract (the foregoing collectively the “Early Termination Fee”); provided that Contractor shall not be entitled to any additional payment or other consideration whatsoever and subject to Contractor’s obligation to remit to Operator all day-rate compensation that Contractor may subsequently receive from any other party for utilization of the Rig as to each day during the remainder of the Primary Term or any Extension Term, as applicable, up to the amount paid by Operator to Contractor;

(b)For termination in accordance with Section 13.1(d) or Section 13.2(b), Contractor shall be entitled to payment as set out in Appendix I for Work performed up to the date of such termination if such termination occurs after the Term Commencement Date, any other sums due or payable in relation to the period prior to the date of termination (including any such amortized amounts as provided under Section 3.3(a) and any Rig Modification Cost (less any payments made in accordance with Section 3.3(a) and Appendix I, Section B(4)), which shall become payable on a lump-sum basis), and the Demobilization Fee, as settlement in full for the termination of this Drilling Contract; provided that

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Contractor shall not be entitled to any additional payments or other consideration whatsoever;

(c)For termination in accordance with Section 13.1(b), Section 13.2(c), Section 13.2(d), Section 13.2(e), Section 13.2(f), Section 13.2(g), Section 13.2(h) or Section 13.2(i), Contractor shall be entitled to payment as set out in Appendix I for Work performed up to the date of such termination, and any other sums due or payable in relation to the period prior to the date of termination (including any such amortized amounts as provided under Section 3.3(a) and any Rig Modification Cost (less any payments made in accordance with Section 3.3(a) and Appendix I, Section B(4)), which shall become payable on a lump-sum basis), as settlement in full for the termination of this Drilling Contract; provided that Contractor shall not be entitled to any additional payments or other consideration whatsoever; and

(d)For termination by Operator at any time during the first (1st) year following the Term Commencement Date that is due to a fundamental breach by Contractor of the terms or obligations under this Drilling Contract (for avoidance of doubt, such fundamental breach shall include the circumstances covered in Section 13.2(e)), subject to the provisions of Section 13.3(c), Contractor shall refund and pay to Operator an amount equal to the Mobilization Fee multiplied by the quotient of the number of days remaining in the Primary Term divided by the total number of days in the Primary Term; provided that such amount shall not exceed fifty percent (50%) of the Mobilization Fee.

13.4Exclusive Remedies

(a)[***]

(b)[***]

(c)Neither Contractor nor Operator shall have any right of termination of this Drilling Contract except pursuant to Sections 13.1 and 13.2, respectively. Notwithstanding anything to the contrary in this Drilling Contract, Operator shall always be entitled to remedies of injunctive relief or specific performance or both, in each case, to the extent available under the laws of England (which remedies, for the avoidance of doubt, shall never include any right or remedy of Operator to take over operation of the Rig or any other Contractor’s Items).

(d)[***]

(e)[***]

ARTICLE XIV
UNSATISFACTORY PERFORMANCE

14.1If Contractor should neglect, delay or discontinue its Work hereunder (except as herein provided), if Contractor should fail to conduct its operations in accordance with this Drilling Contract as a result of causes solely within the control of Contractor, or if Contractor has failed to furnish or to maintain the Rig in compliance with the requirements of this Drilling Contract, Operator may give Contractor written notice in which the causes of dissatisfaction shall be specified.  Should Contractor fail or refuse to

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

commence to remedy the matters complained of within ten (10) days after written notice is received by Contractor, then the senior management of Contractor and Operator shall promptly meet to discuss the appropriate course of action to correct the alleged non-compliance.  If such meeting does not produce satisfactory results and the cause of Operator’s reasonable dissatisfaction has not been cured within ninety (90) days of the meeting, then Operator may, at any point thereafter, suspend the Work and Contractor shall be at the Zero Rate during such suspension until the non-compliance has been corrected.  Should Contractor fail to correct the non-compliance within [***] days, then Operator shall have the right to terminate this Drilling Contract.

ARTICLE XV
NOTICES

15.1Notices and other communications permitted or required hereunder shall be in writing and shall be deemed received (a) when delivered by hand in person, receipt thereof being acknowledged in writing or (b) on the date of signature for receipt by the receiving Party of certified, registered or couriered mail or (c) upon receipt by the sending Party of a reply telefax confirming receipt by the receiving Party of the telefax sent by the sending Party.  Notices and other communications shall be as follows:

IF TO OPERATOR:

Cobalt International Energy, L.P.

Cobalt Center

920 Memorial City Way, Suite 100

Houston, Texas  77024

Tel: 713-579-9137

Fax: 713-579-9184

Email: greg.herring@cobaltintl.com

Attn: Mr. Greg Herring

With a mandatory copy to:

Cobalt International Energy, L.P.

Cobalt Center

920 Memorial City Way, Suite 100

Houston, Texas  77024

Tel: 713-579-9100

Fax: 713-579-9184

Attn: Chief Operating Officer

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

IF TO CONTRACTOR:

Rowan Reliance Limited

Suite 1 Burns House

19 Town Range

Gibraltar

Tel: +350 200 79423

Fax: +350 200 71405

Attn: Director

With a mandatory copy to:

Rowan Companies, Inc.

2800 Post Oak Boulevard, Suite 5450

Houston, Texas 77056

Attn: Mr. John Buvens, Executive Vice President — Legal

Email: jbuvens@rowancompanies.com

Tel: 713-960-7588

Fax: 713-960-7658

ARTICLE XVI
SUCCESSOR AND ASSIGNS / ASSIGNMENT

16.1This Drilling Contract shall inure to the benefit of and be binding upon the respective successors and permitted assigns of the Parties.  This Drilling Contract is personal and Contractor may not assign in whole or in part its rights or obligations under this Drilling Contract without Operator’s prior written consent, such consent not to be unreasonably withheld, conditioned or delayed.  Operator shall have the right, at any time, to assign all or any part of this Drilling Contract to one of its Affiliates upon notice to Contractor; provided that, unless otherwise agreed in writing between Operator and Contractor, Operator shall remain fully liable for the performance of its obligations hereunder and the obligations of its assignee in respect to the assignment for the full term or period of such assignment.  Operator shall also have the right, at any time, to assign all or any part of this Drilling Contract to a Third Party, with prior written consent from Contractor, such consent not to be unreasonably withheld.  In the event of any assignment of this Drilling Contract by Operator to a Third Party, unless otherwise agreed in writing between Operator and Contractor, Operator shall remain fully liable for the performance of its obligations hereunder and the obligations of its assignee in respect to the assignment for the full term or period of such assignment.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

ARTICLE XVII
CONFIDENTIALITY

17.1All information relating to any well(s) drilled pursuant to this Drilling Contract (including well data, log data, prospects, geological or geophysical information, and operational information) obtained by any member of Contractor Group in the conduct of the Work shall be held in strictest confidence by Contractor Group and shall not be disclosed to any other Person except as expressly provided for pursuant to this Article XVII.  Contractor acknowledges and agrees that its obligation with regard to such information requires the highest degree of trust and confidence and shall ensure that such information is not utilized in any activity of Contractor or of Contractor’s Affiliates not related to the Work.  Contractor hereby agrees to be responsible for any use or disclosure of such information by Contractor Group in breach of this Article XVII; accordingly, Contractor agrees that in the event of any such breach or threatened breach, Operator, in addition to any other remedies at law or in equity that it may have, shall be entitled, without the requirement of posting a bond or other security, to equitable relief, including injunctive relief or specific performance or both.

17.2All right, title and interest in and to the information relating to any well(s) drilled pursuant to this Drilling Contract (including well data, log data, prospects, geological or geophysical information, and operational information) shall remain the exclusive property of Operator.  No interest, license or any right respecting such information, is granted hereunder to Contractor or any other Person by implication or otherwise.  Contractor and any other member of Contractor Group shall have no equitable, legal or other interests in any mineral or hydrocarbon deposits which are known or which might be discovered as a result of the Work.  If any such Persons assert, attempt to establish or establish any interest in the mineral or hydrocarbon deposits which are a result of the Work or any other action taken with respect to this Drilling Contract, Contractor shall be responsible for and hold harmless and indemnify Operator Group from and against all losses and damages relating thereto.

17.3The Parties and their respective Groups shall (a) not use the information obtained in conduct of the Work, or allow the use of such information, for any purpose other than the performance of the Work, (b) advise their respective employees that all information obtained in the conduct of the Work is confidential information and requires the highest degree of trust and confidence, and (c) instruct their respective employees not to buy or sell securities of either Party or either Party’s Affiliates based on information obtained in the conduct of the Work.

17.4Neither Contractor nor Operator (nor any of Contractor’s or Operator’s Affiliates) shall make or issue any voluntary public announcement, disclosure or statement with respect to this Drilling Contract, and Contractor (and its Affiliates) shall not make or issue any voluntary public announcement, disclosure or statement with respect to the Work performed hereunder, without requesting and receiving the prior written consent of the other Party; provided, however, that a Party (or its Affiliate) may, without the prior

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

written consent of the other Party, issue such disclosures as may be required by applicable law or Governmental Authority pursuant to proper process, or any rule of any securities exchange market to which the disclosing Party (or its Affiliate) is subject, a Party shall be permitted to disclose this Drilling Contract, to the extent reasonably necessary, to any financial institution, lender or potential equity investor who is investigating the provision of financing to or investment in the equity of such Party (or its Affiliate); provided that such financial institution, lender or potential equity investor has entered into a confidentiality agreement with such disclosing Party (or its Affiliate) and Operator (or its Affiliate) shall be permitted to disclose any information with respect to results of any well(s) drilled pursuant to this Drilling Contract.  Such request shall be made no less than three (3) business days prior to the date of release or disclosure and a failure to reply by any of the Parties within said three (3) business day period shall be deemed as consent to the release.

17.5The foregoing shall not apply to the Parties’ normal and customary disclosures of contract commitments of a public nature, including the disclosure of this Drilling Contract as a material agreement pursuant to any rule of any Governmental Authority or securities exchange market to which the disclosing Party (or its Affiliate) is subject.

17.6Contractor shall ensure that the provisions of this Article XVII are incorporated in any of its subcontracts related to the Work and that the managers, directors, officers, employees, consultants, representatives, invitees, and agents of Contractor, its Affiliates, and subcontractors of any tier comply with same.

ARTICLE XVIII
GENERAL

18.1This Drilling Contract has been jointly drafted by Operator and Contractor, and no portion of this Drilling Contract shall be construed against Operator or Contractor on the ground that Operator or Contractor supplied, amended, or deleted such portion or any other portion hereof.  However, the obligations, undertakings, representations and warranties in the “Whereas” clauses of this Drilling Contract shall be considered as fully enforceable.

18.2It is expressly understood that Contractor is an independent contractor and none of Contractor, its contractors and subcontractors, and any of their respective employees, representatives and agents, are or shall be employees, representatives or agents of Operator.  As an independent contractor, neither Contractor nor anyone employed by Contractor will be eligible for the benefits provided to regular employees of Operator, including health and disability insurance.  The actual performance and superintendence of all Work hereunder shall be by Contractor, under the control and direction of Contractor, as to the details of the Work and Contractor shall take responsibility for the adequacy, stability and safety of all of its operations and methods necessary for the performance of the Work; provided, however, that Operator, being interested in the results to be obtained, is authorized to designate a representative or representatives who shall at all times have

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

access to the Rig and related equipment for the purposes of observing tests or inspecting the Work performed hereunder by Contractor in furtherance of its interest.

18.3This Drilling Contract, including the Appendices, constitutes the entire agreement of the Parties.  Each Party agrees that in entering into this Drilling Contract and the documents referred to therein, such Party is not relying on, and shall have no remedy in respect of, any statements, warranties, or representations given or made (whether negligently or innocently and whether express or implied), which are not expressly set out in this Drilling Contract.  Nothing in this Section 18.3 operates to limit or exclude any liability for fraud.  In the event of a conflict between the Appendices, on the one hand, and the body of this Drilling Contract, on the other, the body of this Drilling Contract shall prevail.

18.4If any portion of this Drilling Contract is declared by a court of competent jurisdiction to be invalid, illegal or incapable of being enforced by any applicable laws, this Drilling Contract shall nevertheless continue in force and effect as to those provisions remaining valid.  The waiver or forbearance of any right hereunder shall not preclude the insistence of such right thereafter in any instance.

18.5In the event of conflict between any provision or term hereof and the provisions or terms of any invoice, bid, price list, manifest, job order or other document between the Parties, the provisions and terms hereof shall prevail.

18.6No amendment hereto shall be effective unless contained in an instrument in writing executed by Operator and Contractor.

18.7None of the terms and conditions of this Drilling Contract shall be considered to be waived by either Operator or Contractor unless a waiver is given in writing by one Party to the other.  No failure on the part of either Party to enforce any of the terms and conditions of this Drilling Contract shall constitute a waiver of such terms.  A waiver shall not be a continuing waiver unless expressly stated.

18.8Notwithstanding anything to the contrary in this Drilling Contract, the provisions of Section 2.7(b), Article III, Article IV, Article VIII, Article IX, Article XI, Article XIII, Article XVII, and this Section 18.8 and any other provision of this Drilling Contract providing for payment of sums due and payable or accruing on or after the termination date of this Drilling Contract shall survive the termination of this Drilling Contract.

18.9This Drilling Contract shall be binding upon and inure solely to the benefit of each Party and their successors, assigns and transferees.

18.10Communications; Language

(a)All instructions, notices, agreements, authorizations, approvals and acknowledgements issued pursuant to, relating to or arising out of this Drilling

64

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Contract shall be in writing.  All such documentation, together with all correspondence and other documents, shall be in English.

(b)Notwithstanding the foregoing, if for any reason it is considered necessary by Operator to give an instruction to Contractor orally in the first instance, Contractor shall comply with such instruction.  Any such oral instruction shall be confirmed in writing as soon as is possible under the circumstances; provided that if Contractor confirms in writing any such oral instruction which is not contradicted in writing by Operator without undue delay, it shall be deemed to be an instruction in writing by Operator.

18.11The Parties agree that this Drilling Contract may be executed in counterparts, including fax counterparts, and together with all counterpart executions shall be considered an original for all purposes hereunder.

18.12Third Party Rights

(a)Subject to subsection (c) hereof, the Parties intend that no provision of this Drilling Contract shall, by virtue of the Contracts (Rights of Third Parties) Act 1999 (the “Act”) confer any benefit on, nor be enforceable by, any Person who is not a party to this Drilling Contract.

(b)For the purpose of this Section 18.12, “Third Party” shall include any member of Operator Group or Contractor Group, but exclude Operator, Contractor, and their respective permitted assignees and novatees.

(c)Subject to the provisions of this Drilling Contract, Article VIII and Article IX are intended to be enforceable by a Third Party by virtue of the Act.

(d)Notwithstanding subsection (c) hereof, this Drilling Contract may be rescinded, amended or varied by the Parties without notice to or the consent of any Third Party even if, as a result, that Third Party’s right to enforce a term of this Drilling Contract may be varied or extinguished.

(e)In enforcing any right to which it is entitled by virtue of the Act and under the provisions of this Drilling Contract, the remedies of a Third Party shall be limited to damages only and such Third Party shall not be entitled to any other remedies available at law or otherwise.

(f)A Third Party shall not be entitled to assign any benefit or right conferred on it under this Drilling Contract.

18.13Parties’ Representations and Warranties

(a)Contractor represents and warrants that (i) it has been duly organized, formed or incorporated, as the case may be, and is existing and in good standing under the

65

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

laws of Gibraltar, with power and authority (corporate and other) to perform its obligations under this Drilling Contract, and (ii) any entity to which this Drilling Contract will be assigned or novated pursuant to the terms hereof is or will be duly organized, formed or incorporated, as the case may be, and existing and in good standing under the laws of the jurisdiction of its organization, formation or incorporation, as the case may be, with power and authority (corporate and other) to perform its obligations under the Deed of Novation and this Drilling Contract.

(b)Contractor represents and warrants that (i) this Drilling Contract has been duly authorized, executed and delivered by Contractor and the obligations of Contractor hereunder constitute legal, valid and binding obligations on Contractor, and (ii) the Deed of Novation will be duly authorized, executed and delivered by the novatee thereof, and after the Deed of Novation is executed and delivered by Contractor, such novatee and Operator, the obligations of such novatee thereunder will constitute legal, valid and binding obligations on such novatee.

(c)Contractor represents and warrants that (i) its entry into this Drilling Contract (A) will not contravene any applicable law, regulation, judgment, order or decree of any court or body having jurisdiction over Contractor and (B) will not contravene or conflict with any provision of the organizational documents of Contractor; and (ii) the applicable novatee’s entry into the Deed of Novation (X) will not contravene any applicable law, regulation, judgment, order or decree of any court or body having jurisdiction over such novatee and (Y) will not contravene or conflict with any provision of the organizational documents of such novatee.

(d)Operator represents and warrants that it has been duly formed and is existing and in good standing under the laws of the State of Delaware, with power and authority (corporate and other) to perform its obligations under this Drilling Contract.

(e)Operator represents and warrants that this Drilling Contract has been duly authorized, executed and delivered by Operator and the obligations of Operator hereunder constitute legal, valid and binding obligations on Operator.

(f)Operator represents and warrants that its entry into this Drilling Contract (A) will not contravene any applicable law, regulation, judgment, order or decree of any court or body having jurisdiction over Operator and (B) will not contravene or conflict with any provision of the organizational documents of Operator.

18.14In connection with the performance of the Work under this Drilling Contract, Operator and Contractor each agree that they and their respective Affiliates will comply with all applicable anti-corruption laws, including but not limited to the U.S. Foreign Corrupt Practices Act of 1977, as amended, and the UK Bribery Act 2010, as amended.

66

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

18.15As of the Effective Date, Contractor shall cause its parent entity, Rowan Companies plc, to execute and deliver the Deed of Guarantee to Operator.

18.16In the event that Operator transfers or disposes of assets to one or more of its Affiliates, and such transfer or disposition, in Operator’s sole determination, represents a material amount of assets, Operator shall notify Contractor and the Parties shall meet to discuss the effect of such transfer or disposition upon the financial condition of Operator.

[Signature Page Follows]

67

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

IN WITNESS WHEREOF, the Parties hereto have executed this Drilling Contract by their duly authorized officers or representatives as of the day and year first above written.

OPERATOR:
COBALT INTERNATIONAL ENERGY, L.P.
By:	/s/ Van P. Whitfield
Name:	Van P. Whitfield
Title:	Chief Operating Officer
CONTRACTOR:
ROWAN RELIANCE LIMITED
By:	/s/ Louis B. Triay
Name:	Louis B. Triay for Trilex Ltd
Title:	Director

SIGNATURE PAGE TO

OFFSHORE DRILLING CONTRACT

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDIX A

RIG ACCEPTANCE AND PERFORMANCE CRITERIA

Contractor shall demonstrate that the Rig and all marine, drilling, subsea, emergency, and other systems are acceptable to Operator through a series of tests (hereinafter, collectively, the “Acceptance Tests”) to be established by Operator, with the agreement of Contractor, such agreement not to be unreasonably withheld.  The Acceptance Tests will be designed to load test and/or pressure test all major components, function test components where appropriate, and perform other tests as required herein prior to Operator accepting the Rig (“Acceptance”) for the performance of the Work under the Drilling Contract.  The time of Acceptance will be determined by an Acceptance Letter provided by Operator to Contractor.  The Acceptance Letter shall include:

·The date of Acceptance of the Rig by Operator;

·Operator’s confirmation that the Rig has passed all pressure, load, and function tests; such tests to include, without limitation, those listed in Sections A through M of this Appendix A; and

·Operator’s confirmation that the Rig is acceptable for use by Operator for the Primary Term of the Drilling Contract.

Notwithstanding anything to the contrary in this Appendix A, the demonstration of the Acceptance Tests listed under Section B.2S BOP Stack Subsea Tests — Secondary BOP Stack shall not be a condition of Acceptance pursuant to this Appendix A and such Acceptance Tests shall be performed following Acceptance of the Rig by Operator.  In the event the Rig fails such Acceptance Tests listed under Section B.2S BOP Stack Subsea Tests — Secondary BOP Stack, such failure shall be deemed to be an event constituting BOP Unavailability and the provisions of Appendix I, Section B(3) shall apply.

Section A:Safety, SEMS, and Regulatory Compliance

A.1Rig Safety

A.1.1Review General Rig Safety Procedures

A.1.2Review Rig Safety Case (if applicable)

A.1.3Audit Contractor’s SMS

A.2Crew Competency (Knowledge, Skills, and Abilities)

A.2.1Review Crew Competency (Knowledge, Skills, and Abilities)

A.3Certifications

A.3.1Review all Certifications

Section B:Well Control and Subsea Equipment

B.1PBOP Stack Surface Tests — Primary BOP Stack

B.1.1Function Test BOP with Largest Pipe Size on Test Stump

B.1.2Pressure Test BOP with Largest Pipe Size on Test Stump

A-1

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

B.1.3Function Test BOP with Smallest Pipe Size on Test Stump

B.1.4Pressure Test BOP with Smallest Pipe Size on Test Stump

B.1.5Pressure Test Choke and Kill Lines on Test Stump

B.1.6Function Test EDS Sequence on Test Stump

B.1.7Test Dead-Man Function on Test Stump

B.1.8Test Auto-Shear Function on Test Stump

B.1.9Demonstrate ROV Hot-stab Functions on Test Stump

B.1SBOP Stack Surface Tests — Secondary BOP Stack

Note:Repeat B.1.1 through B.1.9 for Secondary BOP Stack

B.2PBOP Stack Subsea Tests — Primary BOP Stack

B.2.1Run BOP and Riser and Latch BOP on Wellhead

B.2.2Test LMRP ROV Function Subsea

B.2.3Test Emergency Hydraulic BOP Control System

B.2.3Test Acoustic Emergency BOP Control System

B.2.4Demonstrate Emergency Disconnect of LMRP Subsea (Re-coil Test)

B.2.5Adjust Rig Heading with BOP Latched

B.2.6Perform Accumulator Draw-down Test Subsea

B.2.7Function Test BOP Subsea

B.2.8Pressure Test BOP Subsea from Alternate Pod

B.2.9Pump Down Choke and Kill Lines and Boost with Returns Through Riser

B.2.10Pump Down Kill Line, Up Choke Line, Through Choke Manifold

B.2.11Pump Down Drill Pipe with Returns Through Choke and Kill Lines

B.2.12Function Test Diverter

B.2.13Pressure Test Riser Gas Handling System

B.2.14Demonstrate Operation of Riser Gas Handling System with Seawater

B.2.15Test Pipe Ram ROV Over-Ride Functions Subsea

B.2.16Test BSR/CSR ROV Over-Ride Functions Subsea

B.2.17Test Auto-Shear Arm ROV Over-Ride Function Subsea (if applicable)

B.2.18Reserved for Testing Additional ROV Over-Ride Functions Subsea

B.2.19Reserved for Testing Additional ROV Over-Ride Functions Subsea

B.2.20Reserved for Testing Additional ROV Over-Ride Functions Subsea

B.2.21Reserved for Testing Additional ROV Over-Ride Functions Subsea

B.2.22Function Test Dead-Man BOP Stack Emergency Function Subsea

B.2.23Function Test Auto-Shear BOP Stack Emergency Function Subsea

B.2.24Test BOP Connector ROV Over-Ride Function Subsea

B.2.25Pull Riser and BOP

Note: To the extent possible, Operator shall endeavor to conduct all tests listed under this Section B.2P BOP Stack Subsea Tests — Primary BOP Stack in connection with the test identified in B.2.4 Demonstrate Emergency Disconnect of LMRP Subsea (Re-coil Test).

B.2SBOP Stack Subsea Tests — Secondary BOP Stack

Note:Repeat B.2.1 through B.2.24 for Secondary BOP Stack (excluding B.2.13 and B.2.14.)

A-2

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

B.3Choke Manifold

B.3.1Pressure Test Choke Manifold

B.4MTop-Drive IBOP’s

B.4.1Pressure Test Top-Drive IBOP’s

B.4ATop-Drive IBOP’s

Note:Repeat B.4.1 for Auxiliary Well Center

Section C:Circulating System

C.1Mud Pits

C.1.1Verify Active and Reserve Pit Integrity with Seawater

C.1.2Verify Active and Reserve Pit Capacities

C.2Solids Control Equipment

C.2.1Demonstrate Solids Control Equipment Operation

C.2.2Demonstrate Emergency Shut-Down for Solids Control Equipment

C.3Mud Pumps

C.3.1Demonstrate Mud Pump Performance

C.4Centrifugal Pumps

C.4.1Demonstrate Active and Reserve Pit Piping and Transfer Pumps

C.5Stand-pipe Manifold

C.5.1Pressure Test Stand-pipe Manifold

Section D:Mud and Cement Bulk Systems

D.1Mud Bulk System

D.1.1Verify Pressure Test Mud Bulk Tanks, Lines, and Hoses

D.1.2Verify Mud Bulk Tank Capacities

D.1.3Demonstrate Barite and Gel Bulk Transfer Capabilities

D.1.4Demonstrate Barite and Gel Bulk Transfer to Sack Room

D.1.5Demonstrate Mud Mixing System

D.1.6Demonstrate Chemical Mixing System

D.2Cement Bulk System

D.2.1Verify Pressure Test Cement Bulk Tanks, Lines, and Hoses

D.2.2Verify Cement Bulk Tank Capacities

D.2.3Demonstrate Cement Bulk Transfer Capabilities

D.2.4Demonstrate Cement Bulk Transfer to Cement Unit

Section E:Power Supply Systems

E.1Main Diesel Engines, Generators, and Power Distribution

E.1.1Test Diesel Engines and Generators

E.1.2Test Power Management System

E.1.3Demonstrate Power Limiting and Phase Back of Drilling Systems and Thrusters.

E.1.4Verify Generator Load Protection Settings

A-3

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

E.2Emergency Shut-Down

E.2.1Test Emergency Shut-Down of Engines

E.3Emergency Generator

E.3.1Test Emergency Diesel Engine and Generator

Section F:Hoisting and Rig Floor

F.1MDraw-works — Main Well Center

F.1.1Demonstrate Draw-works Operation

F.1.2Demonstrate Crown-Saver and Floor-Saver Operation

F.1.3Slip and Cut Drill Line

F.1ADraw-works — Auxiliary Well Center

Note:Repeat F.1.1 through F.1.3 for Auxiliary Well Center

F.2Derrick

F.2.1Verify Load Test of Derrick

F.2.2Verify Derrick Capacities

F.2.3Demonstrate Heave-Compensator Operation

F.2.4Inspect Crown Blocks and Traveling Blocks

F.3MTop-Drive — Main Well Center

F.3.1Demonstrate Top-Drive Operation

F.3.2Demonstrate Top-Drive Speed Control

F.3.3Demonstrate Stabbing Top-Drive at Any Block Height

F.3.4Demonstrate Ability of Top-Drive to Hold Constant Torque

F.3.5Demonstrate Operation of Raised Back-up

F.3ATop-Drive — Auxiliary Well Center

Note:Repeat F.3.1 through F.3.5 for Auxiliary Well Center

F.4MRig Floor Equipment — Main Well Center

F.4.1Demonstrate Rotary Table Operation

F.4.2Flood Rig Floor to Check for Leaks

F.4.3Demonstrate Horizontal to Vertical Pipe Handling Machine (if applicable)

F.4.4Demonstrate Operation of Power Slips

F.4.5Demonstrate Operation of Iron Rough-neck

F.4ARig Floor Equipment — Auxiliary Well Center

Note:Repeat F.4.1 through F.4.5 for Auxiliary Well Center

Section G:Tubular Handling Equipment

G.1Tubular Handling Equipment

G.1.1Audit Break-in of Rotary Shouldered Connections

G.1.2Demonstrate Operation of Racking System

G.1.3Demonstrate Operation of Mousehole(s)

G.1.4Demonstrate Operation of Fox-hole(s)

G.1.5Verify Max/Min Stand Heights

G.1.6Demonstrate Zone Management System (ZMS)

G.1.7Demonstrate Make-up and Break-out of Bit with Bit Breaker

G.1.8Demonstrate Manual Drill Pipe Handling

A-4

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

G.1.9Demonstrate Mud Bucket Operation

G.1.10Demonstrate Racking 117/8” Casing/Liner

G.1.11Demonstrate Running 18” Casing

G.1.12Demonstrate Running 36” Structural Casing

G.1.13Demonstrate Operation of Hydraulic Cat-heads

Section H:Marine Systems

H.1Marine Systems

H.1.1Demonstrate Ballast System

H.1.2Confirm Configuration of DP System Settings

H.1.3Demonstrate Power Plant Function

H.1.4Conduct Thruster Trials

H.1.5Demonstrate Auto-Pilot Function

H.1.6Conduct Dynamic Positioning System Trials

H.1.7Conduct Navigation Monitoring Station Functional Tests

H.1.8Conduct System Redundancy Tests

H.1.9Conduct Power Management Tests

H.1.10Verify Maximum Speeds at Varying Drafts

H.1.11Reserved for Additional DP System Tests

H.1.12Reserved for Additional DP System Tests

H.1.13Reserved for Additional DP System Tests

Section I:Not Used

Section J:Emergency and Safety System

J.1Emergency and Safety Systems

J.1.1Audit Firefighting and Lifesaving Equipment

J.1.2Demonstrate Survival Boats

J.1.3Conduct Man Overboard Drills

J.1.4Audit Firefighting Drills

Section K:Deck Handling Equipment

K.1Pedestal Cranes

K.1.1Audit Certification of Pedestal Cranes

K.1.2Demonstrate Pedestal Crane Operations

K.2Knuckle Boom Cranes

K.2.1Audit Certification of Knuckle Boom Cranes

K.2.2Demonstrate Knuckle Boom Crane Operations

K.3Heave-Compensated Crane

K.3.1Audit Certification of Heave-Compensated Crane

K.3.2Demonstrate Heave-Compensated Crane Operation

K.4Gantry Cranes

K.4.1Audit Certification of Riser Gantry Cranes

A-5

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

K.4.2Demonstrate Riser Gantry Crane Operations

K.4.3Audit Certification of BOP Gantry Cranes

K.4.4Demonstrate BOP Gantry Crane Operations

K.4.5Audit Certification of Pod House Gantry Crane

K.4.6Demonstrate Pod House Gantry Crane Operation

K.4.7Audit Certification of Parts Warehouse Gantry Crane (if applicable)

K.4.8Demonstrate Parts Warehouse Gantry Crane Operation (if applicable)

K.4.9Audit Certification of Sack Room Gantry Crane (if applicable)

K.4.10Demonstrate Sack Room Gantry Crane Operation (if applicable)

K.5BOP Handling System

K.5.1Demonstrate Primary BOP Handling System

K.5.2Demonstrate Secondary BOP Handling System

K.6Tree Handling System

K.6.1Demonstrate Tree Handling System

K.7Reserved for ROV Launch and Recovery System

Section L:Spares and Preventative Maintenance Systems

L.1Spares

L.1.1Audit Spares Inventory against Manufacturer’s Recommended Spares List

L.2Preventative Maintenance Systems

L.2.1Audit all Preventative Maintenance Systems

L.2.2Audit the Document Library (Manuals, Drawings, etc.) on the Rig

Section M:Auxiliary Systems

M.1Zero Discharge System

M.1.1Demonstrate Oil/Water Separator Operation

M.2Well Test Equipment

M.2.1Pressure Test Flare Boom Lines

M.2.2Pressure Test Fixed Lines from Rig Floor to Separator Area (if applicable)

M.3Cement Unit

M.3.1Verify Cement Unit Commissioning

M.3.2Confirm Calibration of Cement Unit Displacement Tanks

M.3.3Demonstrate Supply of Drill Water to Cement Unit

M.3.4Demonstrate Supply of Seawater to Cement Unit

M.3.5Demonstrate Operation of Batch Mixer with Seawater

M.3.6Pressure Test Cement Lines and Cement Manifold

M.3.7Demonstrate Cement Unit Maximum Pumping Rate with Water

M.3.8Demonstrate Mixing of Test Cement Slurry

M.4Reserved for Remote Operated Vehicle(s)

M.5Reserved for Mud Logging Unit

Section N:Additional Items

A-6

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Additional Rig Acceptance Testing may be required, and if so, will be covered under a future addendum hereto, as mutually agreed upon by Contractor and Operator.

A-7

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDIX B

CONTRACTOR’S PERSONNEL

A.Rig Personnel:

Position	Number on Board	Hourly Cost* (Regular)	Hourly Cost* (Overtime)	Daily Cost*
DRILLING SUPERINTENDANT**	1	[***]	[***]	[***]
TOOLPUSHER**	3	[***]	[***]	[***]
DRILLER**	4	[***]	[***]	[***]
ASSISTANT DRILLER	4	[***]	[***]	[***]
DERRICKMAN	2	[***]	[***]	[***]
ASSISTANT DERRICKMAN	2	[***]	[***]	[***]
FLOORHAND	12	[***]	[***]	[***]
SENIOR SUBSEA ENGINEER (MUX)	1	[***]	[***]	[***]
SUB-SEA ENGINEER**	2	[***]	[***]	[***]
ASST SUB-SEA ENGINEER	2	[***]	[***]	[***]
CHIEF ENGINEER — DP**	1	[***]	[***]	[***]
1st ASSISTANT ENGINEER	1	[***]	[***]	[***]
2nd ASSISTANT ENGINEER	1	[***]	[***]	[***]
3rd ASSISTANT ENGINEER	2	[***]	[***]	[***]
3rd ASSISTANT ENGINEER - OILER	1	[***]	[***]	[***]
MECHANICAL SUPERVISOR	1	[***]	[***]	[***]
CHIEF MECHANIC**	2	[***]	[***]	[***]
MECHANIC	2	[***]	[***]	[***]
MOTOR OPERATOR	3	[***]	[***]	[***]
ELECTRICAL SUPERVISOR	1	[***]	[***]	[***]
CHIEF ELECTRICIAN	2	[***]	[***]	[***]
ELECTRICIAN	2	[***]	[***]	[***]
CHIEF ELECTRONICS TECHNICIAN	2	[***]	[***]	[***]
ELECTRONICS TECHNICIAN	3	[***]	[***]	[***]
WELDER	2	[***]	[***]	[***]
OIM — MASTER — DP**	1	[***]	[***]	[***]
SENIOR DP OPERATOR**	2	[***]	[***]	[***]
DP OPERATOR	2	[***]	[***]	[***]
CHIEF MATE	1	[***]	[***]	[***]
SECOND MATE	1	[***]	[***]	[***]
THIRD MATE	1	[***]	[***]	[***]
MEDIC	1	[***]	[***]	[***]
SAFETY TRAINING COORDINATORS	2	[***]	[***]	[***]
AB SEAMAN	2	[***]	[***]	[***]

B-1

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

CRANE OPERATOR	4	[***]	[***]	[***]
ASSISTANT CRANE OPERATOR	2	[***]	[***]	[***]
DECK PUSHER	2	[***]	[***]	[***]
ROUSTABOUT	12	[***]	[***]	[***]
SENIOR MATERIALS COORDINATOR	1	[***]	[***]	[***]
MATERIALS COORDINATOR	1	[***]	[***]	[***]
RADIO OPERATOR	1	[***]	[***]	[***]
TOTAL	95

*Rates as of June 2013, which such rates may be subject to adjustment annually effective the anniversary of the Term Commencement Date pursuant to Section 3.3(b)(i) of this Drilling Contract.

**Key Personnel

B.Catering Personnel:

Catering crew as required.

C.Work Schedule:

All of Contractor’s Personnel working offshore as part of the Rig crew shall have a twenty-one (21) days on/twenty-one (21) days off rotation schedule for the Work conducted in the Area of Operations.  All Contractor’s Personnel will work an equal time “on”/”off” schedule.  The regular hourly work schedule on board the Rig will be twelve (12) hours per day (6:00 am - 6:00 pm).

D.Overtime:

At Operator’s request, Contractor shall furnish Contractor’s Personnel for Operator’s account at the scheduled overtime cost, when such labor is required outside the normal working hours of the crew members involved.

B-2

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDIX C

CONTRACTOR’S RIG AND EQUIPMENT

[See Attached]

C-1

Unit Name: Rowan Reliance	Rowan Companies Inc.
		Printed on:            8/1/2013

INTERNATIONAL ASSOCATION OF DRILLING CONTRACTORS
STANDARD FORMAT EQUIPMENT LIST
FLOATING DRILLING UNIT

TABLE OF CONTENTS

SECTION A - UNIT SPECIFICATIONS

A1Main Dimensions/Technical Description

A2Storage Capacities

A3Propulsion/Thrusters

A4Operational Capabilities

A5Variable Loading

A6Environmental Limits

A7Mooring System

A8Marine Loading Hoses

A9Cranes, Hoists, and Materials Handling

A10Helicopter Landing Deck

A11Auxiliary Equipment

SECTION B - GENERAL RIG SPECIFICATIONS

B1Derrick and Substructure

B2Drawworks and Associated Equipment

B3Derrick Hoisting Equipment

B4Rotating System

SECTION C - POWER SUPPLY SYSTEMS

C1Rig Power Plant

C2Emergency Generator

SECTION D - DRILLSTRING EQUIPMENT

D1Tubulars

D2Handling Tools

D3Fishing Equipment

SECTION E - WELL CONTROL/SUBSEA EQUIPMENT

E1Lower Riser Diverter Assembly

E2Primary BOP Stack

E3Primary Lower Marine Riser Package

E4Secondary BOP Stack

E5Secondary Lower Marine Riser Package

E6Primary Marine Riser System

E7Secondary Marine Riser System

E8Diverter BOP

E9Subsea Support System

E10BOP Control System

C-2

E11Subsea Control System

E12Acoustic Emergency BOP Control System

E13Subsea Auxiliary Equipment

E14Choke Manifold

E15BOP Testing Equipment

E16Wellhead Running/Retrieving/Testing Tools

SECTION F - MUD SYSTEM/BULK SYSTEM

F1High Pressure Mud System

F2Low Pressure Mud System

F3Bulk System

SECTION G - CASING/CEMENTING EQUIPMENT

G1Casing Equipment

G2Cement Equipment

SECTION H - INSTRUMENTATION/COMMUNICATION

H1Drilling Instrumentation at Driller’s Position

H2Drilling Parameter Recorder

H3Instrumentation at Choke Manifold

H4Standpipe Pressure Gauge

H5Deviation Equipment

H6Calibrated Pressure Gauges

H7Rig Communication System

H8Environmental Instrumentation

H9Additional MODU Specific Instrumentation

H10Radio Equipment

SECTION I - PRODUCTION TEST EQUIPMENT

I1Burners

I2Burner Booms

I3Lines Required on Burner Booms

I4Sprinkler System

I5Fixed Lines for Well Tesing

I6Auxiliary Power Availability

SECTION J - WORKOVER TOOLS

SECTION K - ACCOMMODATION

K1Offices

K2Living Quarters

SECTION L - SAFETY EQUIPMENT

L1General Safety Equipment

L2Gas/Fire/Smoke Detection

L3Fire Fighting Equipment

L4Breathing Apparatus

L5Emergency First Aid Equipment

C-3

L6Helideck Rescue Equipment

L7Rig Safety Store

L8Emergency Warning Alarms

L9Survival Equipment

SECTION M - POLLUTION PREVENTION EQUIPMENT

M1Sewage Treatment

M2Garbage Compaction

M3Garbage Disposal/Grinder

Dimensions & capacities are approximate only, if shown:

A.UNIT SPECIFICATIONS
Unit Name :		Rowan Reliance
Rig Type :		MODU
Unit/Design/Shape :		Rowan / Gusto P10,000 Drillship
Unit Flag :		Marshall Islands
Unit Classification :		A1 Drillship E , AMS, ACCU, DPS-3, HELIDK(SRF), SH-DLA, SFA(25), UWILD, CDS, CRC, CPS, ENVIRO-OS NBL, ISQM
IMO Certification :	yes/no:	Yes
Which code version :		2009
Year of Construction :		2014
Construction Yard :		Hyundai Heavy Industries, Ulsan, Korea
Type of Positioning system (anchor/dp/combined) :		Dynamic Positioning
A.1MAIN DIMENSIONS/TECHNICAL DESCRIPTION		Note: Incline Experiment not yet performed
Weight (light ship) : estimated		~31,585	metric tonnes
Displacement at loadline :		69,900	metric tonnes
Draft at loadline (deepest) :		11.0	meters
Overall length of unit (including anchor racks) :		229.2	meters
Overall width of unit (including anchor racks) :		36.0	meters
Main deck length :		143.2	meters
Main deck width :		36.0	meters
Main deck elevation above baseline :	at centerline	18.2	meters
Number of main columns/diameter :		N/A
Number of small columns/diameter :		N/A
Drilling draft/related displacement :		N/A
Associated airgap : (RKB to waterline)		24.7	meters
Transit draft/related displacement :		N/A
Survival draft/related displacement :		N/A
Associated airgap :		N/A
Moon pool dimensions :		22.4 long x 12.8 wide	meters
Maximum opening through spider deck :		N/A
Pontoon length :		N/A

C-4

Pontoon breadth :		N/A
Pontoon height :		N/A
Maximum Substructure/Rotary Load :	Main	1,134	mt
	Aux	680	mt
Fuel Consumption (drilling) :		Aprox 50	m3 / day
Accommodation for max. no. of personnel :		210
A.2STORAGE CAPACITIES
Fuel :		47,174	bbls
Drilling wate :		18,240	bbls
Potable water :		8,806	bbls
Active liquid mud :		11,322	bbls
Mud processing tank :		377	bbls
Reserve liquid mud :		7,548	bbls
Bulk bentonite/barite :		456 / 2830	m3 / bbls
Bulk cement :		456 / 2830	m3 / bbls
Sack storage :		8,500	sacks (25kg)
Pipe racks area :
Pipe racks and storage areas :
Fwd-Port Casing pipe rack (area=164m2)		5	mt/m2
Aft-Port tubular storage area (area=97m2)		7	mt/m2
Aft-Dtbd tubular storage area (area=94m2)		7	mt/m2
Well installation area on aft panel deck (area=80m2)		7	mt/m2
Well test area on poop deck (area=300m2)		4	mt/m2
Riser racks Storage capacity :
Buoyant riser joint (OD= 60inch)		165	Joints
Miscellaneous storage area :			mt/m3
Brine storage :		7,548	bbls
Heavy brine accepted (e.g. bromide) :	yes/no:	Yes
Base oil storage :		6,919	bbls
Oil base mud storage :		Included above
Ballast system (or preload) :		N/A
A.3PROPULSION/THRUSTERS
A.3.1In-line Propulsion	yes/no:	No
Shafts:		N/A
Motors per shaft :		N/A
Motors make/type :		N/A
Total HP per shaft :		N/A
Propeller type (fixed/variable blade) :		N/A
Nozzled :	yes/no:
A.3.2Thrusters
Quantity :		6
Fixed/azimuthing :		Azimuthing - equipped with canister type retracting system
Motors per thruster :		1
Make/type motors :		Rolls Royce UUC 445 Thruster / ABB

C-5

		AMI 710L8L VATFMM Motor
Total HP per thruster :		5000 KW
Propeller type (fixed/variable blade) :		Fixed
Nozzled :	yes/no:	Yes
A.3.3Dynamic Positioning
Make/Model :		Kongsbeg DP-22 (main) Kongsberg K-Pos DP-12BU (backup)
Full DP or Mooring Assist :		Full DP
Position Reference :		acoustic (Nautronix RS925) x 2 / DGPS x 4 & (2 x DPS 232, 2 x C-Nav)
A.4OPERATIONAL CAPABILITIES
Maximum designed water depth capablity :		12,000	ft.
Outfitted max. water depth capability :		12,000	ft.
Normal min. water depth capability :		1,700	ft.
Drilling depth capability (rated) :		40,000	ft.
Transit speed towed (historical avg) :		N/A
Transit speed self propelled (historical avg) :		12 EST	Knots (min)
A.5VARIABLE LOADING (VL)
Transit VL :	~	20,000	metric tonnes
Drilling VL :	~	20,000	metric tonnes
Survival VL :	~	20,000	metric tonnes
A.6ENVIRONMENTAL LIMITS
Drilling
Air gap (below main deck) :		N/A
Max. wave height : (Significant wave height HS)		6.0	m
Max. wave period : (Peak wave heigh TP)		10 to 13	sec
Max. wind velocity : ( Wind 1-min mean		25	m/s
Max. current velocity : (Current at surface)		0.82	m/s
Max. heave (double amplitude) : based on -30 to + 30 degrees		16.4	ft
Max. pitch (double amplitude) : based on -30 to + 30 degrees		6.2	deg
Max. roll (double amplitude) : based on -30 to + 30 degrees		1.9	deg
Survival
Air gap (below main deck) :		N/A
Max. wave height :		13.0	m
Max. wave period :		17 to 20	sec
Max. wind velocity :		51.5 (1 - minute mean)	m/s
Max. current velocity :		0.8 (at surface)	m/s
Max. heave (doublt amplitude) : based on -30 to + 30 degrees		64.5	ft

C-6

Max. pitch (double amplitude) : based on -30 to + 30 degrees	14.5	deg
Max. roll (double amplitude) : based on -30 to + 30 degrees	6.9	deg
Transit
Air gap (below main deck) :	N/A
Max. wave height :	13	m
Max. wave period :	17 ~ 20	sec
Max. wind velocity :	51.5	m/s
Max. current velocity :	0.8	m/s
Max. heave (double amplitude) :	64.5	ft
Max. pitch (double amplitude) :	14.5	deg
Max. roll (double amplitude) :	6.9	deg
A.7MOORING SYSTEM
A.7.1Anchor Winches
Quantity :	2
Make/Model :	Rolls Royce
Type (electric/hydraulic/diesel) :	Electric
Motors per winch :	1
Motor make/type :	Ben Buchele Gimbh (BEN-440V60HZ-12/4/2-280 S-73, OKW-122A
Total HP per winch :	593.3	Knots
Rated pull :	40.2	ton
Speed low gear :	9	m/min
Test load :	40.2	ton
Control locations (local/remote/both) :	local
Emergency release (type/location) :	Electric motor exist manual of release for brake
A.7.2Fairleads	N/A
Quantity :	N/A
Make :	N/A
Free rotating range :	N/A
A.7.3Anchors
A.7.3.1Anchors - Primary
Quantity :	2
Make :	Hyundai Steel
Type :	Stockless high holding power type
Weight :	10,575	kg

C-7

A.7.3.2       Anchors - Spare		None
Quantity :
Make :
Type :
Weight:
A.7.4      Anchor Lines
Wire
Quantity (installed/spare) :
Make/Type:
Specification:
Diameter :
Weight per unit length :
Useful length (nominal) :
Classification :
Breaking strength :
Chain
Quantity (installed/spare) :
Make/Type :		Flash butt welded stud link anchor chain
Specification :		Grade 3
Diameter :		92	mm
Weight per unit length :
Useful length (nominal) :		715	m
Classification :		See A. above
Breaking strength :
A.7.5      Anchor Line Running & Retrieval System		1
Primary type (Pennant-buoy or chaser) :		N/A
A.7.5.1       Pennant Lines		N/A
Quantity :
Make :
Type :
Length :
Diameter :
A.7.5.2       Anchor Buoys		N/A
Quantity :
Volume each :
Type :
Foam filled :	yes/no:

C-8

		N/A
A.7.5.3       Chaser
Quantity :
Make :
Type :
A.7.6      Towing Gear
Towing bridle size :
Hook-up system :
Rating :
Power required for infield tow :	bollard pull lt:
Power required for ocean tow :	bollard pull lt:
Spare bridle :	yes/no:	No
A.7.7      Supply Vessel Mooring Lines
Locations (port/stbd/both) :		Both
System :
Rating :
A.8          MARINE LOADING HOSES
		Both
Location of loading manifolds (port/stbd/both) :		NOV Loading Station (fixed reels)
Make/Type :
A.8.1      Potable Water Hose
Quantity :		2
Size :		4”
Make/Type :
Color coding :	yes/no:	No
Make/Type/Connection :		To be confirmed with Client connections
A.8.2      Drilling Water Hose
Quantity :		2
Size :		4”
Make/Type :
Color coding :	yes/no:	No
Make/Type connection :		To be confirmed with Client connections
A.8.3      Gas Oil Hose
Quantity :		2
Size :		4”
Make/Type :

C-9

Color coding :	yes/no:	No
Make/Type connection :		To be confirmed with Client connections
A.8.4    Mud Chemical Hose
Quantity :		2
Size :		5”
Make/Type :
Color coding :	yes/no:	No
Make/Type connection :		To be confirmed with Client connections
A.8.5    Cement Hose
Quantity :		2
Size :		5”
Make/Type :
Color coding :	yes/no:	No
Make/Type connection :		To be confirmed with Client connections
A.8.6    Base Oil Hose
Quantity :		2
Size :		4”
Make/Type :
Color coding :	yes/no:	No
Make/Type connection :		To be confirmed with Client connections
A.8.7    Brine Hose
Quantity :		2
Size :		4”
Make/Type :
Color coding :	yes/no:	No
Make/Type connection :		To be confirmed with Client connections
A. 9         CRANES, HOISTS, AND MATERIALS HANDLING
A. 9.1     Cranes, Revolving, Main
Quantity :		3
Specification (API, etc.) :		Crane Design Code / Standard: FEM — “Rules for the design of Hoisting Appliances”, (1.001, 3rd edition 1998,

C-10

		10.01.). Classification Rule: ABS, Guide for Certification of Cranes, 2007
Make :		NOV OC4000KCE-(20-100)-(45-20)(30)
Type :		Knuckle Boom Crane
Location (stbd, port, aft, frwd) :		Fwd/Port, Fwd/stbd, Aft/Port
Boom length :		Main boom length = 30.613	m
		Knuckle boom length = 22.414	m
Hook reach below main deck (block/whip) :		250 / 125 / 50 m (1 fall / 2 fall / 5 fall)	m
Block capacities and hoisting speeds
Hoisting capacities:		Internal lift: 20 mtons at 45 m	mtons
		Internal lift: 100 mtons at 20 m	mtons
		Sea lift: 20 mtons at 42 m	mtons
		Sea lift: 100 mtons at 15 m	mtons
Maximum working radius (1 fall):		45.0	m
Minimum working radius (1 fall):		8.0	m
Hoisting speed:		60 m/min at full load	m/min
		100 m/min at reduced load, 1 fall	m/min
Whip capacity/hoist speed (ld/rad./spd) :		N/A
Luffing speed main boom:		70	sec
Luffing speed knuckle boom:		70	sec
Slewing speed:		0.65 RPM at 19-45 m working radius without load	RPM
		1.00 RPM at 8-19 m working radius without load	RPM
Slewing range:		360 deg unlimited	deg
Hook load indicator automatically corrected		Load indication system with display for actual and permitted load.
for boom angle :	yes/no:	Yes
Alarm (audible, visual, both) :		Both
Automatic brake :	yes/no:	Yes
Safety latch on hooks :	yes/no:	Yes
Crown saver (limit switch) :	yes/no:	Yes
Boom illumination :	yes/no:	Yes
Basket for personnel transfer :		Yes x2 Billy Pugh 904
Quantity :		1
Specification (API, etc.) :		ABS “Standard for Certification No. 2.22, Lifting Appliance, October 2008”
Make :		NOV OC4475KSCE-(30-165)-(50-17)(32)(20-50)AHC
Type :		Knuckle Boom Crane - Active Heave Compensated
Location (stbd, port, aft, frwd) :		Aft/stbd
Boom length :		164ft - 50m
Hook reach below main deck (block/whip) :	AHC block	12,000 - 3,660	ft - m
	Whip hoist	328 - 100	ft - m
Block capacities and hoisting speeds
Hoisting capacities:		Internal lift: 33 mtons at 50 m	mtons
		Internal lift: 165 mtons at 18 m	mtons
		Sea lift: 25 mtons at 50 m	mtons

C-11

		Sea lift: 165 mtons at 12 m	mtons
		Subsea lift: 25 mtons at 50 m	mtons
		Subsea lift: 165 mtons at 12 m	mtons
Minimum working radius:		8.0	m
Hoisting speed:		12 m/min at full load	m/min
		60 m/min at reduced load	m/min
		25 m/min at full load (boost mode)	m/min
Whip capacity/hoist speed (ld/rad./spd) :
Hoisting capacities:		Internal lift: 20 mtons at 50 m
		Sea lift: 20 mtons at 50 m
Minimum working radius:		8.0	m
Hoisting speed:		60 m/min at full load	m/min
		100 m/min at reduced load	m/min
Luffing speed:		100	sec
Slewing speed:		0 - 0.7	RPM
Slewing range:		360 deg unlimited	deg
Hook load indicator automatically corrected		Load indication system with display for actual and permitted load.
for boom angle :	yes/no:	Yes
Alarm (audible, visual, both) :		Both
Automatic brake :	yes/no:	Yes
Safety latch on hooks :	yes/no:	Yes
Crown saver (limit switch) :	yes/no:	Yes
Boom illumination :	yes/no:	Yes
Basket for personnel transfer :		Yes 2x total
		1 x Frog FS01
		1 x Billy Pugh X870
A. 9.2     Cranes, Revolving, Secondary
Quantity :		1x provision handling crane
Specification (API, etc.) :		DNV certified
Make :		Oriental
Type :		Electro-hydraulic single jib crane
Location (stbd, port, aft, frwd) :		Aft ship’s poop deck
Boom length :		About 20 m
Hook reach below main deck (block/whip) :		Waterline when the vessel is in normal ballast condition.
Block capacities and hoisting speeds
Lifting capacity:		20.0	mtons
Lifting / lowering speed:		~ 10.0	m/min
Whip capacity/hoist speed (ld/rad./spd) :		2.0	mtons
Hook load indicator automatically corrected
for boom angle :	yes/no:	N/A
Alarm (audible, visual, both) :		Both
Automatic brake :	yes/no:	Yes
Safety latch on hooks :	yes/no:	Yes
Crown saver (limit switch) :	yes/no:	Yes
Boom illumination :	yes/no:	Yes
Basket for personnel transfer :	yes/no:	Yes, Same as A.9.2

C-12

A. 9.3     Forklifts
Quantity :		1
Make/Type :		DOOSAN / B32S-5
Rated capacity :		3200	kg
Explosion proof :	yes/no:	Yes
A. 9.4     Monorail Overhead Cranes		Not Applicable
Quantity
Make
Type
Rated capacity
Location
A. 9.5     BOP Handling System
Crane
Make/Type		NOV BOP Gantry Crane
Rated capacity		2x 270 and 2x 35 auxiliary winches	mtons
Trolley
Make/Type		NOV BOP Trolley with integrated guidance system
Rated capacity		600	mtons
A. 9.6     Air Hoists/Derrick Winches
A. 9.6.1      Rig Floor Winches (Non man-riding)
Quantity	Drill floor	2
Make		Ingersol Rand FA5i/E10260A
Type		Air driven winch
Rated capacity		SWL 5,000 kg on top wire layer	kg
Wire length		110	m
Wire diameter		19	mm
Automatic brakes	yes/no:	Yes (auto internal disc brake)
Overload protection	yes/no:	No
Automatic spooling	yes/no:	No (only drum guard)
Quantity	Drill floor	2
Make		Ingersoll Rand FA101A-24XK1G
Type		Air driven winch
Rated capacity		SWL 10,000 kg on top wire layer	kg
Wire length		140	m
Wire diameter		19	mm
Automatic brakes	yes/no:	Yes- Auto disc brake
Overload protection	yes/no:	No
Automatic spooling	yes/no:	No

C-13

A. 9.6.2      Monkey Board Work Winch
Quantity		2
Make		Ingersol Rand FA2i/E10260
Type		Air driven winch
Rated capacity		SWL 2,000 kg on top wire layer	kg
Wire length		50	m
Wire diameter		13	mm
Automatic brakes	yes/no:	Yes (auto internal disc brake)
Overload protection	yes/no:	Yes (gearbox protection)
Automatic spooling	yes/no:	Yes (drum guard)
A. 9.6.3      Rig Floor “Man-Riding” Winch
Quantity	Drill Floor	2
Make		Ingersol Rand FA150KGI-MR12A1-H-CE
Type		Pneumatic
Rated capacity		150 kg SWL at top layer	kg
Wire length		250 m non rotating wire rope	m
Wire diameter		10	mm
Non-twist wire	yes/no:	Yes
Automatic brakes	yes/no:	Yes
Overload protection	yes/no:	Yes
Automatic spooling	yes/no:	Yes
Certified for man-riding	yes/no:	Yes
A. 9.6.4      Utility Winch (i.e. Deck Winch)		N/A
Quantity
Make
Type
Rated capacity			metric tonnes
Wire diameter			millimeters
Automatic brakes	yes/no:
Overload protection	yes/no:
Automatic spooling	yes/no:
Certified for man-riding	yes/no:
A. 9.6.5      Moonpool area “Man riding” winches
Quantity		2
Make		Ingersol Rand FA150KGI-MR12A1-H-CE
Type		Pneumatic
Rated capacity		150 kg SWL at top layer	kg
Wire length		250 m non rotating wire rope	m
Wire diameter		10	mm
Non-twist wire	yes/no:	Yes

C-14

Automatic brakes	yes/no:	Yes
Overload protection	yes/no:	Yes
Automatic spooling	yes/no:	Yes
Certified for man-riding	yes/no:	Yes
A. 9.6.6      Moonpool area “Non-man riding” winches
Quantity		4
Make		Ingersol Rand FA5i/E10260A
Type		Air driven winch
Rated capacity		SWL 5,000 kg on top wire layer	kg
Wire length		110	m
Wire diameter		19	mm
Automatic brakes	yes/no:	Yes (auto internal disc brake)
Overload protection	yes/no:	Yes
Automatic spooling	yes/no:	Yes (drum guard)
A. 9.6.7      Palfinger crane
Quantity :		4
Specification (API, etc.) :		BIM 150188133
Make :		TMW AK 30 LE4
Type :		foldable knuckleboom crane (hydraulic)
Location (stbd, port, aft, frwd) :		2x moonpool, 2x rig floor
Boom length :		15	meters
Hook reach below main deck (block/whip) :		N/A
Block capacities and hoisting speeds		N/A
Load/radius/speed (minimum radius) :
Load/radius/speed (maximum radius) :		930kg @ 15 meters
Whip capacity/hoist speed (ld/rad./spd) :		N/A
Hook load indicator automatically corrected		N/A
for boom angle :	yes/no:	N/A
Alarm (audible, visual, both) :		Both
Automatic brake :	yes/no:	Yes
Safety latch on hooks :	yes/no:	N/A
Crown saver (limit switch) :	yes/no:	N/A
Boom illumination :	yes/no:	N/A
Working Manriding Basket		Yes
A.10       HELICOPTER LANDING DECK
Location		FWD Above Accomodations Deck
Dimensions		22 x 22	m
Perimeter safety net	yes/no:	yes
Load capacity
Designed for helicopter type		Sikorsky S61N and S92
Tie down points	yes/no:	yes
Covered by foam fire system	yes/no:	yes
Heli-refueling system type		Helifuel AS System - Dispensing unit with 2 transportable tanks (includes Foam deluge system)

C-15

Fuel storage capacity		2x tanks (2900L) - 766 Gal each
Helideck lighting to aviation specification
as required by country of operation	yes/no:	CAP 437 (2008)
A.10.1    Helicopter Refueling System
Fuel storage capacity		2x tanks (2900L) - 766 Gal each	Gal
Jettisonable	yes/no:	Yes
Fuel transport containers		Yes
Volume (ea)		766	Gal
Covered by foam fire system	yes/no:	Yes
A.11       AUXILIARY EQUIPMENT
A.11.1    Water Distillation
Quantity		3
Make/Type		Dongwha Entec / DH-SAL-01
Capacity (each/total)		60 m3 / day
A.11.2    Boilers
Quantity		None
Make/Type
Capacity (total system)
A.11.3    Air Conditioning
Quantity		2
Make/Type		Hi Air Korea
Capacity (total system)		2,177	kW
A.11.4    Electric Welding Sets
Quantity		4
Current capacity		400	amps
Make/Model		Unitor UWI 400
Type	fixed/portable:	Portable
Quantity		2
Current capacity		N/A
Make/Model		oxy acetylene gas
Type	fixed/portable:
Quantity
Current capacity
Make/Model
Type	fixed/portable:

C-16

A.11.5    High Pressure Cleaner
Quantity		1
Make/Type		Wilhelmsen Marine / TBD
Electric/pneumatic/diesel		electric
Max delivered pressure		120 -160	Bar/ L/Min
B.            GENERAL RIG SPECIFICATIONS
B.1          DERRICK AND SUBSTRUCTURE
B.1.1.     Derrick/Mast
Make/Type		NOV DDBN-1250/750 60x80x210
Rated for wind speed:
Operating condition (1,587 mt - 1,750 st setback load)		38.2 - 63.75 (3 sec gusts)	m/s - knots
Survival condition (1,134 mt - 1,250 st setback load)		59.5 - 115.65 (3 sec gusts)	m/s - knots
Height		210	ft.
Dimensions of base		60 x 80	ft.
Dimensions of crown		60 x 22	ft.
Gross nominal capacity		2,000 - 4,000,000 (combined)	stons - lbs
		1,250 - 2,500,000 (main)	stons - lbs
		750 - 1,500,000 (aux)	stons - lbs
Maximum Number of lines		16 lines - 2,500,000 pounds (main)
		14 lines - 1,500,000 pounds (aux)
Ladders with safety cages and rests	yes/no:	Yes
Platform for crown sheave access	yes/no:	Yes
Counter balance, system for rig tongs and pipe spinning tong	yes/no:	Yes
Lighting system explosion proof	yes/no:	Yes
B.1.2      Racking Platform
Make/Type		NOV FB-A Adjustable Fingerboard
Racking platform capacity of 6-5/8” DP		375 total	stds
Dedicated Landing String 6-5/8”		150 of mentioned above 375	stds
Racking platform capacity of 6-5/8” HWDP		20 x 135 ft	stds
Racking platform capacity of 9-3/4” DC		-	stds
Racking platform capacity of 9-1/2” DC		10 x 8 - 1/4 to 9-1/2	stds
Racking platform capacity of 8-1/4” DC		6 x 120 ft	stds
Racking platform capacity of 6-3/4” DC		16 x 120 ft	stds
Racking platform capacity of 9.1/2” - 17” BHA		4	stds
Racking platform capacity of 14” Casing (Condition 1)		84 x 141 ft	stds
Racking platform capacity of 9.5/8” Casing (Condition 2)		98 x 141 ft	stds
Racking platform capacity of 7” Casing (Condition 3)		98 x 141 ft	stds
Racking platform capacity of 5” Casing (Condition 4)		98 x 141 ft	stds
		Note: conditions shown are mutually exclusive
B.1.3      Racking Arm

C-17

Quantity		2
Make/Type		NOV Hydraracker IV-ER
B.1.4      Casing Stabbing Board		Will use Palfinger crane with working basket as needed
Quantity		See Palfinger
Make/Type
Adjustable from/to height above rotary
B.1.5      Substructure
Make/Type		HHI / MSC Gusto
Height (above main deck)		17,400 - 57.1	mm - ft
Length		25,600mm-83.9ft (Drill floor deck 29,750mm-97.6ft)	mm - ft
Width		26,750mm-87.7ft (Drill floor deck 29,586mm-97.0ft)	mm - ft
Setback capacity (operating condition)		1,750 - 1,587	stons - mtons
Simultaneous setback + hookload capacity		3,750 - 3,401	stons - mtons
Clear height below R/table beams		35,700 - 117.1	mm - ft
B.1.6      Weather Proofing
Rig floor windbreaks height		4,500 - 14.8	mm - ft
Derrickman windbreaks height		6,096 - 20	mm - ft
B.1.7      Derrick TV Camera System
Camera located at		Various - 12 cameras
Make/Type		Hernis EEx for zone1
Zoom/Pan/Tilt-function	yes/no:	Yes
Monitor located at		Various Locations
B.2          DRAWWORKS AND ASSOCIATED EQUIPMENT
B.2.1      Drawworks
Make/Type	Main	NOV AHD-1250-9000-70-100-10.5-FMM-NE-CLAC
Motors make/type		General Electric B28A3 AC Drilling Motor
Quantity		6
Rated input power continuous		N/A	HP - KW
Rated output power continuous		9,000 - 6,712	HP - KW
Rated input power maximum		N/A	HP - KW
Rated output power maximum		12,600 - 9,396	HP - KW
Drum type		The drum is mounted directly to the main drive shaft and is dynamically balanced; a two-piece removable Lebus grooving sleeve is bolted to the

C-18

		drum bottom and welded together.
Drum diameter		70 - 1,778	Inches - mm
Drill line diameter		2-1/8	Inches
Maximum line pull 16 lines		1,250 - 1,134 (16 lines, 2nd layer)	stons - mtons
Maximum line pull 14 lines		1,094 - 992 (14 lines, 2nd layer)	stons - mtons
Maximum line pull 12 lines		N/A	stons - mtons
Maximum line pull 10 lines		N/A	stons - mtons
Maximum line pull 8 lines		N/A	stons - mtons
Spinning cathead type		N/A
Breakout cathead type		N/A
Crown block safety device make/type		The drawworks control system software includes dynamic floor and crown saver system (KEMS).
Independent fresh water cooling system for drawworks and electric brake	yes/no:	Yes
Make/Type	Aux	NOV AHD-750-5750-63-82-10.5-CLAC
Motors make/type		General Electric B22A3 AC Drilling Motor
Quantity		5
Rated input power continuous		N/A	HP - KW
Rated output power continuous		5,750 - 4,288	HP - KW
Rated input power maximum		N/A	HP - KW
Rated output power maximum		8,050 - 6,003	HP - KW
Drum type		The drum is mounted directly to the main drive shaft and is dynamically balanced, a two piece removable Lebus grooving sleeve is bolted to the drum bottom and weekend together.
Drum Diameter		63 - 1,600	Inches - mm
Wire diameter		1-3/4	Inches
Maximum line pull 14 lines		750 - 680 (14 lines, 2nd layer)	stons - mtons
Maximum line pull 12 lines		N/A	stons - mtons
Maximum line pull 10 lines		N/A	stons - mtons
Maximum line pull 8 lines		N/A	stons - mtons
Spinning cathead type		N/A
Breakout cathead type		N/A
Crown block safety device make/type		The drawworks control system software includes dynamic floor and crown saver system (KEMS).
Independent fresh water cooling system for drawworks and electric brake	yes/no:	Yes
B.2.2Auxiliary Brake		N/A
Make
Model
Independent back-up system type
B.2.3Sandline		None
Make

C-19

Length capacity
Line size/type
Breaking strength
Safe working load
B.2.4Wireline		None
Make
Length capacity
Line size/type
Breaking strength
Safe working load
B.2.5Automatic Driller
Make/Type		N/A
B.3DERRICK HOISTING EQUIPMENT
B.3.1Crown Block
Make/Type	Main	NOV
Rated capacity		1,250	stons
No. of sheaves		8
Sheave diameter		78 - 1,981	Inches - mm
Sheave grooved for line size		2-D11351/8	Inches
Make/Type	Aux	NOV
Rated capacity		750	stons
No. of sheaves		7
Sheave diameter		68 - 1,727	Inches - mm
Sheave grooved for line size		1-3/4	Inches
B.3.2Travel Block
Make/Type	Main	NOV 878TB1250
Rated capacity		1,250	stons
No. of sheaves		8
Sheave diameter		78	Inches
Sheave grooved for line size		2 1/8	Inches
Make/Type	Aux	NOV 768TB750
Rated capacity		750	stons
No. of sheaves		7
Sheave diameter		68	Inches
Sheave grooved for line size		1 3/4	Inches
B.3.3Hook		N/A (non-split type traveling blocks)

C-20

Make/Type
Rated capacity
Complete with spring assembly/hook locking device	yes/no:
B.3.4Swivel		N/A
Make/Type
Rated capacity
Test/working pressure
Gooseneck and wasHPipe minimum ID >= 76mm	yes/no:
Left hand pin connection size
Access fitting for wireline entry on top of gooseneck	yes/no:
B.3.5Drilling Line
Diameter	Main	2-1/8	Inches
Type		Bridon
Length (original)		12,000 - 3,658	ft - m
Support frame for drum/cover	yes/no:	Yes
Drilling line drum power driven	yes/no:	Yes
Spare reel drilling line	yes/no:	No
Location (rig, shore, etc.)
Diameter	Aux	1 3/4	Inches
Type		Bridon
Length (original)		12,000 - 3,658	ft - m
Support frame for drum/cover	yes/no:	Yes
Drilling line drum power driven	yes/no:	Yes
Spare reel drilling line	yes/no:	No
Location (rig, shore, etc.)
B.3.6Anchor Dead Line
Make/Type	Main	NOV FRH-280-C-8C-R-PVF Rotary Deadline Anchor
Weight sensor	yes/no:	Yes
Make/Type	Aux	NOV FRH-160-C-8C-R-PVF Rotary Deadline Anchor
Weight sensor	yes/no:	Yes
B.3.7Drilling String Motion Compensator	Main	NA
Make/Type
Stroke
Capacity - compensated
Capacity - locked
B.3.8Block Guidance System

C-21

Make/Type	Main	Guide rails of W14 x 132 beams / 105,000 ft.lbs of torque / 108 x 115 setback
	Aux	Guide rails of W14 x 120 beams / 63,000 ft.lbs of torque / 91 x 108 setback
B.3.9Retraction System For Traveling Block
Make/Type	Main	NOV - Uni-dolly of 53” retract for top drive and traveling block
	Aux	Fixed dolly
B.4ROTATING SYSTEM
B.4.1Rotary Table
Make/Type	Main	NOV VBJ RST 755
Maximum opening		75-1/2	Inches
Rated capacity		1,375 - 1,250	stons - mtons
Static load capacity		1,375 - 1,250	stons - mtons
Rotating load capacity			stons - mtons
Two speed gearbox	yes/no:	No
Emergency chain drive	yes/no:	No
Driven by an independent electric motor	yes/no:	N/A (hydraulic operated)
Electric motor type/make		N/A (hydraulic operated)
Output power		N/A (hydraulic operated)
Maximum continuous torque		45,000 ft.lbs generated / 120,000 ft-lbs maximum back-up torque on mechanical locks
Drip pan/mud collection system	yes/no:	Yes
Make/Type	Aux	NOV VBJ RST 605
Maximum opening		60-1/2	Inches
Rated capacity		1,000 - 907	stons - mtons
Static load capacity		1,000 - 907	stons - mtons
Rotating load capacity			stons - mtons
Two speed gearbox	yes/no:	No
Emergency chain drive	yes/no:	No
Driven by an independent electric motor	yes/no:	N/A (hydraulic operated)
Electric motor type/make		N/A (hydraulic operated)
Output power
Maximum continuous torque		45,000 ft.lbs generated / 120,000 ft-lbs maximum back-up torque on mechanical locks
Drip pan/mud collection system	yes/no:	Yes
B.4.2Master Bushings
Make/Type	Main	Split lockable with adapters for 75 1/2 inch
Inserts bowls (see G.1.7)		As for above

C-22

Make/Type	Aux	Split lockable with adapters for 60 1/2 inch
Inserts bowls (see G.1.7)		As for above
B.4.3Kelly Bushing
Make/Type		N/A
Lock down assembly	yes/no:
B.4.4Top Drive
Make	Main	NOV TDX-1250
Type (electric/hydraulic)		Electric (dual AC motors)
Rated capacity		Hoisting = 1,250 stons, API-8C, PSL-1	stons
		Drilling (rotating) = 1,236 stons, API-8C	stons
Water course test/working pressure		7,500	psi
Water course opening		4	Inches
If driven by electric motor
Make/Type		2x Reliance TE / WC 1340, AC - Motors
Output power		2x 1,340 = 2,680	HP
Maximum continuous drilling torque		105,000 ft.lbs at 130 RPM	ft.lbs
Maximum intermittent drilling torque		150,000 ft.lbs at stall
Break-out torque (static locking brake)		150,000 ft.lbs	ft.lbs
Two speed gearbox	yes/no:	No
Maximum rotary speed		0 to 250 RPM continuous	RPM
Remote operated kelly cock	yes/no:	Remote operated dual ball IBOP + manual IBOP
Cooling system type		Water cooled AC induction drilling motors
Make	Aux	NOV-TDS-8SA
Type (electric/hydraulic)		Electric AC
Rated capacity		750	Short Tons
Test/working pressure		7,500	psi
If driven by electric motor
Make/Type		1x GEB-20A1
Output power		1,150	HP
Maximum continuous torque		62500 at 95 RPM	ft.lbs
Maximum intermittent drilling torque		95,000 ft.lbs at stall	ft.lbs
Two speed gearbox	yes/no:	no
Maximum rotary speed		270	RPM
Remote operated kelly cock	yes/no:	Remote operated dual ball IBOP + manual IBOP
Cooling system type		Local intake blower
B.4.4.1Top Drive Makeout/Breakout System
Make	Main	NOV TDX-1250

C-23

Model		PH-150
Type		The system utilizes a dual torque post design providing back-up torque for making and breaking tubular connections at the top drive
Max. breakout torque that can be applied by system		150,000	ft.lbs
Make	Aux	NOV TDS 8
Model		PH-100
Type		The system utilizes a dual torque post design providing back-up torque for making and breaking tubular connections at the top drive
Max. breakout torque that can be applied by system		100,000	ft.lbs
B.4.5Powered Mousehole
Quantity		1
Make / Model		NOV MHP - 15 - 15.5 x 95
Capacity		15	mtons
Opening		15.5	Inches
Length		95	ft
B.4.6Rotary Sock
Quantity		1
Make / Model		NOV
Capacity		Shock absorbing element designed for a 27,000 lb x 9.1/2 in drill collar dropped from a height of 96 ft.
Opening		22	Inches OD
Length		total length ≈106	ft
		working length ≈ 90	ft
C.POWER SUPPLY SYSTEMS
C.1RIG POWER PLANT
C.1.1Diesel Engines
Quantity		6
Make/Type		HHI Himsen 16H32 / 40V
Maximum continuous power		8,000	KW
At rotation speed of		720	RPM
Equipped with spark arrestors	yes/no:	Yes
Mufflers installed	yes/no:	Yes
Emissions Standard		Tier 2 & 3 compliant for NOx
C.1.2DC - Generator		N/A
Quantity

C-24

Make/Type
Continuous power
At rotation speed of
Output volts
C.1.3      AC-Generator
Quantity	6
Make/Type	ABB / HHI EES HAJ7 187-10P
Continuous power	7600 @0.8 factor	KW
At rotation speed of	720	RPM
Output volts	11	kV
Frequency	60	Hz
C.1.4      Drilling VFD System
Number of VFD’s	24 AC VFD Drives
Make/Type	ABB / ACS800-107LC-1370-7
Maximum continuous power (total)	18,000 / 28,770	KW/KVA
Output volts	690	VAC
C.1.5      Transformer System
Quantity - Thrusters	6
Make/Type	ABB / Transfor SA TGT FS 4M5M/G / Dry type cast resin AF/WF cooled
Continuous power (each)	5800	KVA
Output volts	1.732 / 1.731	VAC
Frequency	60	Hz
Quantity-Drilling Drives	4
Make/Type	ABB RESIBLOC dry type Marine Transformer. Cast resin AF/WF Cooling
Continuous power (each)	4500	KVA
Output volts	729 / 730	VAC
Frequency	60	Hz
Quantity - 480 Volt Switchbobards Aft	6
Make/Type	ABB RESIBLOC dry type Marine Transformer. Cast resin AF/WF Cooling
Continuous power (each)	2500	KVA
Output volts	480	VAC
Frequency	60	Hz
Quantity - 480 Volt Switchbobards FWD	2
Make/Type	ABB RESIBLOC dry type Marine Transformer. Cast resin AF/WF Cooling
Continuous power (each)	2500	KVA

C-25

Output volts		480	VAC
Frequency		60	Hz
Quantity - 480 Volt Switchbobards -Drilling		4
Make/Type		ABB RESIBLOC dry type Marine Transformer. Cast resin AF/WF Cooling
Continuous power (each)		2500	KVA
Output volts		480	VAC
Frequency		60	Hz
Quantity - Aft LV Switchboards		6
Make/Type		HHI EES / Dry type
Continuous power (each)		100	KVA
Output volts		208/120	VAC
Frequency		60	Hz
Quantity - Topside LV Switchboards		4
Make/Type		HHI EES / Dry type
Continuous power (each)		100	KVA
Output volts		208	VAC
Frequency		60	Hz
Quantity - Fwd LV Switchboards		4
Make/Type		HHI EES / Dry type
Continuous power (each)		180	KVA
Output volts		208	VAC
Frequency		60	Hz
Quantity - Emergency Switchboard		1
Make/Type		HHI EES / Dry type
Continuous power (each)		300	KVA
Output volts		208	VAC
Frequency		60	Hz
C.1.6      Emergency Shutdown
Emergency shutdown switches for the complete power system		Bridge and Engine Control Room
(AC and DC), located at the following points
C.1.7      Auxiliary Power Supply
Power supply for a mud logging unit	yes/no:	Yes
Power supply available:		480
Output volts		480
Frequency		60
Current		100
Phase	single/three:	3

C-26

C.1.8      Compressed Air Systems
Air Compressors - Service Air System
Quantity	4
Make	TAMROTOR MARINE COMPRESSORS AS
Model	TMC 235-13 EWNA (water cooled)
Rated capacity	1,560	m3 / hour
Working press	12	bar
Prime mover (electric/diesel)	Electric
Continuous power	230	kW
Air dryers	Kyung Nam Dryers
Quantity	1 per unit
Make/Type	KADM - 2000 W	Watts
Rated Capacity	1,560	m3 / hour
Air Compressors - Instrument / Control Air System	From Service Air System (above)
Quantity
Make
Model
Rated capacity		m3 / hour
Working press		bar
Prime mover (electric/diesel)
Continuous power
Air dryers	Kyung Nam Dryers
Quantity	1 per unit
Make/Type	KHDMH - 600
Rated Capacity	557	m3 / hour
Air Compressors - Main Engine Start / Direct Injection System
Quantity	6 (2 per engine room)
Make	Sperre Air Compressor
Model	XW090
Rated capacity	85-100	m3 / hour
Working press	25-30	bar
Prime mover (electric/diesel)	Electric
Continuous power	23	kW
Air dryers
Quantity	3 (one per engine room)
Make/Type
Rated Capacity		m3 / hour
Air Compressors - Emergency Gen. Start Air System
Quantity	1
Make	Sperre Air Compressor
Model	HL2/90
Rated capacity	34	m3 / hour
Working press	30	bar
Prime mover (electric/diesel)	Diesel
Continuous power	11	kW
Air dryers
Quantity	1

C-27

Make/Type	Vertical
Rated Capacity	34	m3 / hour
Air Compressors - Bulk Air System (Independent)	The Service Air System shall be connected to the bulk air system and supply air in case of pressure drop below the setting point
Quantity	1
Make	TAMROTOR MARINE COMPRESSORS AS
Model	TMC 235-13 EWNA (water cooled)
Rated capacity	1,560	m3 / hour
Working press	12	bar
Prime mover (electric/diesel)	Electric
Continuous power	230	kW
Air dryers
Quantity	1 per unit
Make/Type	dessicant
Rated Capacity	1,560	m3 / hour
Air Compressors - Riser Tensioning System
Quantity	3
Make	NOV
Model
Rated capacity	138	m3 / hour
Working press	300	bar
Prime mover (electric/diesel)	Electric
Continuous power	55	kW
Air dryers
Quantity	4 per unit
Make/Type	Dessicant tower
Rated Capacity	138	m3 / hour
Air Compressors - Breathing Air System
Quantity	2
Make
Model
Rated capacity	27	m3 / hour
Working press	207-220	bar
Prime mover (electric/diesel)	Electric
Continuous power
Air dryers
Quantity
Make/Type
Rated Capacity		m3 / hour
C.2          EMERGENCY GENERATOR
C.2.1      Engine
Quantity	1
Make/Type	STX Cummins QSK60DMGE

C-28

Maximum output		1,900	KW
At rotation speed		1,800	RPM
Starting methods (automatic, manual, air/hydraulic)		Electric battery starting and air backup
Max. angle of operation		10 degrees fore/aft and 30 degrees athwartships
C.2.2      AC-Generator
Quantity		1
Make/Type		Cummins PM734G1 1500[kW]
Maximum output		1,500	KW
At rotation speed		1,800	RPM
Output volts		480	volts
Capable of back-feeding power to main bus	yes/no:	Yes
C.3          PRIMARY ELECTRIC MOTORS
C.3.1      Propulsion Motors
Quantity		N/A - see Thruster Motors
Type (AC/DC)
Power each
Total power
C.3.2      Thruster Motors
Quantity		6
Type (AC/DC)		ABB, AMI 710L8L VATFMV
Power of each		rated output 5,000	KW
Total power		30,000	KW
C.3.3      Drilling Motors
Quantity		24
Type (AC/DC)		AC
Power of each		850	KW
Total power		20,400	KW
C.3.4      Mooring Winch Motors
Quantity		2 FWD
Type (AC/DC)		ElectricPole change - AC
Power of each		82	KW
Total power
D.          DRILLSTRING EQUIPMENT

C-29

		NOTE: Rowan Specification. Company requested changes to the specification to be agreed by Variation Order
D.1          TUBULARS
D.1.1      Kellys		N/A
Quantity
Nominal size OD
Shape type (hexagonal, square or triangular)
Total/working length
Connection type
API classification
D.1.2      Kelly Saver Subs		N/A
Quantity
Nominal kelly size
Connection type
API classification
Protector	yes/no:
D.1.3      Drill Pipe
		5” S135 - 0.362” WT
Drill pipe OD		5	in
Grade		S135
Total length		10,000	ft
Range		2
Weight		24.62	lbs/ft
Internally plastic coated	yes/no:	Yes - TK34XT
Tool joint OD/ID		6.625 / 3.75	in
Tool joint pin length (original)		11	in
Tapered shoulder tool joints	yes/no:	Yes-18 degrees
Connection type		XT50
Type of hardfacing		TCS Ti - 3/32” (3” on box, 1-1/2” on pin)
API classification		New
Thread protectors	yes/no:	Drill-Tech or MSI Magnum
		5-7/8” S135 - 0.361” WT
Drill pipe OD		5-7/8	in
Grade		S135
Total length		6,000	ft
Range		3
Weight		25.9	lbs/ft
Internally plastic coated	yes/no:	Yes - TK34XT
Tool joint OD/ID			7.25 in -4
Tool joint pin length (original)		15	in
Tapered shoulder tool joints	yes/no:	Yes-18 degrees
Connection type		XT57

C-30

Type of hardfacing		TCS Ti - 3/32” (3” on box, 1-1/2” on pin)
API classification		New
Thread protectors	yes/no:	Drill-Tech or MSI Magnum
		6-5/8” S135 - 0.362” WT
Drill pipe OD		6-5/8	in
Grade		S135
Total length		10,000	ft
Range		3
Weight		29.63	lbs/ft
Internally plastic coated	yes/no:	Yes - TK34XT
Tool joint OD/ID		8 - 4-3/4	in
Tool joint pin length (original)		14	in
Tapered shoulder tool joints	yes/no:	Yes-18 degrees
Connection type		6 5/8 FH
Type of hardfacing		TCS Ti - 3/32” (3” on box, 1-1/2” on pin)
API classification		New
Thread protectors	yes/no:	Drill-Tech or MSI Magnum
		6-5/8” S135 - 0.522” WT
Drill pipe OD		6-5/8	in
Grade		S135
Total length		12,000	ft
Range		3
Weight		42.42	lbs/ft
Internally plastic coated	yes/no:	Yes - TK34XT
Tool joint OD/ID		8.375 - 4.5	in
Tool joint pin length (original)		14	in
Tapered shoulder tool joints	yes/no:	Yes-18 degrees
Connection type		6 5/8 FH
Type of hardfacing		TCS Ti - 3/32” (3” on box, 1-1/2” on pin)
API classification		New
Thread protectors	yes/no:	Drill-Tech or MSI Magnum
		6-5/8” V150 - 0.688” WT
Drill pipe OD		6-5/8	in
Grade		V150
Total length		12,000	ft
Range		3
Weight		52.81	lbs/ft
Internally plastic coated	yes/no:	Yes - TK34XT
Tool joint OD/ID		8.375 - 4.25	in
Tool joint pin length (original)		15	in
Tapered shoulder tool joints	yes/no:	Yes-18 degrees
Connection type		6 5/8 FH
Type of hardfacing		TCS Ti - 3/32” (3” on box, 1-1/2” on pin)
API classification		New
Thread protectors	yes/no:	Drill-Tech or MSI Magnum

C-31

Landing String
Drill Pipe		6-5/8” UD165 - 0.750WT Slip-Proof
Length		6,996	ft
Drill Pipe		6-5/8” UD165 - 0.938WT Slip-Proof
Length		6,000	ft
D.1.4      Drill Pipe Pup Joints
Grade		5-7/8” OD X 4.0” ID
Length		5	ft
Quantity		2
Length		10	ft
Quantity		2
Length		15	ft
Quantity		2
Length		20	ft
Quantity		2
Connection type		XT 57
Internally plastic coated	Yes	TK 34 XT
Thread protectors	yes	Drilltec Plastic HD
Grade		6.906” OD X 3.5” ID
Length		5	ft
Quantity		2
Length		10	ft
Quantity		2
Length		15	ft
Quantity		2
Length		20	ft
Quantity		2
Connection type		6 5/8 FH
Internally plastic coated	Yes	TK 34 XT
Thread protectors	yes	Drilltec Plastic HD
D.1.5      Drill Pipe Casing Protectors		As required
Initial stock
Make/Type
OD
Installation tools (manual hydraulic/none)	yes/no:	Yes, Manual
D.1.6      Heavy-Wate Drill Pipe (e.g. Hevi-Wate)
Spiral HWDP		5-7/8” OD X 4.0” ID
Quantity		40	Joints
Nominal size OD		5 7/8
Weight		59.6
Range		2

C-32

Tool joint OD/ID		7” OD x 4” ID
Type of hardfacing		TCS Ti
Internally plastic coated		None
Connection type		XT 57
Thread protectors	yes	Drilltec Plastic HD
Spiral HWDP		6-5/8” OD X 4.5” ID
Quantity		40	Joints
Nominal size OD		6 5/8
Weight		76.5
Range		2
Tool joint OD/ID		8 1/2 OD x 4 1/2 ID
Type of hardfacing		TCS Ti
Internally plastic coated		None
Connection type		6 5/8 FH
Thread protectors		Drilltec Plastic HD
Spiral HWDP		5” OD X 2-3/4” ID
Quantity		48	Joints
Nominal size OD		5
Weight		52.3
Range		2
Tool joint OD/ID		5 1/4 OD x 2 3/4 ID
Type of hardfacing		TCS Ti
Internally plastic coated	no	None
Connection type		XT 50
Thread protectors	yes	Drilltec Plastic HD
D.1.7      Drill Collars
Drill Collars		9-1/2” OD X 3” ID
Quantity		12	Joints
Nominal Length of each joint		31	ft
Drill collar body (slick/spiral)		Spiral
Recess for “zip” elevator		-
Recess for slips		Yes
Stress relief pin groove		Yes
Boreback on box		Yes
Connection type		7 5/8 API regular
Drill Collars		8-1/4” OD X 2-13/16” ID
Quantity		24	Joints
Nominal Length of each joint		31	ft
Drill collar body (slick/spiral)		Spiral
Recess for “zip” elevator		-
Recess for slips		Yes
Stress relief pin groove		Yes
Boreback on box		Yes
Connection type		6 5/8 API regular
Drill Collars		6-3/4” OD X 2-13/16” ID
Quantity		24	Joints
Nominal Length of each joint		31	ft

C-33

Drill collar body (slick/spiral)		Spiral
Recess for “zip” elevator		-
Recess for slips		Yes
Stress relief pin groove		Yes
Boreback on box		Yes
Connection type		XT 50
D.1.8      Short Drill Collars		None
Quantity
OD body
ID body
Nominal Length of each joint
Stress relief pin groove	yes/no:
Boreback on box	yes/no:
Connection type
D.1.9      Non-Magnetic Drill Colars		None
Quantity
OD body
ID body
Nominal length of each joint
Drill collar body (slick/spiral)
Recess for “zip” elevator	yes/no:
Recess for slips	yes/no:
Stress relief pin groove	yes/no:
Boreback on box	yes/no:
Connection type
D.1.10    Core Barrels		None
Quantity
Make
Model
Size OD x ID
Length
Top connection Type
Spiral stabilizing ribs	yes/no:
Subs and handling tools	yes/no:
D.1.11    Stabilizers		None
Hole size
Quantity
Make
OD blades

C-34

Type blades (straight/spiral/welded/integral/sleeve)
Type of blade hardfacing
OD body or fishing neck
ID body
Connection type
Float valve receptacle	yes/no:
Hole size
Quantity
Make
OD blades
Type blades (straight/spiral/welded/integral/sleeve)
Type of blade hardfacing
OD body or fishing neck
ID body
Connection type
Float valve receptacle	yes/no:
Hole size
Quantity
Make
OD blades
Type blades (straight/spiral/welded/integral/sleeve)
Type of blade hardfacing
OD body or fishing neck
ID body
Connection type
Float valve receptacle	yes/no:
Hole size
Quantity
Make
OD blades
Type blades (straight/spiral/welded/integral/sleeve)
Type of blade hardfacing
OD body or fishing neck
ID body
Connection type
Float valve receptacle	yes/no:
D.1.12    Roller Reamers		None
Hole size
Quantity
Make
OD body
ID body
OD fishing neck
Cutters, supplied sets
Cutters, type
Connection, type

C-35

Hole size
Quantity
Make
OD body
ID body
OD fishing neck
Cutters, supplied sets
Cutters, type
Connection, type
Hole size
Quantity
Make
OD body
ID body
OD fishing neck
Cutters, supplied sets
Cutters, type
Connection, type
D.1.13    Shock Absorbers (Damping Sub)	None
Quantity
Make/Type
OD body
ID body
OD fishing neck
Connection type
Quantity
Make/Type
OD body
ID body
OD fishing neck
Connection type
D.1.14    Drilling Jars	None
Quantity
Make
Type (mechanical/hydraulic; up/down)
OD body
Min. ID body
OD fishing neck
Stroke
Connection type
Quantity
Make
Type (mechanical/hydraulic; up/down)
OD body

C-36

Min. ID body
OD fishing neck
Stroke
Connection type
Quantity
Make
Type (mechanical/hydraulic; up/down)
OD body
Min. ID body
OD fishing neck
Stroke
Connection type
D.1.15    Inside BOP Valve
	DP Safety V/V (TIW) 6- 5/8 FH PxB 8.25 O.D 15K PSI
Quantity	2
Make	Packard Intl.
OD	8 1/4
For pipe:	6 -5/8 DP
Min. drill pipe ID required
Connection type	6- 5/8 FH
Working pressure rating	15k	PSI
	DP Safety V/V (TIW) XT 57 PxB 7.375 O.D 15K PSI
Quantity	3
Make	Packard Intl.
OD	7 3/8
For pipe:	5 -7/8 DP
Min. drill pipe ID required
Connection type	XT 57
Working pressure rating	15k	PSI
	DP Safety V/V (TIW) XT 50 PxB 5.5 O.D 15K PSI
Quantity	2
Make	Packard Intl.
OD	5 1/2
For pipe:	5 DP
Min. drill pipe ID required
Connection type
Working pressure rating	15k	PSI
D.1.16    Fast Shut-Off Coupling	N/A
Make/Type
Quantity
Size tooljoint to fit

C-37

D.1.17Circulation Head		None
Quantity
Make/Type
Valve make
Valve type
Valve size (ID)
Valve working pressure
Bottom connection type
Top connection type
Wireline stripper	yes/no:
Quantity
Make/Type
Valve make
Valve type
Valve size (ID)
Valve working pressure
Bottom connection type
Top connection type
Wireline stripper	yes/no:
D.1.18Side Entry Subs
Quantity		2	Each
For OD DC		For 5-7/8” Drill Pipe
Connection type		XT 57
Quantity		2	Each
For OD DC		For 6-5/8” Drill Pipe
Connection type		6 5/8 FH
D.1.19Kelly Cocks		N/A
Upper
Quantity
Make/Type
Working pressure
Max. OD body
Min. ID body
Connection type
Quantity
Make/Type
Working pressure
Max. OD body
Min. ID body
Connection type
Lower

C-38

Quantity
Make/Type
Working pressure
Max. OD body
Min. ID body
Connection type
Quantity
Make/Type
Working pressure
Max. OD body
Min. ID body
Connection type
D.1.20Circulation Subs
Quantity	2
Make/Type	Circ Sub 6- 5/8 FH Pin x 2” WECO, 24” L	6 -5/8 DP
OD body
Ball size
Dressing kits
Connection type	6- 5/8 FH Pin
Quantity	2
Make/Type	Circ Sub XT 57 Pin x 2” WECO, 24” L	5 -7/8 DP
OD body
Ball size
Dressing kits
Connection type	XT 57 Pin
Quantity	2
Make/Type	Circ Sub XT 50 Pin x 2” WECO, 24” L	5 DP
OD body
Ball size
Dressing kits
Connection type	XT 50 Pin
Quantity	2
Make/Type	Circ Sub 6- 5/8 FH Box x 2” WECO, 24” L	6 -5/8 DP
OD body
Ball size
Dressing kits
Connection type	6- 5/8 FH Box
Quantity	2
Make/Type	Circ Sub XT 57 Box x 2” WECO, 24” L	5 -7/8 DP
OD body
Ball size
Dressing kits

C-39

Connection type	XT 57 Box
Quantity	2
Make/Type	Circ Sub XT 50 Box x 2” WECO, 24” L	5 DP
OD body
Ball size
Dressing kits
Connection type	XT 50 Box
D.1.21Cup Type Testers	None
Quantity
Make
Size test cup for casing weight
Size test cup for casing weight
Size test cup for casing weight
Connection
Quantity
Make
Size test cup for casing weight
Size test cup for casing weight
Size test cup for casing weight
Connection
Quantity
Make
Size test cup for casing weight
Size test cup for casing weight
Size test cup for casing weight
Connection
D.1.22Plug Type Testers	None
Quantity
Make
Size test plugs
Connection
Quantity
Make
Size test plugs
Connection
Quantity
Make
Size test plugs
Connection

C-40

D.1.23Drop-In Valves / Gray Valves
		Inside BOP (gray V/V) 6- 5/8 FH PxB 8.25 O.D 15K PSI
Quantity		2
Make		Packard Intl.
OD		8 1/4
For pipe:		6 -5/8 DP
Min. drill pipe ID required
Connection type		6- 5/8 FH
Working pressure rating		15k	PSI
		Inside BOP (gray V/V) XT 57 PxB 7.375 O.D 15K PSI
Quantity		2
Make		Packard Intl.
OD		7 3/8
For pipe:		5 -7/8 DP
Min. drill pipe ID required
Connection type		XT 57
Working pressure rating		15k	PSI
		Inside BOP (gray V/V) XT 50 PxB 5.5 O.D 15K PSI
Quantity		2
Make		Packard Intl.
OD		5 1/2
For pipe:		5 DP
Min. drill pipe ID required
Connection type		XT50
Working pressure rating		15k	PSI
D.1.24Bit Subs (Box-Box)
		7-5/8” Reg Bit Sub (9.5” OD X 3” ID)
Quantity		2	Each
OD size		9.5”	Inch
ID size		3”	Inch
Top connection		7-5/8” Reg
Bottom connection		7-5/8” Reg
Bored for float valve	yes/no:	Yes
Float size		5F-6R
		7-5/8” Reg Bit Sub (9.5” OD X 2-13/16” ID)
Quantity		2	Each
OD size		9.5”	Inch
ID size		2 13/16”	Inch
Top connection		6-5/8” Reg
Bottom connection		7-5/8” Reg
Bored for float valve	yes/no:	Yes

C-41

Float size		5F-6R
		6-5/8” Reg Bit Sub (8-1/4” OD X 2-13/16” ID)
Quantity		2	Each
OD size		8 1/4”	Inch
ID size		2 13/16”	Inch
Top connection		6-5/8” Reg
Bottom connection		6-5/8” Reg
Bored for float valve	yes/no:	Yes
Float size		5F-6R
		4-1/2” Reg Bit Sub (6-3/4” OD X 2-13/16” ID)
Quantity		2	Each
OD size		4 1/2”	Inch
ID size		2 13/16”	Inch
Top connection		XT 50
Bottom connection		4-1/2” Reg
Bored for float valve	yes/no:	Yes
Float size		4R
D.1.25Crossover Subs
		6-5/8” FH Box Up X 7-5/8” Reg Pin
Quantity		3	Each
OD size		8 1/2” up x 9 1/2” down	Inch
ID size		5” up x 3” down	Inch
Top connection size		6-5/8” FH	Inch
Type (pin/box)		Box
Bottom connection size		7-5/8” Reg	Inch
Type (pin/box)		Pin
		6-5/8” Reg Box Up X 7-5/8” Reg Pin
Quantity		3	Each
OD size		8 1/4” up x 9 1/2” down	Inch
ID size		2-13/16” up x 3” down	Inch
Top connection size		6-5/8” Reg	Inch
Type (pin/box)		Box
Bottom connection size		7-5/8” Reg	Inch
Type (pin/box)		Pin
		6-5/8” FH Box Up X XT57 Pin
Quantity		3	Each
OD size		8 1/2” up x 7 3/8” down	Inch
ID size		4 1/2” up x 4” dwon	Inch
Top connection size		6-5/8” FH	Inch
Type (pin/box)		Box
Bottom connection size		XT57	Inch
Type (pin/box)		Pin
		XT57 Box Up X 6-5/8” Reg Pin Down
Quantity		3	Each

C-42

OD size	7 1/4” up x 8 1/4” down	Inch
ID size	4” up x 2-13/16” down	Inch
Top connection size	XT57	Inch
Type (pin/box)	Box
Bottom connection size	6-5/8” Reg	Inch
Type (pin/box)	Pin
	XT57 Box Up X 7-5/8” Reg Pin Down
Quantity	3	Each
OD size	7 1/4” up x 9 1/2” down	Inch
ID size	4” up x 3” down	Inch
Top connection size	XT57	Inch
Type (pin/box)	Box
Bottom connection size	7-5/8” Reg	Inch
Type (pin/box)	Pin
	XT50 Box Up X 6-5/8” Reg Pin Down
Quantity	3	Each
OD size	6.75” up x 8 1/4” down	Inch
ID size	2-13/16”	Inch
Top connection size	XT50	Inch
Type (pin/box)	Box
Bottom connection size	6-5/8” Reg	Inch
Type (pin/box)	Pin
	XT57 Box Up X XT50 Pin Down
Quantity	3	Each
OD size	7 1/4”	Inch
ID size	4” up x 3-3/4” down	Inch
Top connection size	XT57	Inch
Type (pin/box)	Box
Bottom connection size	XT50	Inch
Type (pin/box)	Pin
	6-5/8” FH Box Up X 6-5/8” Reg Pin
Quantity	3	Each
OD size	8 1/2	Inch
ID size	4 1/2” up x 2-13/16” down	Inch
Top connection size	6-5/8” FH	Inch
Type (pin/box)	Box
Bottom connection size	6-5/8” Reg	Inch
Type (pin/box)	Pin
	6-5/8” FH Box Up X 6-5/8” FH Pin
Quantity	6	Each
OD size	8 3/8	Inch
ID size	3 3/4”	Inch
Top connection size	6-5/8” FH	Inch
Type (pin/box)	Box
Bottom connection size	6-5/8” Reg	Inch
Type (pin/box)	Pin

C-43

D.1.26Drilling Bumper Subs	None
Quantity
Make
OD
Stroke
Connection type
Quantity
Make
OD
Stroke
Connection type
D.1.27Hole Openers	None
Quantity
Make
OD
Connection type
Quantity
Make
OD
Connection type
D.1.28Underreamer	None
Quantity
Make/Type
OD Min/OD Max
Connection type
D.2HANDLING TOOLS
D.2.1Drill Pipe Elevators
Size	5 1/2 - 9 5/8	Inch
Quantity	2 each
Make	NOV
Model	BX - 7 W/rotator
Rated capacity	1250 (1000 with 18 deg. Taper)	tons
Size	2 3/8 - 9 3/4	Inch
Quantity	2
Make	BX4-75
Model
Rated capacity	750
Size	6 5/8 - 5 7/8 - 5	Inch

C-44

Quantity	1 each
Make	Manual Elevator
Model	HGG
Rated capacity	500	tons
D.2.2Drill Collar Elevators	None
Size
Quantity
Make
Model
Rated capacity
D.2.3Tubing Elevators	None
Size
Quantity
Make
Model
Rated capacity
D.2.4Drill Pipe Hand Slips
Size	6 5/8”, 5 7/8”, 5”
Quantity	2 sets per size of pipe
Make/Type	SDHL
D.2.5Semi-Automatic DP Slips
Size range (largest/smallest)	7 5/8 - 4 1/2	in
Quantity	2
Make/Type	PS 495 / NOV
D.2.6Drill Collar Slips
Size	9-1/2
Quantity	2
Make/Type	DCS-L
Size	8-1/4
Quantity	2
Make/Type	DCS-L
Size	6-3/4
Quantity	2
Make/Type	DCS-L
Size

C-45

Quantity
Make/Type
Size
Quantity
Make/Type
D.2.7Drill Collar Safety Clamps
Quantity	2
Range	9 1/2
Quantity	2
Range	8 1/4
Quantity	2
Range	6 3/4
D.2.8Tubing Slips	None
Size
Quantity
Make/Type
Size
Quantity
Make/Type
D.2.9Tubing Spider	None
Slip size (max/min)
Quantity
Make
Adaptor plate
D.2.10Drill Collar Lifting Subs / Lift Caps
Quantity	3	Each
For OD DC	For Handling 9-1/2” DC
Connection type	7 5/8 API regular (bottom) 6 5/8 FH (top)
Quantity	6
For OD DC	For Handling 8-1/4” DC
Connection type	6 5/8 API regular (bottom) XT 57 (top)
Quantity	6	Each
For OD DC	For Handling 6-3/4” DC

C-46

Connection type		XT 50 (bottom) XT 57 (top)
Lift cap,Pin-7 5/8” Reg	9 -1/2 DC	6	Each
Lift cap,Box-7 5/8” Reg	9 -1/2 DC	3	Each
Lift cap,Pin-6 5/8” Reg	8 -1/4 DC	6	Each
Lift cap,Box-6 5/8” Reg	8 -1/4 DC	3	Each
Lift cap,Pin-6-5/8”FH	6 -5/8 DP & HWDP	6	Each
Lift cap,Box-6-5/8”FH	6 -5/8 DP & HWDP	3	Each
Lift cap,Pin- XT 57	5 -7/8 DP & HWDP	6	Each
Lift cap,Box- XT 57	5 -7/8 DP & HWDP	3	Each
Lift cap,Pin- XT 50	6 - 3/4 DC	6	Each
Lift cap,Box- XT 50	6 - 3/4 DC	3	Each
D.2.11DC Lifting Plugs		None
Quantity
For OD DC
Connection type
Quantity			sets
For OD DC
Connection type
D.2.12Bit Breakers
Quantity		1 of each
For bit size		26”, 17 1/2”, 12 1/4”, 8 1/2”
Bit Breaker Adapter Plate	Quantity	2
D.2.13Elevator Links
Quantity of sets		2
Make/Type		NOV
Size		4-3/4	Inches
Length		144”	Inches
Rated capacity		750	Short Tons
Quantity of sets		2
Make/Type		NOV
Size		5 1/2	Inches
Length		144”	Inches
Rated capacity		1000	Short Tons
Quantity of sets		1
Make/Type		NOV

C-47

Size	5-1/2”	Inches
Length	180”	Inches
Rated capacity	1,250	Short Tons
Quantity of sets
Make/Type
Size
Length
Rated capacity
D.2.14Kelly Spinner	N/A
Make/Type
D.2.15Drillpipe Spinner
Make/Type	SSW-40 (pneumatic)
Size (max/min)	3 1/2 - 9 1/2	in
D.2.16Mud Saver Bucket
Make	NOV
Size	2 7/8 - 6 5/8
	The main well HydraTong ARN200 to be equipped with a fully automatic mud bucket.
Make
Size
D.2.17Hydraulic Make-up/Beakout Machine (e.g. Ezy Torque)
Make/Type	EZ Torque CAT-P15-2
Maximum linepull	147 kN Max
D.2.18Rotary Rig Tongs
Quantity	2 sets
Make/Type	HT - 100
Size range (max OD/min OD)	21” to 4”
Torque rating	100,000	ft/lbs
Quantity	2 sets
Make/Type	HT - 50
Size range (max OD/min OD)	19-20 and 28.5-30	in
Torque rating	50,000	ft/lbs
D.2.19Tubing Tongs (manual)	None

C-48

Quantity
Make/type
Size range (max OD/min OD)
Torque rating
D.2.20Tubing Tongs Power		None
Quantity
Make/type
Size range (max OD/min OD)
Max output torque
Torque indicator	yes/no:
Back-up arm	yes/no:
D.2.21Iron Roughneck
Quantity		2
Make/Type		Hydralift ARN 200
Size range (max OD/min OD)		9-3/4”max , 3-1/2”min	Inches
D.3FISHING EQUIPMENT		NOTE: Rowan Specification. Company requested changes to the specification to be agreed by Variation Order
D.3.1Overshots
Quantity		1
Make/Type		NOV-Bowen S-150
Overshot OD		11.750”
To catch size (Max Catch Spiral Grapple)		10 1/8”
To catch size (Max Catch Size Basket Grapple)		9 3/8”
To catch size
Overshot guide OD		11.750” & 17.50”
Extension sub length		36”
Extension sub length		48”
Lipped guide (oversize, regular)		Oversize & Regular
Grapples (spiral, basket, both)	yes/no:	Both
Pack offs		Yes
Top sub connection type		6 5/8” API Reg Box
Quantity		1
Make/Type		NOV-Bowen S-150
Overshot OD		8.125
To catch size (Max Catch Spiral Grapple)		6 1/2”
To catch size (Max Catch Size Basket Grapple)		5 3/4”
To catch size
Overshot guide OD		8 1/8”
Extension sub length		36”

C-49

Lipped guide (oversize, regular)	Regular
Grapples (spiral, basket, both)	Both
Pack offs	Yes
Top sub connection type	4 1/2” IF Box
Quantity	1
Make/Type	NOV-Bowen S-150
Overshot OD	8.125
To catch size (Max Catch Spiral Grapple)	7”
To catch size (Max Catch Size Basket Grapple)	6 3/8”
To catch size
Overshot guide OD	8 1/8”
Extension sub length	42”
Extension sub length	36”
Lipped guide (oversize, regular)	Regular
Grapples (spiral, basket, both)	Both
Pack offs	Yes
Top sub connection type	4 1/2” IF Box
D.3.2Hydraulic Fishing Jar
Quantity	1
Make/Type	NOV-Bowen
OD body	8”
Min. ID	3 1/16”
Stroke	12”
Connection type	6 5/8” API Regular
Repair kit
Quantity	1
Make/Type	NOV-Bowen
OD body	6 1/2”
Min. ID	2 1/4”
Stroke	12”
Connection type	4 1/2” IF
Repair kit
Quantity
Make/Type
OD body
Min. ID
Stroke
Connection type
Repair kit
D.3.3Jar Intensifier
Quantity	1
Make	NOV-Bowen
Type	8”
OD body	3 1/16”

C-50

Min. ID	12”
Connection type	6 5/8” API Regular
Repair Kit
Quantity	1
Make	NOV-Bowen
Type	6 1/2”
OD body	2 1/4”
Min. ID	13”
Connection type	4 1/2” IF
Repair Kit
Quantity
Make
Type
OD body
Min. ID
Connection type
Repair Kit
D.3.4Surface Jar	None
Quantity
Make/Type
OD body
Stroke
Connection type
Repair Kit
D.3.5Fishing Bumpersubs
Quantity	1
Make/Type	NOV-Bowen
OD body	8”
Min. ID	3 1/2”
Stroke	18”
Connection type	6 5/8” API Regular
Quantity	1
Make/Type	NOV-Bowen
OD body	6 1/2”
Min. ID	3 1/8”
Stroke	18”
Connection type	4 1/2” IF
Quantity
Make/Type
OD body
Min. ID
Stroke
Connection type

C-51

D.3.6Safety Joints	None
Quantity
Make/Type
OD body
Min. OD
Connection type
Quantity
Make/Type
OD body
Min. OD
Connection type
D.3.7Junk Baskets (Reverse Circulation)
Quantity	1
Make/Type	NOV-Bowen
For hole size
OD body	11”
OD Bushing	15”
OD Mill Shoe Blank	15”
Connection type	6 5/8” API Regular
Inside magnet available	Yes
Mill shoes type Blank	4
Quantity	1
Make/Type	NOV-Bowen
For hole size
OD body	7 7/8”
Connection type	5 1/2” API Regular
Inside magnet available	Yes
Mill shoes type Blank	2
D.3.8Bull Nose Subs
Quantity	1 (Nylon)	Each
For OD DC	5 -7/8 DP
Connection type	XT 57 Box
D.3.9Junk Subs	None
Quantity
Make/Type
For hole size
OD body
Connection type
Quantity
Make/Type
For hole size

C-52

OD body
Connection type
Quantity
Make/Type
For hole size
OD body
Connection type
D.3.10Flat Bottom Junk Mill	None
Quantity
Make/Type
OD flat mill
Connection type
Quantity
Make/Type
OD flat mill
Connection type
Quantity
Make/Type
OD flat mill
Connection type
D.3.11Magnet Fishing Tools	None
Quantity
Make/Type
OD body
Connection type
Quantity
Make/Type
OD body
Connection type
D.3.12Taper Taps	None
Quantity
Make
OD (Max/Min)
OD body
Length
Connection type
D.3.13Die Collars	None
Quantity

C-53

Make
OD (Max/Min)
OD body
Length
Connection type
E.WELL CONTROL/SUBSEA EQUIPMENT
E.1LOWER RISER DIVERTER ASSEMBLY
(used when drilling for the surface casing)		N/A
E.1.1Hydraulic Connector		N/A
Size
Make
Surface controlled hydraulic operated dump valves
Size
E.1.2Flex Joint/Riser Adaptor		N/A
Flex Joint
Make/type
Size			inches
Max Deflection			deg
Riser Adaptor
Make/type
Size			inches
E.2PRIMARY BOP STACK (from bottom to top)
Stack complete with:
- guide frame	yes/no:	Yes
- pick up attachment	yes/no:	Yes
- transport base	yes/no:	Yes
Size (bore)		18-3/4	Inches
Working pressure		15,000	psi
H2S service	yes/no:	Yes
E.2.1Alternate hydraulic connector
Alternate connector available		No
Connector make/model		N/A
Adaptor available		N/A
E.2.2Hydraulic Wellhead Connector
Size		30/27	Inches
Make/Type		Vetco Super HD H-4

C-54

Working pressure		15,000	psi
Hot tap for underwater intervention	yes/no:	Yes
Spare connector same type	yes/no:	Yes
E.2.3Ram Type Preventers
Preventers:
Quantity		7 cavities
Bore size		18-3/4	Inches
Working Pressure		15,000	psi
Make		Cameron
Model		TL
Type (single/double)		2x triple, 1x single (removable)
Ram locks	yes/no:	Yes “ST locks”
Preventer connection type - top		BX164
Preventer connection type - bottom		BX164
Side oultlets	yes/no:	Yes
Size		3-1/16	Inches
Connection type		Studded/flange
Acoustic control system	yes/no:	Yes (Nautronix)
Pipe rams:
Quantity		1 set
Size		6 5/8” Fixed
Quantity
Size
Quantity
Size
Casing Shear Rams:		Super Shear
Quantity		1 set
Blind/Shear Rams:		CDVS Blind Shear
Quantity		2 sets
		2 sets
Variable Rams:
Quantity		3 sets
Size range (max/min)		3 1/2” by 6 5/8” VBR
E.2.4Stack Configuration		Can be modified to meet client and/or regulatory requirements
(Blind/Shear/Pipe/Variable)	Numbers ascend from the Bottom (Wellhead) to the Top (Annulars), as per API RP 53 7.2
Upper Triple
Top rams	(Cavity 7)	Blind shear rams
Middle rams	(Cavity 6)	Casing shear rams
Lower rams	(Cavity 5)	Blind shear rams

C-55

Lower Triple
Upper rams	(Cavity 4)	3.5-6 5/8” VBR
Middle rams	(Cavity 3)	6 5/8” fixed
Lower rams	(Cavity 2)	3.5-6 5/8” VBR
Bottom Single Ram
Single Ram	(Cavity 1)	3.5-6 5/8” VBR
Position of side outlets - kill
Upper		Below Cavity 5
Middle		Below Cavity 3
Lower		Below Cavity 1
Position of side outlets - choke
Upper		Below Cavity 7
Middle		Below Cavity 4
Lower		Below Cavity 2
E.2.5Annular Type Preventer On Stack		N/A (2 each annulars on LMRP)
Size
Working pressure
Make/Type
E.2.6Mandrel
Make/Type		Cameron AX
Size		18-3/4 15M	Inches
E.2.7Fail-Safe Hydraulic Valves
(Kill and Choke)
Quantity on each side outlet		2
Size (ID)		3 1/16	Inches
Make/Type		Cameron MCS
Working pressure		15,000	psi
Solid block		yes
E.2.8Subsea Accumulators
(See also E.7.1 - Surface Accummulator Unit)
Quantity		12 x 150 gal
Useful capacity per accumulator (w/o pre-charge)		150	Gal
Bottle working pressure		7,500	psi
Hotline pressure		7,500	psi
E.2.9Hydraulic Control Pod/Receptacles
Quantity		2
Redundancy		100	percent

C-56

Color Coded	yes/no:	Yes
Remote regulation of operating pressure for functions requiring lower operating pressure	yes/no:	Yes
Spare control pod	yes/no:	No (but have complete second BOP stack)
E.3PRIMARY LOWER MARINE RISER PACKAGE
(From Bottom To Top)
E.3.1Hydraulic Connector
Make/Type		Cameron Collet HC
Size		18 3/4	inches
Working pressure		15K	psi
Hot tap for underwater intervention	yes/no:	Yes
Spare connector same type	yes/no:	No (but have complete second BOP stack)
E.3.2Annular Type Preventer (LMRP)
Upper
Size		18-3/4	Inches
Working pressure		10M	psi
Make/Type		Hydril GX Dual
Lower
Size		18-3/4	Inches
Working pressure		10M	psi
Make/Type		Hydril GX Dual
E.3.3Flex Joint
Make/Type		OSI Flex Joint
Size		18-3/4 6KSI
Max deflection		10	deg
E.3.4Riser Adapter
Make/Type		Cameron
Size		19.25	inches
E.3.5Connection Lines to Riser
Type (rigid loops, coflexip, etc.)		Coflexip “with/coflon”
E.4SECONDARY BOP STACK (from bottom to top)		As above for Primary stack.
Stack complete with:
- guide frame

C-57

- pick up attachment
- transport base
Size (bore)
Working pressure
H2S service
E.4.1     Alternate hydraulic connector
Alternate connector available
Connector make/model
Adaptor available
E.4.2      Hydraulic Wellhead Connector
Size	Inches
Make/Type
Working pressure	psi
Hot tap for underwater intervention
Spare connector same type
E.4.3      Ram Type Preventers
Preventers:
Quantity
Bore size
Working Pressure
Make
Model
Type (single/double)
Ram locks
Preventer connection type - top
Preventer connection type - bottom
Side oultlets
Size
Connection type
Acoustic control system
Pipe rams:
Quantity
Size
Quantity
Size
Quantity
Size
Blind/Shear rams:
Quantity
Blind/Shear rams:
Quantity
Variable rams:

C-58

Quantity

Size range (max/min)

Quantity

Size range (max/min)

E.4.4      Stack Configuration

(Blind/Shear/Pipe/Variable)

Upper Triple

Top rams

Middle rams

Lower rams

Lower Triple

Upper rams

Middle rams

Lower rams

Bottom Single Ram

Single Ram

Position of side outlets - kill

Upper

Middle

Lower

Position of side outlets - choke

Upper

Middle

Lower

E.4.5      Annular Type Preventer On Stack

Size

Working pressure

Make/Type

E.4.6      Mandrel

Make/Type

Size

E.4.7      Fail-Safe Hydraulic Valves

(Kill and Choke)

Quantity on each side outlet

Size (ID)

Make/Type

Working pressure

Solid block

E.4.8      Subsea Accumulators

(See also E.7.1 - Surface Accummulator Unit)

C-59

Quantity
Useful capacity per accumulator (w/o pre-charge)
Bottle working pressure
E.4.9      Hydraulic Control Pod/Receptacles
Quantity
Redundancy
Color Coded
Remote regulation of operating pressure for
functions requiring lower operating pressure
Spare control pod
E.5          SECONDARY LOWER MARINE RISER PACKAGE	As above for Primary stack.
(From Bottom To Top)
E.5.1      Hydraulic Connector
Make/Type
Size
Working pressure
Hot tap for underwater intervention
Spare connector same type
E.5.2      Annular Type Preventer (LMRP)
Upper Annular
Size
Working pressure
Make/Type
Lower Annular
Size
Working pressure
Make/Type
E.5.3      Flex Joint
Make/Type
Size
Max deflection
E.5.4      Riser Adapter
Make/Type
Size

C-60

E.5.5      Connection Lines to Riser
Type (rigid loops, coflexip, etc.)
E.6       PRIMARY MARINE RISER SYSTEM
E.6.1     Marine Riser Joints
Make/Model		Cameron Load King
OD		21.25	Inches
ID		19.25	Inches
Wall thickness		1.0	Inches
Average length of each joint		75	ft.
Weight of one complete joint (in air)		est. 33,514 “slick joint ”	lbs
Quantity		150 (10 slick)
Pipe material		x-80
Minimum yield strength		80,000
Type riser connectors		Flanged
Dogs		no
Pup joints:
Quantity		1
Length		40	ft.
Quantity		1
Length		35	ft.
Quantity		1
Length		30	ft.
Quantity		1
Length		25	ft.
Quantity		1
Length		20	ft.
Quantity		1
Length		15	ft.
Quantity		1
Length		10	ft.
Quantity		1
Length		5	ft.
E.6.2      Telescopic Joint
Make/Type		Cameron Load King
Size (ID)		19 3/4	Inches
Stroke		80	ft.
Double Seals		Yes
Spare telescoping joint	yes/no:	Yes
Location		Vessel
Rotating support ring for riser tensioners		Yes “Roller Bearing”
Connection points		N/A

C-61

E.6.3      Kill/Choke Lines
Quantity	1x choke, 1x kill
Outside diameter	6.75	inches
Inside diameter	4.5	inches
Working pressure	15,000	psi
E.6.4      Booster Lines (If Fitted)
Quantity	1
Outside diameter	5	inches
Inside diameter	4	inches
Working pressure	7,500	psi
E.6.5      Hydraulic Supply Lines
Quantity	2
Outside Diameter	3.125	inches
Inside Diameter	2 1/2	inches
Working pressure	5,000	psi
E.6.6      Upper Ball (Flex) Joint	Flex
Make/Type	OSI diverter flex II-3
Size	21	inches
Maximum deflection	15 plus/minus	degs
Spare upper ball (flex) joint	No
E.6.7      Buoyancy Modules (If Fitted)	Buoyancy configuration under technical review
Make	Cuming
Quantity of buoyed riser joints	32
OD of buoyed riser joints	54	Inches
Length of each module	210	Inches
Volume of each module	A: 97.6 B: 90.6	cu ft
Buoyancy in seawater	29,140 (total uplift per joint)	lbs
Rated water depth	2,500	ft
Make	Cuming
Quantity of buoyed riser joints	33
OD of buoyed riser joints	56	Inches
Length of each module	210	Inches
Volume of each module	A: 108.6 B: 101.3	cu ft
Buoyancy in seawater	29,140 (total uplift per joint)	lbs
Rated water depth	5,000	ft
Make	Cuming
Quantity of buoyed riser joints	33
OD of buoyed riser joints	59	Inches

C-62

Length of each module	210	Inches
Volume of each module	A: 124.4 B: 117.2	cu ft
Buoyancy in seawater	29,092 (total uplift per joint)	lbs
Rated water depth	7,500	ft
Make	Cuming
Quantity of buoyed riser joints	33
OD of buoyed riser joints	59	Inches
Length of each module	210	Inches
Volume of each module	A: 124.4 B: 117.2	cu ft
Buoyancy in seawater	28,612 (total uplift per joint)	lbs
Rated water depth	10,000	ft
Make	Cuming
Quantity of buoyed riser joints	27
OD of buoyed riser joints	59	Inches
Length of each module	210	Inches
Volume of each module	A: 124.4 B: 117.2	cu ft
Buoyancy in seawater	26,292 (total uplift per joint)	lbs
Rated water depth	12,000	ft
E.6.8      Marine Riser Spider
Make/Type	Cameron Load King 3.5
E.6.9      Marine Riser Gimbal
Make/Type	Cameron Load King 3.5
E.6.10    Riser Handling Tools
Quantity	4
Type	2 Hydraulic / 2 Manual
E.6.11    Riser Test Tools
Quantity	5
Type	integral to Riser running tool “aux line lockdown pins”
E.6.12    Instrumented Riser Joint
Quantity	None
Make
Type
Length
Functions:
Tension
Mud temp
Mud weight

C-63

Other
E.6.13    Riser Flood/Fill System
Quantity	None
Make
Type
Length
Automatic operation
Manual override
No. of inlet valves
Size of valves (ID)
E.7          SECONDARY MARINE RISER SYSTEM	None
E.7.1      Marine Riser Joints
Make/Model
OD
ID
Wall thickness
Average length of each joint
Weight of one complete joint (in air)
Quantity
Pipe material
Minimum yield strength
Type riser connectors
Dogs
Make/Model
OD
ID
Wall thickness
Average length of each joint
Weight of one complete joint (in air)
Quantity
Pipe material
Minimum yield strength
Type riser connectors
Dogs
Pup joints:
Quantity
Length
Quantity
Length
Quantity
Length
Quantity
Length

C-64

E.7.2Telescopic Joint		N/A
Make/Type
Size (ID)			Inches
Stroke			ft.
Double Seals
Spare telescoping joint	yes/no:
Location
Rotating support ring for riser tensioners
Connection points
E.7.3Kill/Choke Lines		N/A
Quantity
Outside diameter
Inside diameter
Working pressure
E.7.4Booster Lines (If Fitted)		N/A
Quantity
Outside diameter
Inside diameter
Working pressure
E.7.5Hydraulic Supply Lines		N/A
Quantity
Outside diameter
Inside diameter
Working pressure
E.7.6Upper Ball (Flex) Joint		N/A
Make/Type
Size
Maximum deflection
Spare upper ball (flex) joint
E.7.7Buoyancy Modules (If Fitted)		N/A
Make
Quantity of buoyed riser joints
OD of buoyed riser joints
Length of each module
Volume of each module
Buoyancy in seawater
Rated water depth

C-65

Make
Quantity of buoyed riser joints
OD of buoyed riser joints
Length of each module
Volume of each module
Buoyancy in seawater
Rated water depth
E.7.8Marine Riser Spider	N/A
Make/Type
E.7.9Marine Riser Gimbal	N/A
Make/Type
E.7.10Riser Handling Tools	N/A
Quantity
Type
E.7.11Riser Test Tools	N/A
Quantity
Type
E.7.12Instrumented Riser Joint	N/A
Quantity
Make
Type
Length
Functions:
Tension
Mud temp
Mud weight
Other
E.7.13Riser Flood/Fill System	N/A
Quantity
Make
Type
Length
Automatic operation
Manual override
No. of inlet valves

C-66

Size of valves (ID)
E.8DIVERTER BOP
(For installation in fixed bell nipple)
Make/Type	Cameron Type CSO
Max Bore Size	21.25
Working pressure	500	psi
Number of diverter outlets	7
Outlet OD	List below
Insert packer size ID	CSO
E.8.1Diverter Flowlines
Quantity	2
OD of flowlines	18	Inches
Running from diverter to	overboard - port and stbd
Valve types	ball
Size	18	Inches
Working pressure	ANSI 300 Class (720 psi)	psi
Control valve type (air/hydraulic/etc.)	air
Remote controlled from	NOV Cyberbase
Quantity	1
OD of flowlines	18	Inches
Running from diverter to	flowline
Valve types	ball
Size	18	Inches
Working pressure	ANSI 300 Class (720 psi)	psi
Control valve type (air/hydraulic/etc.)	air
Remote controlled from	NOV Cyberbase
Quantity	1
OD of flowlines	6	Inches
Running from diverter to	trip tank fill
Valve types	ball
Size	6	Inches
Working pressure	ANSI 300 Class (720 psi)	psi
Control valve type (air/hydraulic/etc.)	air
Remote controlled from	NOV Cyberbase
Quantity	1
OD of flowlines	12	Inches
Running from diverter to	degasser
Valve types	ball
Size	12	Inches
Working pressure	ANSI 300 Class (720 psi)	psi
Control valve type (air/hydraulic/etc.)	air
Remote controlled from	NOV Cyberbase
Quantity	2

C-67

OD of flowlines		4	Inches
Running from diverter to		well fill from trip tank
Valve types		1x ball & 1x non return
Size		4	Inches
Working pressure		ANSI 300 Class (720 psi)	psi
Control valve type (air/hydraulic/etc.)		air
Remote controlled from		NOV Cyberbase
E.8.2Diverter Control Panels		Cameron MUX control & Manual skid
Driller’s panel		yes
Make		Cameron
Model		MUX surface control
Location		Drillfloor
Locking/unclocking control		yes/ software seq.
Remote panel		yes
Make		Cameron
Model		MUX surface control
Location		Superintendants Office
Locking/unclocking control		yes /software seq.
E.9SUBSEA SUPPORT SYSTEM
E.9.1Riser Tensioners
Quantity		16
Make/Type		NOV Hydralift - SWRT 250-65
Capacity each tensioner		250	kips
Maximum stroke		16.25	ft.
Wireline size		2.75	Inches
Line travel		65	ft.
Independent air compressors	yes/no:	yes
Independent air drying unit	yes/no:	yes
E.9.2Guideline System		N/A
Quantity
Make/Type
Capacity each tensioner
Maximum stroke
Wireline size
Line travel
Line storage drums with tensioners
E.9.3Remote Guideline Replacement Tool		N/A
Make/Type

C-68

E.9.4Remote Guideline Cutting Tool	N/A
Make/Type
E.9.5Pod Line Tensioners	N/A
Quantity
Make/Type
Capacity each/tensioner
Maximum stroke
Wireline size
Line travel
E.9.6Tensioner/Compensator Air Pressure Vessels
Quantity	detail below
Total capacity	Working APV 48 X 2000L Standby APV 8 X 1815L
Rated working pressure	Working APV = 3000psi Standby APV = 4500psi
Pressure relief valve installed	Yes
E.10BOP CONTROL SYSTEM
E.10.1Surface Accumulator Unit	Two units - main and offline
(See also E.2.8 & E.4.8 - Subsea Accumulators)
Make	CIW Mark III Mux
Model/Type	bladder type
Location	Subsea equipment room
Soluble oil reservoir capacity	Satisfy API 16D
Oil/water mix.capacity	Satisfy API 16D
Glycol reservoir capacity	Satisfy API 16D
No. of bottles installed	100
Useful capacity per accumulator (w/o pre-charge)	15	Gal
Bottle working pressure	5000	psi
Control manifold model	Cameron
Regulator type
Total useful accumulator volume (surface and stack) equals all preventer opening and closing volumes.	Satisfy API 16D
Plus percent additional volume
E.10.2Accumulator Hydraulic Pumps
Electric Driven	Yes
Quantity	3
Make	Hammelmann
Model	Triplex pump

C-69

Each driven by motor of power	Electric
Flow rate of each pump	30	GPM
At minimum operating pressure	4500	psi
Air Driven	N/A
Quantity
Make
Model
Each driven by motor of power
Flow rate of each pump
At minimum operating pressure
E.10.3Driller’s Control Panel
Graphic control panel at driller’s position showing subsea functions with controls for the following functions of the BOP stack	Yes
Marine riser connector	Yes
All annular type BOP’s	Yes
All ram type BOP’s	Yes
Lock for ram type BOPs	Yes
Wellhead and LMRP connector	Yes
Inner and outer kill and choke line valves	Yes
Low acc. pressure warning	Yes
Low reservoir level warning	Yes
Low rig air pressure warning	Yes
Pressure regulator for annular	Yes
Flowmeter	Yes
Quantity of pressure gauges	Yes
Emergency push button for automatic	Yes
riser disconnection	Yes
Other control functions	Yes
Control panel make	Cameron
Control panel model	Touch
E.10.4Remote Control Panels
Ability to operate main closing unit valves directly	yes
Quantity	1
Make/Model	Cameron
Locations	Toolpushers Cabin (mimic) / Bridge (active)
Operating System Routing (Direct/via Primary Control Panel)	direct
E.11SUBSEA CONTROL SYSTEM
E.11.1Hose Reels

C-70

Quantity	1
Location	Moonpool area
Make/Type	PatCo
Maximum storage length each	13,000	ft
Drive motor type	Pneumatic motor/ drive system
E.11.2Pod Hose	N/A
Location
Length
OD hose
Control line ID
Quantity total
Quantity spare (when new)
Control line ID
Quantity total
Quantity spare (when new)
Control line ID
Quantity total
Quantity spare (when new)
E.11.3Pod Hose Manifold	N/A
E.11.4Surface Test Pod	Pod test stand
E.12ACOUSTIC EMERGENCY BOP CONTROL SYSTEM
Make/Model	Nautronix
Type (Fixed/Portable)	Portable
Number of functions	8
Type of functions
Upper shear ram preventer - close	Yes
Upper pipe ram preventer - close	Yes
Lower shear ram preventer - close	Yes
LMRP connector - unlatch	Yes
Upper pipe ram ST lock - lock	Yes
Super shear ram preventer - close	Yes
Acoustic system - isolation	Yes
Other	Yes acoustic system “RESET/ARM”
E.13SUBSEA AUXILIARY EQUIPMENT
E.13.1Hole Position Indicator	To be specified
Make/Type

C-71

Quantity of monitors
Monitor location
Monitor location
Recorder
E.13.2Riser Angle Indicator
Make/Type	Electric and Acoustic
Quantity of monitors	3
Monitor location	1 Riser adapter
Monitor location	1 each Pod
Recorder	Yes
E.13.3Slope Indicators	Bullseye
Make	Cameron
Quantity	2
Provision for installation on	Riser adapter/stack
BOP	N/A
Pin Connector	N/A
Other
E.13.4Underwater TV System
Make/Type	Video Ray / P4 OG 300BASE Configuration
Quantity of TV monitors	TBD
Monitor location	TBD
Monitor location	TBD
Reels/cables for maximum water depth	130’ of Preformance Neutral Buoyancy Tether, 250’ Standard Neutral Buoyancy Tether, 250’ Negative Buoyancy Tether, and Ship Hull Crawler Accessory for monitoring sea chest intakes
TV frame type	TBD
Pan/tilt unit	Yes
Spare camera	TBD
Spare cable	TBD
E.13.5ROV System	Space and provisions for two (2) sets overboard launched work-class ROVs (approx.150 HP) shall be provided. The ROV shall be using a cursor system (ROV owner supplied) with lower guide frames attached to the outboard side of the hull. Detailed layout drawings will be provided by the ROV manufacturer

C-72

Quantity
Make
Type
Monitor location
Monitor location
Provided by
Maximum water depth
Cameras - color
Cameras - B & W
Manipulators
Quantity
Type (spacially correspondent, rate, grabber)
Functions
Quantity
Type (spacially correspondent, rate, grabber)
Functions
Quantity
Type (spacially correspondent, rate, grabber)
Functions
Sonar
Type
Type
E.14       CHOKE MANIFOLD
E.14.1    Choke Manifold
(For instrumentation, see H.3)
Make		WOM
Minimum ID		3-1/16	Inches
Maximum WP		15,000	psi
H2S service	yes/no:	Yes
Quantity of fixed chokes		20 each 3-1/16” 15K manual gate valves
Make		WOM
Model		Magnum F.E.
Size (ID)		3-1/16”	Inches
Quantity of fixed chokes		11 each 4-1/16” - 10K manual gate valves
Make		WOM
Model		Magnum F.E.
Size (ID)		4-1/16”	Inches
Quantity of fixed chokes		4 each 2-1/16” — 15K manual gate valves
Make		WOM
Model		Magnum F.E.
Size (ID)		2-1/16”	Inches
Quantity of adjustable chokes
Make
Model
Size (ID)			Inches
Quantity of power chokes		4 (Hydraulic)

C-73

Make		Expro
Model		Power Choke
Size (ID)		3” orifice	Inches
Power choke remote control panel
Make
Model
Location		drillers cabin
Glycol injection	yes/no:	Yes
E.14.2    Flexible Choke & Kill Lines		API 15,000 PSI 16C monogrammed
(Connecting riser to drilling unit)
Quantity	choke	1
Make/Type		Coflex / Coflon lined choke, kill, and bost (workover capable)
ID		3	Inches
Working pressure/test pressure		15,000	psi
Quantity	kill	1
Make/Type		Coflexip
ID		3	Inches
Working pressure/test pressure		15,000	psi
E.15       BOP TESTING EQUIPMENT
E.15.1    Hydraulic BOP Test Pump
Make		Cameron
Model/Type		HPTU
Pressure rating		22,500	psi
Chart recorder	yes/no:	Yes
E.15.2    BOP Test Stump		Offline operation
Quantity		2 each size (total 4)
Test pressure		15,000	psi
Type		Vetco VX/VT
Size		27” & 30” load/non-load bearing	inches
Connected to deck (welded/bolted)		Bolted
E.15.3    LMRP Test Stump		Offline operation
Quantity		1
Test pressure		10,000	psi
Type		CIW AX
Size		18 3/4	inches
Connected to deck (welded/bolted)		Bolted
E.16       WELLHEAD RUNNING/RETRIEVING/		operator supply

C-74

TESTING TOOLS (RT/RRT/TT)
Wellhead make
Wellhead type
Wellhead size
Pressure rating
E.16.1    RT’s For Casing Installation	operator supply
Mechanical RT - casing housing sizes
Hydraulic RT - casing housing sizes
Pack Off RT - casing housing sizes
Hanger RT - casing hanger sizes
Hanger RT - casing type
Seal Assembly RT - casing sizes
E.16.2    RRT’s For Casing Installation	operator supply
Seal Assembly RRT - casing sizes
Wear Bushing RRT - casing sizes
Seat Protector RRT - casing sizes
E.16.3    Miscellaneous Tools	operator supply
Temporary guide base RT
BOP stack TT
Multi-purpose TT
Conductor casing jetting head
Clean out tool
Lock ring wellhead release tool
Seal assembly torque tool
Utility guide frame
Guide frame adaptor sizes
E.16.4    DP Hang-Off Subs	None
OD drill pipe
Quantity
Connection type
Grade
Hang Off Method (sq. shoulder/doughnut)
E.16.5    Mini Hose Bundle for use with hydraulic running tools	None
Control line ID
Quantity of lines
Control line ID
Quantity of lines

C-75

E.16.6    Emergency BOP Recovery System
Emergency BOP recovery system:	yes/no	Yes
Make/type		Cameron/ Shackles and slings
E.17       Riser Gas Handling System
Make / Manufacturer		Cameron
Location in Riser String		Below Telescopic Joint
Components
(1) Cameron 21-1/4” 2M Annular (Rapid close)
(1) Flow spool with 3 ea. 6” ports.
(1) Spacer Spool - Note: Spool can be replaced with Weatherford 7875 RCD unit for conversion to MPD joint.
Dedicated Choke Manifold
(2) ea. 6” API 17K compliant hoses and valving (to choke manifold)
(1) 6” API 17K compliant bypass Line (overboard)
F.            MUD SYSTEM/BULK SYSTEM
F.1          HIGH PRESSURE MUD SYSTEM
System working pressure		7,500	psi
System test pressure		11,250	psi
Built to which design standard		API
F.1.1       Mud Pumps
Quantity		5
Make		NOV
Model		14-P-220
Type (Triplex/Duplex)		Triplex
Liner sizes available		6-1/2” standard, 5 1/2” and 6”
Mud pump drive motors		2
Motor type		NOV AC - DM 27
Continuous power rating per motor		1,150	Horsepower
Fluid end		NOV Mission
Maximum working pressure		7,500	psi
Test pressure		11,250	psi
Pump stroke counter		Electronic
Supercharging pump		Mission 8x6x14
Driven by motor of power		100	HP
Flowrate		1,500	GPM
Discharge/Suction line ID		Discharge (150mm) / Suction line (250mm)ID
M.P. Pulsation Dampener		R-120 (7,500 psi)
Reset Relief Valve		Titan BX

C-76

Working flowrate per pump at 90% of max spm
Liner Size		6”   /   5-1/2”	inches
Pump speed (90% of max.)			RPM
Pump pressure			psi
Working flowrate @ 100% volumetric output			GPM
F.1.2       Transfer Pumps/Mixing Pumps
Mixing/Transfer Pumps
Quantity		4
Make		NOV
Model		Vertical Magnum
Type		8 x 6 x 14
Drive motor type		Electric
Power output		125	HP
F.1.3       Booster Pump
Quantity		None
Make/Type
Pumping capacity (each)
Drive motor type
Power output
F.1.4       Standpipe Manifold
Quantity of standpipes		3 (2 on main well center and 1 on auxiliary well center)
Standpipes ID		5	Inches
H-Type standpipe manifold	yes/no	Yes
Kill line outlet	yes/no	Yes
Fill-up/bleed-off line outlet	yes/no	Yes
Outlets (total)		3
ID		3” for 10K
Type connections		main run to/from inflo-API flange 10K
Dimensions OD x ID		OD=171.4 X ID 127.0 A519 GR4130 seals
Design standard		API 6A PtoU (-20F TO +250F) rated pressure 7,500 PSI test pressure 11,250 PSI
F.1.5       Rotary Hoses
Quantity		3
Make/Type		7,500psi, API 7K
ID x length		4” x 110ft
Snubbing lines		Yes

C-77

F.1.6       Cementing Hose
Quantity	2
Type (i.e. Coflexip)
Length	110ft
ID	3’
Working pressure	15,000psi, API 7K
F.1.7       Chiksan Steel Hoses	None
Integral non-screwed
Make/type
ID
Section length
Quantity
Section length
Quantity
Sweep swivels, make/type
Nom. size ID
Fittings, non-screwed type
Suitable for H2S service
F.2          LOW PRESSURE MUD SYSTEM
F.2.1       Mud Tanks
Quantity	28 (includes active, reserve and slug)
Total capacity	~20,000 (includes active, reserve and slug)	bbls
Capacity, tank No. 1 Active	1578.7	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 2 Active	1578.7	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 3 Active	977.4	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 4 Active	460.4	bbls
Type (active/reserve)	Active
Height	5.1	meters
Mixers	Yes

C-78

Mud guns	Yes
Capacity, tank No. 5 Active	977.4	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 6 Active	518.3	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 7 Active	460.4	bbls
Type (active/reserve)	Active
Height	5.1	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 8 Active	460.4	bbls
Type (active/reserve)	Active
Height	5.1	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 9 Active	518.3	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 10 Active	518.3	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 11 Active	484.3	bbls
Type (active/reserve)	Active
Height	5.1	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 12 Active	977.4	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 13 Active	545.3	bbls
Type (active/reserve)	Active
Height	5.3	meters

C-79

Mixers	Yes
Mud guns	Yes
Capacity, tank No. 14 Active	1028.4	bbls
Type (active/reserve)	Active
Height	5.3	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 1 Reserve	2615.3	bbls
Type (active/reserve)	Reserve
Height	7.05	meters
Mixers	Yes
Mud guns	No
Capacity, tank No. 2 Reserve	2615.3	bbls
Type (active/reserve)	Reserve
Height	7.05	meters
Mixers	Yes
Mud guns	No
Capacity, tank No. 3 Reserve	905.1	bbls
Type (active/reserve)	Reserve
Height	3.34	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 4 Reserve	780.6	bbls
Type (active/reserve)	Reserve
Height	3.34	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 5 Reserve	565.5	bbls
Type (active/reserve)	Reserve
Height	3.34	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 6 Reserve	565.5	bbls
Type (active/reserve)	Reserve
Height	3.34	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 7 Reserve	613.9	bbls
Type (active/reserve)	Reserve
Height	3.34	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 8 Reserve	613.9	bbls
Type (active/reserve)	Reserve

C-80

Height	3.34	meters
Mixers	Yes
Mud guns	Yes
F.2.2       Mud Processing Tanks
Quantity	23
Total capacity	2176	bbls
Sand Trap Tank	94	bbls
Agitation	Yes
Degasser	94	bbls
Agitation	Yes
Desilter	63	bbls
Agitation	Yes
Desander	63	bbls
Agitation	Yes
Clean Mud	63	bbls
Agitation	Yes
F.2.3       Pill/Slug Tank
Capacity, tank No. 1 Slug	179.3	bbls
Height	2.6	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 2 Slug	166.1	bbls
Height	2.6	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 3 Slug	166.1	bbls
Height	2.6	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 4 Slug	166.1	bbls
Height	2.6	meters
Mixers	Yes
Mud guns	Yes
Capacity, tank No. 5 Slug	166.1	bbls
Height	2.6	meters
Mixers	Yes
Mud guns	Yes

C-81

Capacity, tank No. 6 Slug		152.8	bbls
Height		2.6	meters
Mixers		Yes
Mud guns		Yes
F.2.4       Trip Tank
Capacity		65	bbls
Capacity/foot		3.05	bbls
Level indicator		Yes
Electric pump make		NOV
Model/type		Supreme 2500 3x2x13
Motor output		50	HP
Facility for casing fill-up		Yes
Alarm and strip chart recorder (See H.1.11)		Yes
Capacity		65	bbls
Capacity/foot		3.05	bbls
Level indicator		Yes
Electric pump make		NOV
Model/type		Supreme 2500 3x2x13
Motor output		50	HP
Facility for casing fill-up		Yes
Alarm and strip chart recorder (See H.1.11)		Yes
F.2.5       Stripping Tank
Capacity		10	bbls
Capacity/foot		0.87	bbls
Equalizing facility with triptank		Yes
Transfer pump		No
F.2.6       Chemical Mixing Tank
Capacity	Operating	260	liters
Chemical mixer type		Caustic Powder
F.2.7       Shale Shakers
Primary:
Quantity		1
Make/Model		NOV Brandt
Type		Dual Gumbo Box
Driven by no. of electric motors		2
Design flowrate (total)		2,200 (w/ 1” x 1” chain)	GPM
Cascading:
Quantity		8

C-82

Make/Model	NOV Brandt VSM-300
Type	Balanced, elliptical motion, low profile, cascade shaker
Driven by no. of electric motors	2
Design flowrate (total)
F.2.8       Desander
Quantity	1
Make/Model	NOV Brandt
Type	Hydrocyclone
Number of cones x sizes	3 x 12”
Centrifugal pump type	NOV Mission 8x6x14 2500 Surpreme
Centrifugal pump size	8” x 6” x 14” with 11.3/4” impeller
Driven by electric motor of	125 HP @ 1800 rpm class 1, group D, ex-proof for zone 2, with class F insulation, rated for 55 deg C ambient, 1.15 service factor, IP56, horizontal.
Is pump dedicated to desander	The vessel is equipped with 3x mud treatment pumps; due to proper piping configuration all pumps can alternatively feed the desander and the desilter.
Max. flowrate	1500	GPM
F.2.9       Desilter
Quantity	1
Make/Model	NOV Brandt
Type	VSM300 Desilter Header (24-cone)
Number of cones x sizes	24 x 4”
Centrifugal pump type	NOV Mission 8x6x14 2500 Surpreme
Centrifugal pump size	8 x 6 x 14 with 11.3/4 impeller
Driven by electric motor of	125 HP @ 1800 rpm class 1, group D, ex-proof for zone 2, with class F insulation, rated for 55 deg C ambient, 1.15 service factor, IP56, horizontal.
Is pump dedicated to desander	The vessel is equipped with 3x mud treatment pumps; due to proper piping configuration all pumps can alternatively feed the desander and the desilter.
Max. flowrate	1,500	GPM
F.2.10    Mud Cleaner	None
Quantity
Make/Model
Type

C-83

Number of cones x sizes
Centrifugal pump type
Centrifugal pump size
Driven by electric motor of
Is pump dedicated to desander
Max. flowrate
F.2.11    Mud/Gas Separator (Poor Boy)
Make/Type	M-I Swaco Super Mud Gas Seperator
Gas discharge line ID	12	inches
Gas discharge location, primary	Above water table in derrick
Can discharge be tied into burner system	No
Mud seal height	20	ft
Calculated gas throughput	65	mmscf
F.2.12    Degasser
Make/Type	Burgess Magna-Vac 1500
Centrifugal pump type
Centrifugal pump size
Driven by electric motor of power
Discharge line running to	MGS vent line in derrick
Vacuum pump make
Type
Make/Type	Burgess Magna-Vac 1500
Centrifugal pump type
Centrifugal pump size
Driven by electric motor of power
Discharge line running to	MGS vent line in derrick
Vacuum pump make
Type
F.2.13    Mud Agitators
Quantity	8
Make/Model	Brandt MA 30RG
Driven by motor of power	30	HP
Located in tanks (See F.2.1 for tank numbers)	Active pits - 4, 6, 7, 8, 9, 10, 11, 13
Quantity	2
Make/Model	Brandt MA 30RG
Driven by motor of power	30	HP
Located in tanks (See F.2.1 for tank numbers)	Reserve pits - 3, 4
Quantity	4
Make/Model	Brandt HMA 40RG
Driven by motor of power	40	HP
Located in tanks (See F.2.1 for tank numbers)	Active pits - 3, 5, 12, 14
Quantity	4

C-84

Make/Model		Brandt HMA 40RG
Driven by motor of power		40	HP
Located in tanks (See F.2.1 for tank numbers)		Reserve pits - 1, 2
Quantity		2
Make/Model		Brandt MA 40RG
Driven by motor of power		40	HP
Located in tanks (See F.2.1 for tank numbers)		Active pits 1
Quantity		4
Make/Model		Brandt HMA 25RG
Driven by motor of power		25	HP
Located in tanks (See F.2.1 for tank numbers)		Reserve pits: 5, 6, 7, 8
Quantity		6
Make/Model		Brandt VMA - 15RG
Driven by motor of power		15	HP
Located in tanks (See F.2.1 for tank numbers)		Slug Tanks: 15, 16, 17, 18, 19, 20
F.2.14    Mud Centrifuge		None
Quantity
Make/Model
Feed pump make/model
Capacity
F.2.15    Mud Hopper
Quantity		3
Make/Model		Vortex Type
Feed pump make/model
Capacity
F.2.16    Mud Laboratory and Facilities
Separate room	yes/no	Yes
Equipped with
Mud balance	yes/no	Yes
Marsh funnel	yes/no	Yes
Filtration kit	yes/no	Yes
Sand content kit	yes/no	Yes
Stopwatch	yes/no	No
F.3          BULK SYSTEM
F.3.1       Barite/Bentonite Silos
Quantity		6
Capacity of each silo		709	Sacks
Locations		Stbd
Type weight loadcell		4 load cells / 1 weight indicator

C-85

Manufacturer		NOV
Pressure rating		90 psi design and 72.5 psi operating
Relief valve(s) installed	yes/no	Yes
F.3.2       Cement Silos
Quantity		6
Capacity of each silo		709	Sacks
Locations		Port
Type weight loadcell		4 load cells / 1 weight indicator
Manufacturer		NOV
Pressure rating		90 psi design and 72.5 psi operating
Relief valve(s) installed	yes/no	Yes
Separate mud/cement loading facilities	yes/no	Yes
Discharge line for cement independent from	yes/no	Yes
barite/bentonite discharge line
F.3.3       Surge Tank for Barite/Bentonite
Quantity		2
Capacity of each tank		57	Sacks
Type weight loadcell		1 load cell / 1 weight indicator
Manufacturer		NOV
Pressure rating
Relief valve(s) installed	yes/no	Yes
F.3.4       Surge Tank for Cement
Quantity		2
Capacity of each tank	Total	83	Sacks
	Operating	7.6
Type weight loadcell		VC3500-5T for level monitoring, 3 ea unit
Manufacturer		NOV
Pressure rating	Design	6.2 / 90
	Max. Operating	5.5 / 80
Relief valve(s) installed	yes/no	Sempell safety relief valve 2 inch x 3 inch, 6.2 barg / 90 psi for overpressure relief, 1 ea unit
F.3.5       Bulk Transfer System
(See also C.1.8 - Compressed Air Systems)
Independent air system for the silos and surge tanks consisting of a high-volume low-pressure compressor and air drier	yes/no	Yes
Air reduced from main air supply through pressure regulators	yes/no	Yes
Separate volume tank and drier	yes/no	Yes

C-86

G.            CASING/CEMENTING EQUIPMENT
G.1         CASING EQUIPMENT
G.1.1      API Casing Drifts	None
For casing OD, weight, quantity
For casing OD, weight, quantity
For casing OD, weight, quantity
For casing OD, weight, quantity
G.1.2      Clamp-On Type Casing Thread Protectors	None
For casing OD, quantity
For casing OD, quantity
For casing OD, quantity
For casing OD, quantity
G.1.3      Side Door Casing Elevator
Quantity	2
For OD casing	30”	Inch
Make/Type
Capacity	150	Ton
G.1.4      Single Joint Casing Elevators
		Inch
Quantity	2
For OD casing	20”.
Make/Type
Safety latches
Wire rope size
Swivel size
Quantity	2
For OD casing	16”
Make/Type
Safety latches
Wire rope size
Swivel size
Quantity	2
For OD casing	13 5/8
Make/Type
Safety latches
Wire rope size
Swivel size

C-87

Quantity	2
For OD casing	13 3/8”
Make/Type
Safety latches
Wire rope size
Swivel size
Quantity	2
For OD casing	9 5/8”
Make/Type
Safety latches
Wire rope size
Swivel size
G.1.5      Slip Type Elevator/Spiders	None
Quantity
Make/Type
Capacity
W/slips for OD casing sizes
G.1.6      Casing Slips
Quantity	1
Make/Type
For OD casing	30”.	Inch
Quantity	1
Make/Type
For OD casing	20”.	Inch
Quantity	1
Make/Type
For OD casing	13 5/8”	Inch
Quantity	1
Make/Type
For OD casing	13 3/8”	Inch
Quantity	1
Make/Type
For OD casing	9 5/8”	Inch
G.1.7      Casing Bowls
Quantity	1
Make/Type
For OD casing (max/min)	30”	Inches

C-88

Quantity	1
Make/Type
For OD casing (max/min)	20”
Quantity	1
Make/Type
For OD casing (max/min)	16”
G.1.8      Casing Tongs	None
Quantity (sets)
Make/Type
W/jaws for OD casing (max/min)
Inserts / Jaws
G.1.9      Power Casing Tongs
Quantity	1 (to be used in conjunction with ARN 200)
Make/Type	Farr — KT-20000
W/jaws for OD casing (max/min)	8.5/8” to 20” OD.	Inch
	9 5/8”, 13 3/8”, 13 5/8”, 16” and 20”.	Inch
Max output torque
Torque indicator
Back-up arm
G.1.10    Power Unit For Casing & Tubing Tongs	None
Quantity
Driven by electric motor
G.1.11    Casing Circulating Head (Swedge)	None
For OD casing
Connection type
For OD casing
Connection type
For OD casing
Connection type
For OD casing
Connection type
G.1.12    Casing Spears (Internal)	None
Quantity

C-89

Make/Type
For OD casing
For casing weight
Pack-off
Quantity
Make/Type
For OD casing
For casing weight
Pack-off
Quantity
Make/Type
For OD casing
For casing weight
Pack-off
G.1.13    Casing Cutters (Internal)	None
Quantity
Make/Type
For OD casing (max/min)
Quantity
Make/Type
For OD casing (max/min)
Quantity
Make/Type
For OD casing (max/min)
G.1.14    Crossover to Handle Casing with Drill Pipe	None
Quantity
For OD casing
Casing connection
Drill pipe connection type
Rated capacity
Quantity
For OD casing
Casing connection
Drill pipe connection type
Rated capacity
Quantity
For OD casing
Casing connection
Drill pipe connection type
Rated capacity

C-90

G.1.15    Casing Scrapers	None
Quantity
Make
For OD casing
For casing weight
OD body
Connection type
Quantity
Make
For OD casing
For casing weight
OD body
Connection type
Quantity
Make
For OD casing
For casing weight
OD body
Connection type
Quantity
Make
For OD casing
For casing weight
OD body
Connection type
G.2         CEMENTING EQUIPMENT
G.2.1      Cement Unit
Owner	Halliburton
Free placement basis	Yes
Make/Type	HCS Electric Advantage
No. of triplex pumps	2 x HT 400 High-pressure pumps
Maximum working pressure	15,000 psi
Maximum flowrate	15.18 bpm @ 850psi total & 3.6 bpm @ 15,000psi
Unit powered by (electric/diesel)	Electric
Recirculating mixing system	RCM IIIr High Energy Mixing System
Capacity	One 25 bbl mixing tank with agitators
Motor power	One 6x5 Centrifugal Recirculation Pump
Liquid additive system
Premix/batch tank	One 20 bbl measuring tank with agitators
Quantity	1
Capacity	20 bbl

C-91

Pressure recorder	Yes
G.2.2      Cementing Manifold
Discharge manifold working pressure	15M
Cement pump discharge lines min. ID	76.2	MM
Cement pump discharge lines working pressure	15M
G.2.3      Cement Kelly	N/A
Quantity
Nominal size OD
Total length
Working length
Connection type
Cement head
G.2.4      Cementing Tubing	None
Size
Length (total)
X-overs to drillpipe specified in Section D.1.3
H.            INSTRUMENTATION/COMMUNICATION
H.1         DRILLING INSTRUMENTATION AT DRILLER’S POSITION
H.1.1      Weight Indicator
Make/Type	NOV Cyberbase
Sensor type	2 x M/D Totco load pins on travelling block
Calibrated for number of lines strung
(6, 8, 10, 12, etc.)	16 lines
H.1.2      Standpipe Pressure Gauges
Quantity	Main S.P 1 x NOV and 1 x WOM
	Aux S.P. 1x NOV and 1 x WOM
Make/Type	NOV Cyberbase — ScanSense
Pressure range	0 — 7,500
H.1.3      Choke Manifold Pressure Gauge
Quantity	2 x upstream 2x downstream
Make/Type	WOM

C-92

Pressure range	0 — 15,000
H.1.4      Rotary Speed Tachometer
Make/Type	NOV — RST755
Capacity range	5 — 15 RMP
H.1.5      Rotary Torque Indicator
Make/Type	NOV — RST755
Max Torque	45,000 ft/lbs or 61,000 Nm
H.1.6      Motion Compensator Instruments
Make/Type	N/A
Hook position indicator	N/A
Lock/unlock indicator	N/A
H.1.7      Pump Stroke Counters
Make/Type	NOV — SDI / Prox Switches
One pump stroke indicator and one cumulative
pump stroke counter for each pump.	3 sets counters per pump
	2 x to Cyberbase 1 x from 3rd party.
H.1.8      Tong Torque Indicator
Make/Type	NOV Cyberbase
Capacity range
H.1.9      Pit Volume Totalizer
Make/Model	Vaga — Flex 61
Floats in active mud tanks	Guided wave radar
Floats in reserve mud tanks	Guided wave radar
Loss/Gain indicator	Yes - Cyberbase
Alarm (audio and visual)	Yes - Cyberbase
H.1.10    Mud Flow Indicator
Make/Model	NOV — Paddle type
High/low alarm (audio and visual)	Yes - Cyberbase
H.1.11    Trip Tank Indicator
Make/Model	NOV Cyberbase
Chart recorder	NOV Cyberbase
Alarm	Yes - Cyberbase

C-93

H.1.12    General Alarm System
	Kongsberg
H.1.13    Automatic Driller
Make/Type	None
H.1.14    Remote Choke Control Unit
(See E.14.1)
Make/Model	EXPRO
H.2         DRILLING PARAMETER RECORDER
Quantity	4 x cyberchair plus 4 office workstations
Location - 1	Company Man office
Location - 2	Toolpusher office
Make/Type	NOV Cyberbase workstations
Quantity of pens	Can be setup for various channels
Parameter recorded	Can be setup to suit operator.
Parameter recorded
Parameter recorded
Parameter recorded
Parameter recorded
Parameter recorded
Parameter recorded
Parameter recorded
H.3         INSTRUMENTATION AT CHOKE MANIFOLD
H.3.1      Standpipe Pressure Gauge
Make/Type	Not yet specified
Pressure range (maximum)	15,000 PSI/KPA (Dual Read-Out) Local
	7,500 PSI / 150 deg (Cyberbase)
H.3.2      Choke Manifold Pressure Gauge
Make/Type	Not yet specified
Pressure range (maximum)	15,000 PSI
H.3.1 and H.3.2 combined on one panel
Visible from choke operating position

C-94

H.4         STANDPIPE PRESSURE GAUGE
(At Standpipe)
Make/Type		Not yet specified
Pressure range		0-15,000 PSI/KPA (Local), 7,500 PSI (Cyberbase)
Visible from driller’s position		Yes on Cyberbase
H.5         DEVIATION EQUIPMENT
H.5.1      Measuring Device		None
Quantity
Make/Type
Deviation range
H.5.2      Wireline Winch		None
Make/Model
Wire length (nominal)
Depth counter
Wire size
Pull indicator
H.6         CALIBRATED PRESSURE GAUGES
Make/type instrument guages		Not yet specified
Size
Connection		C/W 2” FIG.2202 union connection
Range		0-15,000 PSI/KPA (Local)
Quantity		4 x Standpipe (local) 2 x Standpipe (Cyberbase) 2 x Choke & Kill (local)
Facilities to install gauges on:
Standpipe Manifold		Yes
Choke Manifold		Yes
Cement Unit		Yes
H.7         RIG COMMUNICATION SYSTEM
H.7.1      Telephone System
No. of stations		240 Minimum
Make/Type		Nortel CS-1000
Explosion proof	Yes	Where Required per Class
No. of stations
Make/Type
Explosion proof

C-95

H.7.2      Public Address System
Can be combined with above	Yes	Yes
Make/Type		MRC / P4-AC-CS2DA
Explosion proof	Yes	Where Required per Class
H.7.3      Drill Floor - Derrickman’s Talkback
(For Intercom System)
No. of stations		13 + 5 Third Party
Location		Drillers Cabin, Bridge, Moonpool, Shaker House, Engine Control Room, Mud Pump Room, Drill Floor, Fingerboard Level, Forward Catwalk, Aft Catwalk, (2) ROV Control Vans, MWD, LWD, Cement Unit.
Make/Type		MRC / Echo-24CE
Explosion proof	Yes	Where Required per Class
H.7.4      Hand-Held VHF Radios
Quantity		6 Sets
Make/Type		Motorola HT 1250
H.8         ENVIRONMENTAL INSTRUMENTATION
H.8.1      Temperature Indicators
Air temperature		Yes
Make/Model		Kongsberg HMS 100
Sea water temperature		Yes
Make/Model		Skipper GDS 101
Recorder
H.8.2      Barometric Pressure Indicator
Make/Model		Kongsberg HMS 100
Recorder		Yes
H.8.3      Humidity Sensing Indicator FWD Radar Mast
Make/Model		Kongsberg HMS 100
Recorder		Yes
H.8.4      Wind Speed/Direction Meter Fwd Radar Mast
Make/Model		Gill WindObserver no.1 Intrinsically Safe. With 2m cable and PCI Unit.

C-96

Recorder
H.8.4      Wind Speed/Direction Meter Derrick Crown
Make/Model	OMC Wind Sensor 2, Obermet 150 EEX39 Display with 2-Gill Wind oberver & 2-OMC-160
Recorder
H.8.4      Wind Speed/Direction Meter Crown
Make/Model	OMC-139 (for OMC-160 sensor) Winddisplay 3
Recorder
H.8.4      Wind Speed/Direction Meter Crown
Make/Model	Gill WindObserver no.4 Intrinsically Safe.(With 2m cable and PCI Unit.
Recorder
H.8.5      Wave Profile Recorder
Make/Model	N/A
Recorder	N/A
H.9         ADDITIONAL MODU SPECIFIC INSTRUMENTATION
H.9.1      Roll, Pitch and Heave Indicator
Make/Type	Kongsberg MRU 5
Recorder	IDL
H.9.2      Gyro Compass	3
Make/Model	Mastercompass Navigat X MK1
Located at	2 on the Bridge and 1 in the ECR
H.9.3      Echo Sounder
Main Unit Make/Model	GDS-101
Located at	Bridge
Digital Indicator Make/Model	IR301
Located at	Bridge
Transducer Make/Model	ETN200SXG
Located at	Fwd Shell Bottom
Recorder/Printer	OKI ML 280
Located	Bridge
H.9.4      Current Indicator
Make/Model	None

C-97

Located at
Recorder
H.9.5      Weather Facsimile Recorder
Make/Model	Kongsberg Maritime JRC JAX-94
Located at	Radio Room
Recorder	Yes
H.9.6      Radar-S Band
Quantity	1 Scanner & 1 Display Unit
Make/Model	Kongsberg 65825WAR/KM
Located at	Forward Radar Mast/Display on Bridge
Bandwidth	S-Band
H.9.6.1   Radar- X Band
Quantity	1 Scanner & 1 Display Unit for both Fwd & AFT
Make/Model	Kongsberg 65830MHR/KM
Located at	Forward Radar Mast/Display on bridge
Bandwidth	X-Band
Quantity	1 Scanner
Make/Model	65825WAR/KM
Located at	Aft Radar Mast
Bandwidth	X-Band
H.9.6.2   Radar- DOPPLER WEATHER
Quantity	1
Make/Model	DOPRAD FURY 225EU
Located at	Bridge
Bandwidth	Variable
H.10       RADIO EQUIPMENT
H.10.1    SSB Transceiver
Quantity
Make/Model	SAILOR 6363
Power	250W
Frequency ranges	Transmit: 1.605-30MHz in ITU Marine Bands
	Receive: 150KHz-30MHz free
(Synthesized/crystal)	Yes
Facsimile capable	Yes

C-98

Telex capable	Yes
H.10.2    E.P.I.R.B’s
Quantity	2
Make/Model	Sailor SE-406 II
H.10.3    VHF Radio Telephone
Quantity	3
Make/Model	Sailor 6222
Power	25/0.9 watt
Channels	USA channels 70 DSC
H.10.4    VHF Radio Transceiver
Quantity	3
Make/Model	SAILOR SP3520
Power	RF Out Power 2W/1W
H.10.5    Radio Beacon Transmitter
Quantity	1
Make/Model	Kongsberg Maritime/TS-1B
Power	13W
H.10.6    Aeronautical VHF Transceiver
Quantity	2
Make/Model	Jotron TR-810
Power	10W Adjustable (40 W PEP)
Frequency range	117 - 137 MHz
(Synthesized/crystal)	Yes
H.10.7    Watch Receiver
Quantity	1
Make/Model	SAILOR 6363, Built in 6 channels DSC watch Receiver
Frequency	2.0000 - 24.9999 Mhz
H.10.8    Scrambler	None
Quantity
Make/Model

C-99

H.10.9    Telex
Quantity	1
Make/Model	Jaeun/Thrane & Thrane, Mcmurdo SmartFind GMDSS Navtex receiver - Freq- 518KHz, 490 KHz and 4209.5Kh 2 Channel 3 Frequencies with simultaneous reception of 518 and 490 or 4209.5
H.10.10     Satellite Communication System
Make/Model	Sailor/500
Type	BGAN Class 8
Facsimile link	Yes
Telex link	Yes
Telephone link	Yes
Other capabilities
H.10.11     MF/HF Radio
Make/Model	Jaeun/Thrane & Thrane, GMDSS Radio SAILOR 6320, 250W MF/HF Radio System, with transceiver/receiver SAILOR 6363 -
Frequency	Freq — 1.605-30MHz in ITU marine Bands and Receive 150KHz-30Mhz free. Remote MF/HF radio and DCS control unit SAILOR 6301
H.10.12     Other
SARTs
Make/Model	Jaeun/Thrane & Thrane, SAILOR SART II
Frequency	Freq- 9.2GHz — 9.5 GHz
AIS	Kongsberg Maritime AIS 200 Part no. 703564
VDR —	Kongsberg Maritime, Consilium, VDR FI, S-VDR SI
LRIT	Sailor 3027, with LRIT
	Rx Freq. 1525 - 1545 MHz
	Tx Freq. 1626.5 - 1646.5 MHz
BNWAS -	Kongsberg Maritime Midi Operator Station Part no. 4403239
ECDIS —	Kongsberg Maritime Part no. 305347, Marine Computer MP7900 NAV

C-100

I.             PRODUCTION TEST EQUIPMENT
I.1           BURNERS	None
Make/Type
Quantity
Capacity
Weight
Water requirement at 100 psi
I.2           BURNER BOOMS
Make/type
Quantity	None (Foundation for 2 provided)
Length
Horizontal
Height above sea level (at drilling draft)
Maximum wind speed
WalKWay and handrails
Burner platform size
Burner mounting rotatable
Regulatory approvals
I.3           LINES REQUIRED ON BURNER BOOMS
I.3.1        Oil Line
ID	4”
Working pressure	1500	psi
Connection type at burner end
H2S	yes
Pressure gauge connection at barge end
I.3.2        Gas Line
ID	4”
Working pressure	HP 1500 psi, LP 500 psi
Extended beyond burner by
Connection type at burner end
H2S	yes
Pressure gauge connection at barge end
I.3.3        Water Line
ID	6”
Working pressure	170psi
Connection type at burner end
Pressure gauge connection at barge end

C-101

I.3.4        Air Line
ID	4”
Working pressure	150 psi
Connection type at burner end
Pressure gauge connection at barge end
I.3.5        Pilot Gasline
ID	1
Working pressure	150psi
Connection type at burner end
Pressure gauge connection at rig end
I.4           SPRINKLER SYSTEM	Yes
Sufficient to give protection to rig and personnel against heat radiation damage from the burners	Yes, purpose built
I.5           FIXED LINES FOR WELL TESTING
I.5.1        Drillfloor To Separator Area
Type (Screwed/welded, both)	Welded
Quantity	One
Size ID	108.3	MM
Working pressure	15K	Psi
Connection type on drillfloor	Flange
Connection type at separator	Flange
Number of valves/lines	One line
Size of valves	No valves presently
H2S	Yes
I.5.2        Separator Area to Both Burner Boom	Design under review
Type (screwed/welded, both.)
Quantity
Size ID
Working pressure
Connection type at separator
Connection type at boom
Number of valves/lines
Size of valves
H2S
Valves installed near separator area for switching gas to either burner.
I.5.3        Mud Pumps To Both Burner Booms	Design under review
Type (screwed/welded, both)

C-102

Quantity
Size ID
Working pressure
Number of valves required
Size of valves
Connected to fire fighting pumps
Rated line capacity at 300 psi
I.5.4Rig Air System To Burners	None
Type (screwed/welded, both)
Quantity
Size ID
Working pressure
Non-return valves fitted
I.5.5Oil Storage Tank To Overboard	None
Type (screwed/welded, both)
Quantity
Size ID
Working pressure
Height above water level
Connection type at separator area
I.5.6Separator To Ventstack Of Rig	None
Type (screwed/welded, both)
Quantity
Size ID
Working pressure
Connection type at separator area
I.6AUXILIARY POWER AVAILABILITY
I.6.1For Field Laboratory	To be Specified
Quantity
Volts
Frequency
I.6.2For Crude Transfer Pump	To be Specified
Quantity
Volts
Frequency
I.6.3For Electric Heaters	To be Specified

C-103

Quantity
Volts
Frequency
J.WORKOVER TOOLS	None
(nonapplicable)
K.ACCOMMODATION
K.1OFFICES
K.1.1Company Representative’s Office
Quantity	1
Complete with desk, filing cabinet(s) and other necessary furniture	Yes
Unrestricted view to drill floor	Yes
K.1.2Contractor Representative’s Offices
Quantity	1
Unrestricted view to drill floor	Yes
K.1.3Radio Room
Quantity	1
K.1.4Hospital Room
Number of beds/bunks	4
Wash basin	Yes
Medical cabinet	Yes
Dangerous drugs	Yes
K.2LIVING QUARTERS
K.2.1Accommodations
Total quantity	210	persons
Quantity of single bed rooms	22
toilet (private/shared/communal)	private
Quantity of two bed rooms	94
toilet (private/shared/communal)	private
Quantity of four bed rooms	0
toilet (private/shared/communal)	N/A

C-104

Quantity of six bed rooms		0
toilet (private/shared/communal)		N/A
Quantity of eight bed rooms		0
toilet (private/shared/communal)		N/A
K.2.2Galley
Quantity		1
K.2.3Mess Seating Capacity
Main mess		112	persons
Aux. mess		N/A
K.2.4Meeting Rooms
Conference room (20 person)	Yes	59.8	m2
K.2.5Recreation Rooms / Puplic Spaces
Recreation facilities:	Yes	48.3	m2
TV	Yes
VCR	Yes
Pool Table	No
Ping Pong Table	No
Internet room	Yes	17.8	m2
Gaming room	Yes	10.4	m2
Clean break room (Nav. Bridge deck)	Yes	13	m2
Non-Smoking dirty break room (main deck)	Yes	26.6	m2
Smoking dirty break room (main deck)	Yes	14.6	m2
K.2.6Other Rooms
Laundry	Yes
Dry food store	Yes
Refrigerator	Yes
Change Rooms	Yes
Prayer Room	No
Cinema (111 person)	Yes	154.3	m2
Workout/Weight Room	Yes	53.5	m2
L.SAFETY EQUIPMENT
L.1GENERAL SAFETY EQUIPMENT
L.1.1General Personnel Protective Gear
Safety hats (contractor only/everyone/not supplied)		Contractor as required (Per HSE Policy)

C-105

Safety boots (contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
Safety clothing (contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
Ear protection (contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
Rubber gloves (contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
Rubber aprons (contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
Fullface visors (contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
Eye shields (for grinding machines, etc.)
(Contractor only/everyone/not supplied	Contractor as required (Per HSE Policy)
Dust masks (contractor only/everyone/ not supplied)	Contractor as required (Per HSE Policy)
Rubber gloves - elbow length for chemical handling
(Contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
Explosion proof handtorches c/w batteries
(Contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
Safety belts c/w lines (contractor only/everyone/not supplied)	Contractor as required (Per HSE Policy)
L.1.2Eye Wash Stations
Quantity	20
Make/model
Located at	Sack Store Room (x2)
Located at	Mud Pit Room (x2)
Located at	Close to Moonpool (x2)
Located at	Shale Shaker Room
Located at	No. 1 Engine Room
Located at	No. 2 Engine Room
Located at	No. 3 Engine Room
Located at	Rig Mechanic Shop
Located at	Weld Shop
Located at	SubSea Shop
Located at	Galley
Located at	Laundry
Located at	Near Paint Locker
Located at	Warehouse
Located at	Cementing Unit Room
L.1.3Derrick Safety Equipment
Derrick escape chute (rem chute)	To be specified as required
Make/Type	NOV- Platform Type

C-106

Derrick safety belts
Make/Type
L.1.4Derrick Climbing Assistant
Make/Type	NOV Elevator in Derrick
L.1.5      Fresh Air Blowers (Bug Blowers)	None
Quantity
Make/Type
Located at
Located at
L.2GAS/FIRE/SMOKE DETECTION
L.2.1H2S Monitoring System
Make/Type	Autronica AutroPoint TX-50.Ex.;
Sampling points at:
Bellnipple	Yes
Drillfloor	Yes
Shale shaker	Yes
Mud tanks	Yes
Ventilation system into living quarters	Yes
Other	2 Engine Rooms
General alarm	Yes
Alarm types (audible, visual, both) at:	Both
Driller’s console	Yes
Engine room	Yes
Mud room	Yes
Living quarters each level	Yes
Central area each structural level	Yes
Other
Central alarm panel	Yes
Located at	Bridge
L.2.2Combustible Gas Monitoring System
Make/Type	Autronica Autro Point HC200, Ex.
Sampling points at:	Yes
Bellnipple	Yes
Drill floor	Yes
Shale Shaker	Yes
Mud tanks	Yes
Ventilation system into living quarters	Yes
Other	2 Engin Rooms
General alarm	Yes
Alarm types (audible, visual, both) at:	Both
Driller’s console	Yes

C-107

Other	Machinery and Workshop Spaces
L.2.3H2S Detectors (Portable)
Quantity	3
Make/Type	Draeger XAM 7000 Multigas
Phials for H2S: measuring range
from 1 to 20 ppm
from 100 to 600 ppm
L.2.4CO2 Gas Detectors (Portable)
Quantity	See L2.3
Make/Type
Phials for CO2: measuring range
from 1 to 20 ppm
from 20 to 200 ppm
L.2.5Explosimeters	See L2.3
Quantity
Make/Type
L.2.6Fire/Smoke Detectors in Accommodation
Make/type Fire detection	Autronica, Autrosafe - self verifying system
Smoke detection	Autronica BH-500, optical Autronica BH-500Ex, optical Autronica BHH-520,optical/heat Autronica BHH-520/Ex, optical/heat Autronica BD-500, heat Autronica BD-501/Ex, heat Autronica AutroFlame FD-X33AF, infrared flame
Central alarm panel	5 x control panels - networked
Location	2 x General Electric Space (Accom) 3 x Aft (Swbd Rooms)
L.3FIRE FIGHTING EQUIPMENT
L.3.1Fire Pumps
Quantity	2
Make/Model	ShinShin- Hamworthy
Type	Centrifugal
Output	2 x 670m3/hr main fire pumps, Head 100m

C-108

All offtake points supplied by each pump	Yes
Location of pumps	Main fire pump No.2 Aft Pumproom
Location of pumps	Emergency fire pump No.1 Fwd pump rm
Fire fighting water delivery conforms to IMO MODU spec	Yes
IMO MODU spec version	2009
L.3.2Hydrants and Hoses
Hydrants positioned such that any point may be reached by a single hose length from two separate hydrants	See Fire Plan for details
Quantity of hydrants	56
Hose connections/hydrant	Quick coupling (STORTZ)
Hose max. diam.	50mm
Length	15m~ 25m depending on the area
L.3.3Portable Fire Extinguishers
Quantity (total)	263 (see Approved Fire Plan for detail)
Type 1- CO2	63
Type 2 - Dry chemical	191
Type 3 - Foam	9
Mounted adjacent to access ways and escape routes	As per Fire Plan
L.3.4 Fire Blankets
Location	1
Quantity	Galley
L.3.5Fixed Foam System
Automatically injected into fixed fire water system at central point with remote manual control	Pits
Make/Type	NK / SLG - FL V310
Quantity foam stored on site	800	liters
Inductor tube	located on tank in system room
Foam nozzles
Located at
Located at
Located at

C-109

L.3.6Helideck Foam System
Dedicated system adequate for at least 10 minutes fire fighting at the rate quoted in the IMO MODU code IMO MODU code version	Yes, as per SOLAS, ABS “HELDK (SRF) “ and CAP 437
Make/Type	SKUM / FJM-80 Oscillating
Quantity of monitors	3
Foam type	AFFF
Rate	2 pumps 165 m3/h each
L.3.7Fixed Fire Extinguishing System
Protected spaces
Engine room, type (Halon/CO2)	Water mist
Paint locker, type (Halon/CO2)	Novec 1230 Fixed flood
Emergency generator, type (Halon/CO2)	Water mist
SCR room, type (Halon/CO2)	N/A
Other (specify location & type)	Novec 1230 Fixed Flood - ECR, Switchboard rooms, Thruster VFD/transformer rooms, transformer rooms, thruster rooms
Alarms (audible, visual or both)	Audible & Visual
Automatic shutting of mechanical ventilation in protected spaces	YES
Remote manual release located at	Outside of each space.
Remote manual release located at	ECR & CCR Panels
Remote manual release located at	Fire Control Room (water mist only)
L.3.8Manual Water Deluge System
Protected spaces	Drill Floor
Protected spaces
Water supplied from fire main line	Yes
L.3.9Water Sprinkler System in Accommodation
Automatic	Yes
Working pressure	6 bar
Pressurized tank capacity	3000 Liter
L.4BREATHING APPARATUS
L.4.1General Sets
Quantity	10
Make	Drager

C-110

Type	PAS
Bottle duration	30	minutes
Located at	4 x forward fire locker
Located at	4 x aft fire locker
Located at	2 x drill floor
Quantity	4
Make	Drager
Type	PAS
Bottle duration	30	minutes
Located at	2 x helideck
Located at	2 X ECR
Located at
L.4.2Derrickman Escape Sets
Quantity	25
Make/Type	MED Wheelmark
Bottle duration	10	minutes
Located at	as per fire plan
L.4.3Cascade Stations
Quantity	9
Make/Type	Worthington Cylinder 300 Bar
Locations/outlets at location	Drillers House, Drillfloor, Mud Pit Room
Locations/outlets at location	BOP Control Room, ECR
Locations/outlets at location	Mud Logging Unit, Mud Processing Area
Locations/outlets at location	Nav Bridge, Mud Pump Room
	Note: All manifolds have 6 connections
L.4.4Breathing Air Recharge Compressor
Quantity	2
Make/Type	Paramina/Cyclone
Located at	Fwd Rope Store
Located at	Electrical Store Room (Aft)
L.4.5Compressed Air Breathing Aparatus Trolley Unit	N/A
Positive pressure
Make/Type
Air line length
Compressed air bottles
Quantity
Size
Including

C-111

Face mask
Demand valve
Microphone
Safety harness
Safety line (incorporating telephone line)
L.4.6Air Purity Test Equipment	To be Specified
Quantity
Make/Type
L.5EMERGENCY FIRST AID EQUIPMENT
L.5.1First Aid Kits	As Per Safety Plan
Quantity
L.5.2Burn Kits	Hospital
Quantity
L.5.3Resuscitators	Hospital
Quantity	3xAED - ECR, Drillfloor & Messroom
Charged (spare) oxygen cylinders	Hospital
L.5.4Stretchers
Quantity	2
Type	Flat type
Located at	Medical Treatment room (F’csl deck)
Quantity	2
Type	Rescue type
Located at	Medical Treatment room (F’csl deck)
L.6HELIDECK RESCUE EQUIPMENT
L.6.1Storage Boxes
Quantity	1
Construction material	GRP
Max height open
L.6.2Equipment	As Per CAP 437

C-112

Aircraft axe	1
Large firemans rescue axe	2
Crowbar	1
Heavy duty hacksaw	1
Spare blades	6
Grapnel hook	1
Length of wire rope attached	4M
Quick release knife	4
Bolt croppers	1
L.7RIG SAFETY STORE	As Per SOLAS
Equipment to repair, recharge and restock safety equipment as listed below:
Foam concentrate	1
Dry chemical charges	29
CO2 charges for dry chemical extinguishers	39
CO2 charges for water extinguishers	N/A
CO2 charges for foam extinguishers	N/A
Discharge hoses, control nozzles and horns and washers for CO2 extinguishers	Yes
Discharge hoses, control nozzles and horns and washers for dry chemical extinguishers	Yes
Fire blankets	1
Fireproof gloves	6 Pairs
Rubber gloves - elbow length	Yes
Rubber aprons	Yes
Rubber boots	Yes
Full face visors	Yes
Eye shields (for grinding machines, etc.)	Yes
Dust masks	Yes
Spare safety helmets, boots, overalls	Yes
Gloves, hand torches, batteries, etc.	Yes
Spare lifebuoys	2
Spare lifebuoy lights	2
Fresh air blowers/inductors for ventilating enclosed spaces	Yes
Spare life jackets	Yes to meet SOLAS
Safety belts c/w line	Yes
Full safety harness	Yes
Spare derrickman’s safety belts	Yes
Spare CABA bottles, charged	Yes
L.8EMERGENCY WARNING ALARMS
Approved system to give warning of different emergencies	Yes
L.9SURVIVAL EQUIPMENT

C-113

L.9.1Lifeboats
Make/Type	Hyundai
Quantity	6
Capacity	70	persons
Locations (fore, aft, port, stbd)	P&S fwd and aft
Fire protection	Yes
Radios	Yes
Flares	4x Rocket/parachute, 6x Hand flare, 2x Smoke
Food	Yes
First aid kits	Yes
L.9.2Liferafts
Make/Type	VIKING 25DK+ Liferaft for 25 persons, roll off type with cradle & hydrostatic release
Quantity	18
Capacity	25	persons
Davit launched	No
Locations (fore, apt, port, stbd)	12 Forecastle deck and 6 aft poop deck (Ports/Stbd)
Fire protection	As per location design
Radios	Portable
Flares	6 x Hand, 4 x Smoke
Food	Yes
First aid kits	Yes
L.9.3Rescue Boat
Make/Type	Hyundai Rescue Craft, 6 person
Engine power	50	HP
L.9.4Life Jackets
Make/Type	Rigid type for adult with light & whistle
Quantity	641 (420 in lifeboats, 210 cabins, 6 rescue boat, 3 Nav deck, 2 Eng Cont Rm)
L.9.5Life Buoys
Make/Type	Self igniting light & self activating smoke, with quick release device
Quantity	2 - on Nav deck P&S
Make/Type	Self ignite light
Quantity	5 (various locations)

C-114

Make/Type	With life line
Quantity	8 (various locations)
L.9.6Work Vests
Make/Type	Mustang HIT inflatable
Quantity	30
L.9.7Escape Ladders/Nets
Make/Type	Embarcation Ladders
Quantity	6 (2x Fcsl, 2x Stern, 2 Main deck)
Make/Type	For Accomodation ladders
Quantity	2x Main deck
L.9.8Distress Signals
Type	Rocket / Parachute
Quantity	1x set (of 12) - on Nav Deck/Bridge
M.POLLUTION PREVENTION EQUIPMENT
M.1SEWAGE TREATMENT
Make/Model	Accommodation Evac/Jet/ST8-C Super Trident , Aft Gravity type ST2A-C Super Trident
System type	Fwd Vacuum, Aft Gravity
Conforms to (Marpol annex IV, etc.)	Yes
M.2GARBAGE COMPACTION
Make/Model	Dolphin / SFP-40
System type	Compactor
Conforms to (Marpol annex IV, etc.)	Yes
M.3GARBAGE DISPOSAL/GRINDER
Make/Model	Dolphin / Model TG7.5
System type	Tuff —Gut
Conforms to (Marpol annex IV, etc.)	YES

C-115

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDIX D

EQUIPMENT, SERVICES AND FACILITIES FURNISHED

The following table identifies the responsibilities of both Parties, including the financial responsibilities, for the provision of additional equipment, materials, supplies and services.  Operator is designated “OPR” or “Operator”, Contractor as “CON” or “Contractor”, and the Rig as “Rig”.

		Provided By		To Account
A. DRILLING LOCATION		OPR	CON	OPR	CON
1	Licenses, permits and certificates of financial responsibility (excepting for Rig) relating to, and consents to perform, the Work, including suspension or abandonment thereof.	X		X
2	Fees, licenses, pilotage fees, wharfage fees, harbor fees and costs or similar charges, including any sales taxes or clearing agent or brokerage fees, relating to Contractor’s Items and replacements or spare parts.		X		X
3	Fees, licenses, pilotage fees, wharfage fees, harbor fees and costs or similar charges, including any sales taxes or clearing agent or brokerage fees, relating to Operator’s Items and replacements or spare parts.	X		X
4	Location surveys including marker buoys, side scan sonar, sea floor surveys, sea/Metocean conditions and bathymetry charts and seabed cores/samples and analysis, if required by Contractor (riser analysis provided by Contractor at Operator’s expense).	X		X
5	Well location verification.	X		X
6	Insurance underwriter representatives (if required).		X		X
7	Acoustic beacons, repair and replacement of Contractor-provided acoustic system.		X		X

		Provided By		To Account
B. TRANSPORTATION/HANDLING		OPR	CON	OPR	CON
1	Air and land transportation for all Contractor’s Personnel to Operator’s shorebase heliport (if applicable).		X		X
2	Helicopter transport for Contractor’s Personnel and Operator’s personnel between Operator’s heliport and Rig and return.	X		X
3	Helicopter transport for Contractor’s ill or injured personnel (Medivac or dedicated flight).	X		X
4	Helicopter refueling system aboard Rig, including fuel tanks, fuel tank stand, fuel pump and filters, hoses, and grounding system as per Appendix C.		X		X
5	Helicopter fuel and lubes.	X		X
6	Non-directional beacon for helicopter operations.	X		X
7	Special or additional helicopter safety equipment aboard Rig.	X		X
8	Accommodation, meals, transportation and overtime for Contractor’s Personnel unavoidably incurred as a result of delays in helicopter transport between Operator’s shorebase heliport and		X	X

D-1

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

		Provided By		To Account
B. TRANSPORTATION/HANDLING		OPR	CON	OPR	CON
	Rig due to unavailability or delay of the aircraft, provided that Contractor’s Personnel have complied with Operator’s travel instructions.
9	Accommodation, meals, transportation and overtime for Contractor’s Personnel during evacuations due to weather or other safety reasons.		X	X
10	Marine and land transportation of Contractor-owned equipment and supplies to designated shore base of Operator.		X		X
11	Cargo baskets:
	·   cargo baskets for use in transporting Contractor’s Items, and		X		X
	·   cargo baskets for use in transporting Operator’s Items.	X		X
12	Transportation of Contractor’s materials and spare parts from Operator’s shorebase location to and from Rig.	X		X
13	Extra labor (in excess of supply vessel’s personnel) required aboard supply vessels when alongside Rig to unload or load Contactor’s and/or Operator’s Items.	X		X
14	Dock and dockside facilities, labor and equipment for loading/unloading Operator’s equipment and Contractor’s equipment at Operator’s shore base.	X		X
15	Offloading facilities to transfer cargo to and from Rig to Operator’s supply vessel(s).		X		X
16	Storage space:
	·   storage space at Operator’s shore base for Contractor’s Items, and		X		X
	·   storage space at Operator’s shore base for Operator’s Items.	X		X
17	Serviceable set of boat mooring lines, fenders and hoses acceptable to Operator at the Term Commencement Date for transfer of bulk and liquid materials between supply vessel and Rig.		X		X
	Replacement boat mooring lines and hoses for transfer of bulk and liquid materials between supply vessels and Rig and end of Drilling Contract term set.		X	X
18	Waste disposal: ·   transportation, supply of containers, and cost of disposal, of non-hazardous oilfield waste generated by the Designated Well,	X		X
	·   transportation, supply of containers, and cost of disposal, of reasonable volumes of non-hazardous oilfield waste generated by Rig,	X		X
	·   transportation, supply of containers, and cost of disposal, of hazardous waste generated by the Designated Well or Operator,	X		X
	·   transportation to shore, and supply of containers and documents, of hazardous waste generated by Rig, and	X		X
	·   onshore transportation, supply of containers and documents, and cost of disposal, of hazardous waste (paints, thinners, oil, oily rags, etc.) generated by Rig or Contractor.		X		X
19	Trash compactor unit as per Appendix C.		X	X
20	Supply of waste bags for trash compactor unit.	X		X

D-2

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

		Provided By		To Account
B. TRANSPORTATION/HANDLING		OPR	CON	OPR	CON
21	Standby vessel (if required).	X		X

		Provided By		To Account
C. THIRD PARTY SERVICES		OPR	CON	OPR	CON
1	ROV and diving equipment services and installation costs.	X		X
	Surface diving services for hull inspections and Contractor’s marine equipment.		X		X
2	Drill stem testing tools and services.	X		X
3	Wire line formation testing and side wall sample equipment.	X		X
4	Electric well logging equipment and services.	X		X
5	Mud logging equipment and services.	X		X
	·   Services for set-up of mud logging equipment (power, water, air, communications, etc.).		X	X
6	Mud engineering services and supervision.	X		X
7	Provision of drilling fluids laboratory and equipment (if required).	X		X
8	Well drilling fluids laboratory equipment.	X		X
9	Acidizing and fracturing services.	X		X
10	Directional drilling equipment and services.	X		X
	·   Services for set-up of directional drilling equipment (power, water, air, communications, etc.).		X	X
11	Cementing unit (free placement).		X		X
	·   Repair and maintenance of cement unit.	X		X
	·   Cementing services.	X		X
12	Coring, formation testing and equipment.	X		X
13	Gun and perforating services.	X		X
14	Tubing and casing running services.	X		X
15	Welding:
	·   normal welding and services required on Operator’s Items to the extent available from Contractor’s Personnel,		X		X
	·   welding material used on Operator’s Items, and		X	X
	·   extra welders and welding material used on welding and cutting Operator’s equipment as authorized by Operator.		X	X
16	Well completion services.	X		X
17	Measurement while drilling services (MWD).	X		X
	·   Services for set-up of directional drilling equipment (power, water, air, communications, etc.).		X	X
18	Liner installation services.	X		X
19	Wellhead installation and recovery services.	X		X
20	Weather forecasting and reporting services.	X		X
21	Satellite phone system from Rig to Operator’s and Contractor’s offices, shore base and supply vessels:
	·   satellite phone and data system from Rig to Contractor’s office and shore base including permits and licenses, and		X		X
	·   satellite phone and data system from Rig to Operator’s office and shore base including permits and licenses.		X	X

D-3

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

		Provided By		To Account
D. MATERIALS AND SUPPLIES		OPR	CON	OPR	CON
1	Cement and cement additives.	X		X
2	Drilling fluids and additives, lost circulation and completions fluids.	X		X
3	Fuel for Rig upon her arrival at Operator’s designated location in the Area of Operations and pursuant to Section 5.4 of this Drilling Contract.	X		X
4	Grease and lubricants for Rig and Contractor’s equipment.		X		X
	·   Tool joint compound for Operator-supplied tubulars.		X	X
	·   Thread compound for Contractor’s DC’s and premium tubing.		X		X
	·   Thread compound for Contractor’s drillpipe.		X		X
5	Casing and tubing dope and drift mandrels.	X		X
6	Hydraulic fluid and anti-freeze (if required) for BOPs and control unit.		X		X
7	Water for drilling, wash down and cementing.	X		X
8	Potable water in excess of production of distillation unit on board Rig.	X		X
9	Drilling bits, diamond bits, core-heads and catchers.	X		X
10	Shale shaker screens up to 60 mesh.		X		X
	Shale shaker screens over 60 mesh.		X	X
11	Scalping screens up to 60 mesh.		X		X
12	Mud drying equipment / centrifuges.	X		X
	Services for mud drying equipment and centrifuges (space, power, water and air).		X	X
13	Contractor shall provide the maintenance, repair and repair parts of:
	·   Contractor’s surface equipment, and
	·   elastomer and rubber goods in Contractor’s BOPs:		X		X
	·  initial supply in new condition for standard service at the Term Commencement Date, and		X		X
	·  replacement goods for the initial set of Contractor’s subsea equipment (including new set at end of term of this Drilling Contract).		X	X
14	100 psi air supply in moonpool and on Rig floor available and able to service all completions/well test requirements.		X		X
15	Low pressure water supply at moonpool.		X		X
16	Routine inspection, repair and/or replacement of Contractor-supplied subsea equipment (except as otherwise provided in this Drilling Contract).		X		X

		Provided By		To Account
E. DRILLING RIG AND EQUIPMENT		OPR	CON	OPR	CON
1	Contractor’s equipment and materials as specified in Appendix C.		X		X
2	Except as otherwise specified, maintenance and repair, including repair parts of Contractor’s Items.		X		X
3	Drill pipe, drill collars and handling tools other than those specified in Appendix C.	X		X
4	Fishing tools, other than those specified in Appendix C.	X		X
5	Tubing handling equipment.	X		X
6	Cementing heads.	X		X

D-4

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

		Provided By		To Account
E. DRILLING RIG AND EQUIPMENT		OPR	CON	OPR	CON
7	Drilling jars.	X		X
8	Hole openers.	X		X
9	Reamers, under reamers and stabilizers.	X		X
10	Effective mud waste reduction devices, including drillpipe OD wipers and competent mud-bucket.		X		X
	Mud vacuum.	X		X
11	Mechanical casing cutters and casing spears.	X		X
12	Backup hydraulic power supply for Third Party contractor’s casing power tongs as per Appendix C.		X		X
13	Mud pump fluid and power end parts and consumables.		X		X
	Mud pump pistons and liners (of size 5.5 inches).		X		X
	Mud pump pistons and liners (of size 6 inches).		X		X
14	Spares for choke manifold, being one full replacement item and one complete overhaul kit for each type of valve or choke on the choke manifold.		X		X
15	Drill pipe:
	·   initial inspection of Contractor’s drill pipe, drill collars and HWDP as outlined in Appendix C, (i) to the extent that such equipment is in new condition, in accordance with inspection standards to be mutually agreed upon Contractor and Operator and with API Spec 5D and API Spec 7, and (ii) to the extent that such equipment is in used condition, in accordance with T. H. Hill & Associates Drill Pipe Inspection Standards, DS-I, Category 5 and with API Spec 5D, API Spec 7 and API RP7G.		X		X
	·   inspection and repair of Contractor’s drill pipe, drill collars and other in-hole equipment, according to DS1, Volume 3, 4th Addition, Cat 3 dimensional, Cat 5 inspection, after the Work commences under this Drilling Contract at reasonable intervals requested by Operator, and	X		X
	·   inspection and repair of Contractor’s drill pipe, drill collars and other in-hole equipment, according to DS1, Level 5 specification, at end of term of this Drilling Contract.		X	X
16	·   Initial supply of new riser seals, choke, kill and hydraulic line seals.		X		X
	·   Replacement of seals identified above:
	·  50% of replacement seals, and		X		X
	·  50% of replacement seals.		X	X
17	Mouse hole or equivalent alternative.		X		X
18	Cranes with sufficient wire and bulk hoses to enable use at transit draft or mutually agreed alternative as per Appendix C.		X		X
19	Mud pits re-coating if determined by Contractor’s maintenance and inspection program. Contractor will supply inspection reports to Operator.		X		X
20	·   Low range pressure gauge fitted to poor-boy degasser.		X		X
	·   Separate high (0-10,000 psi) and low (0-200 psi) gauges on choke panel with separate choke, kill and drill pipe gauges.		X		X
21	Contractor shall be responsible for any modifications to BOP support frame to enable BOP connector to interface with Operator’s wellheads and subsea trees.		X	X

D-5

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

		Provided By		To Account
F. WELL EQUIPMENT		OPR	CON	OPR	CON
1	All tubular goods, including casing, tubing, hangers and packers.	X		X
2	Casing shoes, collars, baskets, centralizers, float equipment, baffles, scratchers, etc.	X		X
3	Permanent and temporary guide bases.	X		X
4	Wellhead Equipment.	X		X
	Wellhead connector seal ring from BOP stack to wellhead.		X	X
	Wellhead connector seal ring from BOP stack to LMRP.		X		X
5	Valves, Xmas trees and necessary tools and equipment for installation.	X		X

		Provided By		To Account
G. SAFETY		OPR	CON	OPR	CON
1	First aid, infirmary, equipment and medical attention on board Rig for all persons while on board.		X		X
2	Firefighting equipment as required for compliance with regulations.		X		X
3	Onshore medical services for Contractor’s Personnel.		X		X
4	All necessary lifesaving and safety equipment for compliance with regulations and requirements of Billy Pugh X904 (or equivalent).		X		X

		Provided By		To Account
H. MISCELLANEOUS		OPR	CON	OPR	CON
1	All hand and power tools required for normal maintenance of Rig components and its equipment.		X		X
2	Meals and quarters for all of Contractor’s Personnel and up to and including seven (7) Operator’s personnel.		X		X
3	Meals and quarters for all of Operator’s personnel and Operator’s third party personnel to be charged at $150.00 per day per person in excess of seven (7) per day based on POB from IADC Daily Drilling Report.		X	X
4	Onboard entertainment, video, films and satellite TV.		X		X
5	Contractor’s Personnel as per Appendix B.		X		X
6	Extra Contractor’s personnel as requested by Operator other than those specified in Appendix B.		X	X
7	Overtime for Contractor’s Personnel authorized by Operator in writing or caused by delays in Operator-provided transport.		X	X
8	·   PPE for Contractor’s Personnel for completion fluid, where required.	X		X
	·   PPE for Operator’s personnel for completion fluid, where required.	X		X
9	At least 6 m2 of dry air-conditioned storage for Operator’s tools, equipment and spares.		X		X
10	Acoustic doppler current profiler inclusive of winch assembly (if required by Contractor).	X		X

D-6

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDIX E

INSURANCE

A.Minimum Insurance Coverage to be maintained by Contractor

Prior to the Term Commencement Date and during the term of this Drilling Contract, when reasonably requested by Operator, Contractor shall furnish, or cause to be furnished, to Operator for viewing at Contractor’s offices during normal business hours copies of insurance policies evidencing the insurance coverage required of Contractor under Article IX of the Drilling Contract and this Appendix E, placed with insurers with an A.M. Best rating of “A-VIII” or better and who are authorized to do business in the geographical area where the Work is to be performed.  Contractor’s insurance policies are confidential information within the meaning of, and subject to, Article XVII of the Drilling Contract.  The types and amounts of insurance (through insurance, including self-insured retentions and/or deductibles in reasonable amounts consistent with customary industry practice) set forth in this Appendix E, Part A are the minimum types and amounts or their equivalent that Contractor must obtain and maintain during the term of this Drilling Contract.

If insurance is provided on a “claims made” basis, coverage in each case shall provide for and maintain a retrospective date prior to or concurrent with the commencement of the Work and an automatic extended reporting period of no less than ninety (90) days.  Such “claims-made” coverage shall be maintained continuously, on substantially the same material terms to the extent reasonably commercially available, for a period of at least five (5) years following completion of the Work, through extension or renewal of such coverage or through the purchase, at Contractor’s sole expense, of an additional extended reporting period and/or run-off or “tail” coverage acceptable to Operator.  In the event Contractor is notified of any intention of the issuer or underwriter of any such “claims-made” coverage not to renew such coverage during the period required by this Drilling Contract, Contractor shall notify Operator within thirty (30) days.

The types and limits of insurance coverage specified below are minimum requirements and shall not be deemed to constitute, or be construed as, a limitation on Contractor’s liabilities under this Drilling Contract or as constituting acceptance by Operator of any responsibility for financial or other liabilities or indemnities in excess of such limits.

1.Commercial General Liability (bodily injury and property damage) insurance with limits of not less than One Million U.S. Dollars (US $1,000,000.00) combined single limit per occurrence and not less than Two Million U.S. Dollars (US $2,000,000.00) in the aggregate including the following supplementary coverage:

E-1

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

A.Contractual Liability to cover the indemnities and liabilities contractually assumed by Contractor under this Drilling Contract including cross liability and severability of interest;

B.Completed Operations Hazard Coverage for any claim relating to defects or deficiencies in services rendered by Contractor in connection with its operations;

C.Broad Form Property Damage Liability insurance;

D.Coverage for explosion, collapse, and underground hazards for Work performed by Contractor involving equipment or materials of a volatile, incendiary or explosive nature or involving excavation activity;

E.Independent Contractor’s Coverage;

F.Personal Injury Liability;

G.Premises Liability;

H.In Rem Endorsement;

I.Territorial extension to cover all areas where Work is performed and the Area of Operations;

J.Watercraft exclusion deleted;

K.Seepage and Pollution Liability on a sudden and accidental basis, including, without limitation, cleanup;

L.“Care, custody, and control” exclusion deleted; and

M.Coverage for punitive damages where allowed by applicable law.

2.Automobile Liability Insurance covering owned, hired and non-owned vehicles or automotive equipment used by Contractor with limits of One Million U.S. Dollars (US $1,000,000.00) combined single limit per occurrence for bodily injury and property damages.

3.Workers’ Compensation and Occupational Disease Insurance in accordance with the state, federal, and maritime laws and requirements (as appropriate) of the state or offshore location where the Work is to be performed, the state in which Contractor’s employees reside and the state in which Contractor is domiciled;

E-2

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

covering all liabilities owed for compensation and other benefits under the relevant Workers’ Compensation laws of any state or of the federal government, and Employer’s Liability Insurance for bodily injury by accident with limits of not less than One Million U.S. Dollars (US $1,000,000.00) per each accident, and bodily injury by disease with policy limits of not less than One Million U.S. Dollars (US $1,000,000.00) per each employee; Maritime Employer’s Liability with limits of not less than One Million U.S. Dollars (US $1,000,000.00) per each accident, or such greater amounts, in all cases, as may be required by law, without limitation:

A.Protection for liabilities under the U.S. Longshore and Harbor Worker’s Compensation Act and the Outer Continental Shelf Lands Act;

B.If not included in the Protection and Indemnity Insurance (as described at Appendix E, Part A(4)(B) herein), coverage for liability under the Merchant Marine Act of 1920, commonly known as the Jones Act, the Admiralty Extension Act of 1948, and the Death on the High Sea Act;

C.If not included in the Protection and Indemnity Insurance (as described at Appendix E, Part A(4)(B) herein), protection against liability of the employer to provide transportation, wages, and maintenance and cure to maritime employees and a Voluntary Compensation Endorsement;

D.Coverage amended to provide that a claim In Rem shall be treated as a claim against the employer;

E.Territorial extension to cover all areas where Work is performed and the Area of Operations; and

F.“Alternate Employer or Borrowed Servant” Endorsement stating that a claim brought against Operator as a “Borrowed Servant” by any person who is on the payroll of Contractor or its subcontractors shall be treated as a claim against Contractor or its subcontractor.

4.For all vessels (including the Rig) owned, operated, chartered or brokered by or for Contractor Group in connection with the Work under this Drilling Contract, Contractor shall carry, or require the owner or operator of such vessels to carry, the following:

A.“All Risks” Hull and Machinery Insurance — American Institute Hull Clauses or equivalent covering all vessels (including the Rig) and marine craft (whether navigable or not) and equipment to the agreed value.  Coverage shall include but not be limited to Removal of Wreck/Debris, Collision Liability, with the sistership clause unamended, Tower’s

E-3

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Liability, Sue and Labor, Salvage, War Risks.  Any “as owner of the vessel”, “as owner” clause or any other language purporting to limit coverage to that of the owner shall be deleted.  Any language limiting coverage for any member of Operator Group in the event of the applicability of the Limitation of Liability Statute shall be deleted.  Removal of Wreck/Debris shall have a separate limit of a minimum of twenty-five percent (25%) of the agreed value of the insured vessel (including the Rig) for the removal of debris and/or wreckage where such removal is compulsorily required by legally constituted authority, is required under this Drilling Contract, and/or where any debris and/or wreckage constitutes an impediment or interference to any operations of Operator.  This coverage may be subject to a self-insured retention and/or deductible in a reasonable amount consistent with customary industry practice; provided, however, that Contractor shall provide Operator thirty (30) days’ written notice in the event such self-insured retention and/or deductible shall at any time exceed Fifty Million U.S. Dollars (US $50,000,000.00).

B.Protection and Indemnity Insurance and/or Marine Liability Insurance — Coverage for owned, non-owned or hired waterborne craft/vessels covering Contractor’s liabilities including but not limited to crew, sudden & accidental pollution emanating from the insured vessel, and contractual liability arising from the use and/or operation of the said craft of not less than One Million U.S. Dollars (US $1,000,000.00) combined single limit per occurrence.  All Protection and Indemnity Insurance policies shall be on Form SP23 or equivalent and shall meet the following requirements and have the following endorsements, if applicable: (i) coverage for master and members of crew, including but not limited to admiralty benefits and damages under the Jones Act, Death on the High Seas Act and General Maritime Law, and including wages, transportation, maintenance and cure; (ii) third party bodily injury and property damage; (iii) liability for sudden & accidental pollution emanating or originating from the insured vessel (including the Rig) including containment, cleanup, control, removal, restoration and remediation; (iv) contractual liability coverage to cover the indemnities and liabilities contractually assumed by Contractor under this Drilling Contract; and (v) Cargo Legal Liability.  Any “as owner of the vessel”, “as owner” clause or any other language purporting to limit coverage to that of the owner shall be deleted.

5.Charterers Legal Liability Insurance in respect of non-owned vessels for bodily injury and property damage with limits of not less than One Million U.S. Dollars (US $1,000,000.00) combined single limit per occurrence.

E-4

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

6.Aircraft Liability Insurance covering fixed and rotary winged aircraft (where Contractor has hired aircraft or helicopters) with combined single limit coverage of not less than Five Million U.S. Dollars (US $5,000,000.00) combined single limit per occurrence covering all owned, non-owned and hired aircraft by Contractor in connection with the Work to be performed, covering public liability, passenger liability, bodily injury, death, property damage, and contractual liability to cover the indemnities and liabilities contractually assumed by Contractor under this Drilling Contract.

7.Umbrella/Excess Liability Insurance Coverage providing coverage excess of insurance requirements set forth in Parts A(1), A(2), A(3) (except Workers’ Compensation), A(4)(B), A(5), and A(6) of this Exhibit E, in the amount of at least Six Hundred and Fifty Million U.S. Dollars (US $650,000,000.00) following form of the primary insurance.

8.Property Insurance (Increased Value Insurance) in an all risk form (including transit) covering Contractor’s Items (other than the Rig) and other machinery, plant, facilities and equipment used in performing the Work under this Drilling Contract, including transit thereof, whether owned, hired or leased, for its replacement cost value (as declared).  Such policies must cover loss or damage to equipment below the surface of the water if such loss or damage is caused by any of the perils insured against.  At the option of Contractor, where applicable, this coverage may be included in the Hull Insurance as outlined in Part A(4)(A).  All Risk Insurance as herein required covers transit risk, including storage, loading and unloading.  Contractor shall satisfy Operator that adequate insurance coverage is applicable on the Rig and Contractor’s equipment being moved, or obtain coverage as required so that Operator shall not pay for any Contractor transit risk insurance, for the protection of all parties; or Contractor may, at its option, and at its expense, make arrangements for the transporting company to obtain transit risk, including loading and unloading, with the understanding the proof of such coverage shall be submitted in the manner provided for Contractor’s coverage, and the coverage shall give the same protection as a policy written for Contractor to meet the requirements of this Drilling Contract.

All such policies described above shall include (either by operation of policy terms or, to the extent not so provided, by express endorsement) provisions for waiver of underwriter’s rights of subrogation against Operator Group, but such waiver shall be strictly limited to the extent of the indemnities and liabilities contractually assumed by Contractor under this Drilling Contract.  All such policies described above (other than the Workers’ Compensation Insurance) also to include (either by operation of policy terms or, to the extent not so provided, by express endorsement) the members of Operator Group as additional insureds, and to provide that such insurances shall be primary over any insurances that may be maintained by any member of Operator Group, but any additional insured coverage shall be strictly limited to the extent of the indemnities and

E-5

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

liabilities contractually assumed by Contractor under this Drilling Contract.  The naming of the members of Operator Group as additional insureds is not intended to, and shall not derogate from, the indemnities, obligations, and allocation of risks and liabilities contained in Article VIII, Section 13.4, and Section 17.2 of the Drilling Contract.  Operator agrees that the Operator Group shall not be entitled to assert a claim against Contractor’s insurance coverages required herein with respect to the indemnities and liabilities contractually assumed by Operator under the Drilling Contract.  In addition, said insurances (other than the Workers’ Compensation Insurance) shall be written to provide that claims in rem shall be treated as claims in personam and to provide coverage for any of the insureds in the same manner as would have been provided such insured if separate policies had been issued in the name of each insured thereunder.

Except as specifically stated to the contrary herein, any and all deductibles, self-insured retentions, retrospective premiums and loss-sensitive premiums in the above described insurance policies shall be assumed by, for the account of and at Contractor’s sole risk.

All policies providing coverage hereunder shall contain provisions that no cancellation or material changes in the policies shall become effective except on thirty (30) days’ written notice thereof to Operator (seven (7) days for cancellation due to war risk).

When requested by Operator, Contractor shall furnish, or cause to be furnished, to Operator, in the manner above provided, certificates of insurance evidencing coverage for each subcontractor in minimum amounts deemed necessary by Contractor to cover the Work performed by the particular subcontractor.  Should insurance coverage maintained by a subcontractor be less than the minimum requirements for Contractor, as set out above, Operator may, at its option (1) require Contractor, or require Contractor to cause any subcontractor of Contractor, to secure such minimum coverage, or (2) upon ten (10) days’ prior written notice to Contractor purchase insurance necessary to provide such minimum coverage and charge the premiums therefor (not to exceed $2,500 per day) to Contractor’s account.

In the event that Contractor’s minimum insurance coverages, as required by Part A of Appendix E (except for the insurance coverages described at Part A(4)(B) and Part A(7), which for the purposes of this paragraph only, such minimum amount of the combined coverages shall be Five Hundred Million U.S. Dollars (US $500,000,000.00)), is not provided or should be canceled, or materially modified or changed in breach of the Drilling Contract, Operator may, at its sole discretion, suspend the Work until such minimum insurance coverage is provided or reinstated.  The Zero Rate shall be applicable during any such suspension.  If Contractor fails to provide or maintain the minimum insurance coverages required hereunder, and Operator so notifies Contractor in writing, Contractor shall have ten (10) business days from the date of such notice to provide or maintain the minimum insurance coverage required by Part A of Appendix E.  In the event Contractor fails to provide or maintain such minimum insurance coverage within

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

the said ten (10) business day period, Operator shall have the right (but not the obligation) to terminate this Drilling Contract by the giving of immediate notice.

B.Minimum Insurance Coverage to be maintained by Operator

Prior to the Term Commencement Date and during the term of this Drilling Contract, when reasonably requested by Contractor, Operator shall furnish, or cause to be furnished, to Contractor for viewing at Operator’s offices during normal business hours copies of insurance policies evidencing the insurance coverages required of Operator under Article IX of the Drilling Contract and this Appendix E, placed with insurers with an A.M. Best rating of “A-” or better and who are authorized to do business in the geographical area where the Work is to be performed.  Operator’s insurance policies are confidential information within the meaning of, and subject to, Article XVII of the Drilling Contract.  The types and amounts of insurance (through insurance, including self-insured retentions and/or deductibles in reasonable amounts consistent with customary industry practice) set forth in this Appendix E, Part B are the minimum types and amounts that Operator must obtain and maintain during the term of this Drilling Contract.

If insurance is provided on a “claims made” basis, coverage in each case shall provide for and maintain a retrospective date prior to or concurrent with the commencement of the Work and an automatic extended reporting period of no less than ninety (90) days.  Such “claims-made” coverage shall be maintained continuously, on substantially the same material terms to the extent reasonably commercially available, for a period of at least five (5) years following completion of the Work, through extension or renewal of such coverage or through the purchase, at Operator’s sole expense, of an additional extended reporting period and/or run-off or “tail” coverage acceptable to Contractor.  In the event Operator is notified of any intention of the issuer or underwriter of any such “claims-made” coverage not to renew such coverage during the period required by this Drilling Contract, Operator shall notify Contractor within thirty (30) days.

The types and limits of insurance coverage specified below are minimum requirements and shall not be deemed to constitute, or be construed as, a limitation on Operator’s liabilities under this Drilling Contract or as constituting acceptance by Contractor of any responsibility for financial or other liabilities or indemnities in excess of such limits.

1.Workers’ Compensation and Employer’s Liability Insurance in accordance with all applicable federal, state, and maritime laws (including Death on the High Seas Act, HSL&H and Jones Act) which shall cover all Operator’s personnel, invitees, subcontractors, guests, consultants, etc., performing under this Drilling Contract.  The Employer’s Liability Employer’s Liability Insurance shall include coverage for bodily injury by accident with limits of not less than One Million U.S. Dollars (US $1,000,000.00) per each accident, and bodily injury by disease with policy limits of not less than One Million U.S. Dollars (US $1,000,000.00) per each

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

employee; Maritime Employer’s Liability for bodily injury by accident with limits of not less than One Million U.S. Dollars (US $1,000,000.00) per each accident, or such greater amounts, in all cases, as may be required by law, without limitation.  All such insurance shall include a “Borrowed Servant Endorsement” stating that a claim brought against Contractor, in rem or in personam, will be treated as a claim against Operator.

2.Commercial General Liability with a combined personal injury and property damage limit of not less than One Million U.S. Dollars (US $1,000,000.00) per occurrence and not less than Two Million U.S. Dollars (US $2,000,000.00) in the aggregate including the following supplementary coverage:

A.Contractual Liability to cover the indemnities and liabilities contractually assumed by Operator under this Drilling Contract, cross liability and severability of interest;

B.Completed Operations Hazard Coverage;

C.Broad Form Property Damage Liability insurance;

D.Coverage for explosion, collapse, and underground hazards for Work performed by Contractor involving equipment or materials of a volatile, incendiary or explosive nature or involving excavation activity;

E.Independent Contractor’s Coverage;

F.Personal Injury Liability;

G.Premises Liability;

H.In Rem Endorsement;

I.Territorial extension to cover all areas where Work is performed and the Area of Operations;

J.Seepage and Pollution Liability on a sudden and accidental basis, including, without limitation, cleanup;

K.“Care, custody, and control” exclusion deleted; and

L.Coverage for punitive damages where allowed by applicable law.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

3.“All Risk” Insurance, equal to the replacement value (as declared) but subject to a nominal deductible, covering physical loss or damage (including wreck/debris removal) for all platform(s), pipeline(s) and facilities where Operator or its Affiliates have a working interest at or near the Designated Well site(s) and Operator’s equipment and other property (owned or hired) of Operator and its subcontractors (excluding any Contractor’s Items) including coverage while such property is on board the Rig or loss/damage during use, loading, unloading or while in transit.  The Parties agree that where Operator and its Affiliates insure their interest in such platform(s), pipeline(s) and facilities, Operator may fulfill its obligations under this Appendix E, Part B(3) by causing such Affiliates to provide the coverage required hereunder (including all endorsements) to the extent of each Affiliate’s interest in the platform(s), pipeline(s) and facilities.

4.Operator’s Extra Expense Insurance in the amount of not less than Five Hundred Million U.S. Dollars (US $500,000,000.00) combined single limit (100%) per occurrence to cover any and all sums which Operator may be obligated to incur as expenses and/or liabilities which may be incurred on account of bringing under control an oil or gas well which is out of control or extinguishing an oil or gas well fire, redrilling or repair of loss or damage to an oil or gas well, seepage and pollution, cleanup and contamination.

5.For all vessels chartered by or for Operator in connection with its obligations under Appendix D of this Drilling Contract (excluding the Rig and any vessels owned, operated, chartered, or brokered by Contractor Group), Operator shall carry, or require the owner or operator of such vessels to carry, the following:

A.“All Risks” Hull and Machinery Insurance — American Institute Hull Clauses or equivalent covering all vessels and marine craft (whether navigable or not) and equipment, including Collision Liability, with the sistership clause unamended, with limits of liability at least equal to the agreed value thereof providing coverage against losses or damage by such perils and risks including but not limited to war risks, tower’s liability.  In addition, the policy shall include provisions to provide full coverage to Contractor as additional insured (but only to the extent of the liability assumed by the Operator hereunder) without limiting coverage to liability “as owner of the vessel” and to delete any “as owner” clause or any other language purporting to limit coverage to liability of an insured “as owner of the vessel”, and (b) to delete any language limiting coverage for Contractor in the event of the applicability of the Limitation of Liability Statute.

There shall be included under the Hull and Machinery Insurance a separate limit of a minimum of twenty-five percent (25%) of the agreed value for the removal of debris and/or wreckage where such removal is compulsorily required by legally constituted authority, is required

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

contractually (including by this Drilling Contract), and/or where any debris and/or wreckage constitutes an impediment or interference to any operations of Operator.

B.Protection and Indemnity Insurance and/or Marine Liability Insurance — Coverage for owned, non-owned or hired waterborne craft/vessels covering the insured vessel owner’s liabilities including but not limited to crew, sudden & accidental pollution emanating from the insured vessel, and contractual liability arising from the use and/or operation of the said craft of not less than One Hundred Million U.S. Dollars (US $100,000,000.00) combined single limit per occurrence or the agreed value of each vessel whichever is greater.  All Protection and Indemnity Insurance policies shall be on Form SP23 or equivalent and shall meet the following requirements and have the following endorsements, if applicable: (i) coverage for master and members of crew, including but not limited to admiralty benefits and damages under the Jones Act, Death on the High Seas Act and General Maritime Law, and including wages, transportation, maintenance and cure; (ii) third party bodily injury and property damage; (iii) liability for sudden & accidental pollution emanating from the insured vessel including containment and cleanup; (iv) contractual liability coverage; and (v) Sue and Labor and Salvage Charge, and (vi) Cargo Legal Liability.  Any language in this policy which limits the coverage to an insured who is not the insured vessel owner or who is not entitled to limitation of liability shall be deleted.

6.Charterers Legal Liability Insurance in respect of non-owned vessels for bodily injury and property damage with limits of not less than One Million U.S. Dollars (US $1,000,000.00) combined single limit per occurrence.

7.Aircraft Liability Insurance covering fixed and rotary winged aircraft provided by Operator with a combined single limit coverage of not less than Five Million U.S. Dollars (US $5,000,000.00) per occurrence covering all owned, non-owned and hired aircraft by Operator in connection with the Work to be performed, covering public liability, passenger liability, bodily injury, death, property damage, and contractual liability to cover the indemnities and liabilities contractually assumed by Operator under this Drilling Contract.

8.Automobile Liability Insurance covering owned, hired and non-owned vehicles or automotive equipment used by Operator with limits of One Million U.S. Dollars (US $1,000,000.00) combined single limit per occurrence for bodily injury and property damages.

9.Umbrella/Excess Liability Insurance Coverage providing coverage excess of insurance requirements set forth in Parts B(1) (except Workers’ Compensation),

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

B(2), B(4), B(6), B(7), and B(8) of this Exhibit E, in the amount of at least Two Hundred and Fifty Million U.S. Dollars (US $250,000,000.00).

All such policies described above shall include (either by operation of policy terms or, to the extent not so provided, by express endorsement) provisions for waiver of underwriter’s rights of subrogation against Contractor Group, but such waiver shall be strictly limited to the extent of the indemnities and liabilities contractually assumed by Operator under this Drilling Contract.  All such policies described above (other than the Workers’ Compensation Insurance) also to include (either by operation of policy terms or, to the extent not so provided, by express endorsement) the members of Contractor Group as additional insureds, and to provide that such insurances shall be primary over any insurances that may be maintained by any member of Contractor Group, but any additional insured coverage shall be strictly limited to the extent of the indemnities and liabilities contractually assumed by Operator under this Drilling Contract.  The naming of the members of Contractor Group as additional insureds is not intended to, and shall not derogate from, the indemnities, obligations, and allocation of risks and liabilities contained in Article VIII, Section 13.4, and Section 17.2 of the Drilling Contract.  Contractor agrees that the Contractor Group shall not be entitled to assert a claim against Operator’s insurance coverages required herein with respect to the indemnities and liabilities contractually assumed by Contractor under the Drilling Contract.  In addition, said insurances (other than the Workers’ Compensation Insurance) shall be written to provide that claims in rem shall be treated as claims in personam and to provide coverage for any of the insureds in the same manner as would have been provided such insured if separate policies had been issued in the name of each insured thereunder.

All such insurance shall be endorsed to provide not less than thirty (30) days’ prior written notice to Contractor in the event of cancellation or any material changes in the policies which affect the interests of Contractor, and the policies shall be endorsed in a manner which stipulates that Contractor shall not be liable for any premiums or deductibles.

The above specified amounts and types of insurance coverage shall not be deemed to constitute, or be construed as, a limitation on Operator’s liability under this Drilling Contract.

In the event that Operator’s minimum insurance coverages, as required by Part B of Appendix E (except for the insurance coverages described at Part B(4) and Part B(9), which for the purposes of this paragraph only, such minimum amount of the combined coverages shall be [***], is not provided or should be canceled, or materially modified or changed, Contractor may, at its sole discretion, suspend operations until such minimum insurance coverage is provided or reinstated.  The Standby Rate shall be applicable during any such suspension.  If Operator fails to provide or maintain the minimum insurance coverage required hereunder, and Contractor so notifies Operator in writing, Operator shall have ten (10) business days from the date of such notice to provide or

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

maintain the minimum insurance coverage required by Part B of Appendix E.  In the event Operator fails to provide or maintain such minimum insurance coverage within the said ten (10) business day period, Contractor shall have the right (but not the obligation) to terminate this Drilling Contract by the giving of immediate notice.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDIX F

INTENTIONALLY OMITTED

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APPENDIX G

DEED OF NOVATION

THIS DEED OF PARTIAL NOVATION (this “Deed”) is made the          day of August, 2013

BETWEEN:

(1)COBALT INTERNATIONAL ENERGY, L.P., a limited partnership organised and existing under the laws of the State of Delaware having its principal place of business at Cobalt Center, 920 Memorial City Way, Suite 100, Houston, Texas 77024 (“Operator”);

(2)ROWAN RELIANCE LIMITED, a company organised and existing under the laws of Gibraltar having its registered office at Suite 1, Burns House, 19 Town Range, Gibraltar (the “Transferor”); and

(3)ROWAN (UK) RELIANCE LIMITED, a company organised and existing under the laws of England and Wales (company number 8592391) having its registered office at Mitre House, 160 Aldersgate Street, London EC1A 4DD (the “Transferee”),

(together referred to as the “Parties”).

WHEREAS:

(A)Pursuant to an offshore drilling contract dated August 5, 2013 made between the Operator and the Transferor (the “Drilling Contract”), the Transferor has agreed to provide offshore drilling services to the Operator upon the terms therein set out.

(B)Pursuant to a deed of guarantee dated August 5, 2013 (the “Deed of Guarantee”) made between the Operator and Rowan Companies plc, a company incorporated under the laws of England (the “Guarantor”), the Guarantor has agreed to guarantee unconditionally and irrevocably to the Operator (1) the due and punctual payment of all amounts which the Transferor and the Transferee are or shall become obliged to pay to the Operator in respect of the Guaranteed Obligations (as defined in the Deed of Guarantee), and (2) the full and complete performance by the Transferor and the Transferee of all other terms, covenants, agreements and obligations made or undertaken by or imposed upon the Transferor and the Transferee in respect of the Guaranteed Obligations (as defined in the Deed of Guarantee) and under the Drilling Contract in connection with the transactions contemplated thereby.

(C)The Operator has agreed that the Transferee will be substituted in place of the Transferor under the Drilling Contract upon the terms and subject to the conditions set forth hereinafter.

NOW THEREFORE THIS DEED WITNESSETH as follows:

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

1.Words and expressions used but not defined herein shall have the same meaning as in the Drilling Contract.

2.In this Deed the expression “Novation Date” means the date upon which the Rig arrives in the Area of Operations.  The Transferor shall promptly provide written notice to the Operator of the exact date, time, and location that the Rig has arrived in the Area of Operations.

3.Subject to Clauses 4.1, 4.2 and 4.4 below, the parties hereto agree that with effect on and from the Novation Date and with respect to the period from the Novation Date:

3.1.the Transferor shall cease to be a party to the Drilling Contract (and shall cease to be Contractor as such term is defined in the Drilling Contract (except as set forth in Clauses 4.1, 4.2 and 4.4 below)), and the Transferee shall become a party to the Drilling Contract (and shall become Contractor as such term is defined in the Drilling Contract) and shall assume the liabilities, perform the obligations and be entitled to the rights and benefits therein in the place of the Transferor;

3.2.the Operator hereby releases and discharges, and agrees to release and discharge, the Transferor from the various covenants, undertakings, warranties and other obligations contained in the Drilling Contract which are hereby assumed by the Transferee, and shall accept the like performance and discharge of those covenants, undertakings, warranties and other obligations of the Transferee in the place thereof;

3.3.the Transferee undertakes and covenants to the Operator to assume, observe, perform, discharge and be bound by all liabilities, obligations and duties arising under the Drilling Contact in the place of the Transferor and to be bound by and discharge all the obligations of the Transferor under the Drilling Contract and to be bound by all the terms and conditions of the Drilling Contract in every way as if the Transferee was named in the Drilling Contract in place of the Transferor;

3.4.the Transferor hereby releases and discharges, and agrees to release and discharge, the Operator from the various covenants, undertakings, warranties and other obligations contained in the Drilling Contract which are enjoyed by the Transferor and from all claims and demands whatsoever arising out of or in respect of the Drilling Contract;

3.5.the Operator undertakes and covenants to the Transferee to observe, perform, discharge and be bound by all liabilities, obligations and duties arising under the Drilling Contact and to be bound by and discharge its obligations under it and to be bound by all the terms and conditions of the Drilling Contract in every way as if the Transferee was named in the Drilling Contract in place of the Transferor; and

3.6.Nothing in this Deed shall affect or prejudice any claim or demand that the Operator

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

may have under or in connection with the Drilling Contract arising before the Novation Date.

4.Notwithstanding Clause 3 above:

4.1.The Transferor shall remain a party to the Drilling Contract for the purpose of Section 3.2 thereof and references to “Contractor” in Section 3.2 of the Drilling Contract shall be references to the Transferor (or such other Affiliate of the Transferor as the Transferor and the Operator shall agree).

4.2.The rights conferred by Section 3.2 of the Drilling Contract upon “Contractor” to agree any new Area of Operations and to determine with Operator any changes needed in accordance with that Section shall remain with the Transferor throughout the term of the Drilling Contract notwithstanding this Deed.

4.3.The Transferee hereby agrees that it may not exercise any right of assignment under Section 16.1 of the Drilling Contract, which right is specifically reserved to Transferor (with the Operator’s prior approval as set out in that Section) notwithstanding this Deed.  Nothing in this Clause 4.3 is intended by the parties hereto to amend or otherwise the limit the rights of the Operator set out in the Drilling Contract.

4.4.The parties hereto agree that the Mobilisation Fee to be invoiced on or after the Term Commencement Date in accordance with the provisions of Section 2.7(a) of the Drilling Contact will be invoiced by and payable to the Transferor to the extent earned prior to the Novation Date and invoiced by and payable to the Transferee to the extent earned after the Novation Date.  In no event shall the total amounts invoiced exceed the Mobilisation Fee and the thirty (30) day period for the payment of such invoices under Section 4.2 of the Drilling Contract shall commence only when the Operator has received two invoices totalling no more than the Mobilisation Fee.  The payment of the Mobilisation Fee by the Operator to the Transferor and the Transferee in accordance with the invoices rendered by them shall constitute full and final settlement in respect of such liability under the Drilling Contract.

5.In the event that the Rig commences mobilisation to an area outside the U.S. Gulf of Mexico outer-continental shelf lease blocks prior to the termination of the Drilling Contract, the Transferor will resume its role as Contractor under the Drilling Contract such that upon the receipt by the Operator of a written notice from the Transferor confirming the date of such commencement (the “Reversion Date”), automatically with effect from the Reversion Date and in respect of the period on and from the Reversion Date:

5.1.the Transferee shall cease to be a party to the Drilling Contract and the Transferor shall again become a party to the Drilling Contract and shall assume the liabilities,

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perform the obligations and be entitled to the rights and benefits therein in the place of the Transferee;

5.2.the Operator hereby releases and discharges and agrees to release and discharge the Transferee from the various covenants, undertakings, warranties and other obligations contained in the Drilling Contract which are assumed by the Transferor, and shall accept the like performance and discharge of those covenants, undertakings, warranties and other obligations of the Transferor in the place thereof;

5.3.the Transferor undertakes and covenants to the Operator to assume, observe, perform, discharge and be bound by all liabilities, obligations and duties arising under the Drilling Contact in the place of the Transferee and to be bound by and discharge all the obligations of the Transferee under it and to be bound by all the terms and conditions of the Drilling Contract in every way; and

5.4.the Transferee hereby releases and discharges and agrees to release and discharge the Operator from the various covenants, undertakings, warranties and other obligations contained in the Drilling Contract which are enjoyed by the Transferee and from all claims and demands whatsoever arising out of or in respect of the Drilling Contract.

6.Notices to the Transferee shall, for the purposes of the Drilling Contract, be sent to the Transferee at:

ROWAN (UK) RELIANCE LIMITED

Mitre House

160 Aldersgate Street

London

EC1A 4DD

United Kingdom

Attn:  George Yuill

Facsimile:  44 208 4290982

7.Except as otherwise provided in this Deed, all terms and conditions contained in the Drilling Contract shall remain in full force and effect.

8.This Deed (and all non-contractual obligations which may arise out of or in connection with it) shall be governed by and construed in accordance with the laws of England, not including any of its conflicts of law rules that would direct or refer to the laws of another jurisdiction.  Any dispute arising, between or among any of the Parties, out of or in connection with this Deed or the Drilling Contract shall be resolved in accordance with Section 11.2 of the Drilling Contract; provided that if all the Parties are parties to the arbitration, the Transferor and the Transferee shall jointly nominate one arbitrator, the Operator shall nominate another arbitrator and the third arbitrator shall be nominated by the two Party-nominated arbitrators.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

9.The Parties agree that this Deed may be executed in counterparts, including fax counterparts, and together with all counterpart executions shall be considered an original for all purposes hereunder.

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CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

IN WITNESS WHEREOF this Deed was duly executed and unconditionally delivered on the date first above written.

Signed as a deed on behalf of COBALT
INTERNATIONAL ENERGY, L.P., a	Van P. Whitfield
Delaware limited partnership, by Van P.	Authorised Signatory
Whitfield, being a person who, in accordance
with the laws of that territory, is acting under
the authority of the limited partnership
	Witness
Signed as a deed on behalf of ROWAN
RELIANCE LIMITED, a company	Louis B. Triay
incorporated in Gibraltar, by Louis B. Triay	Authorised Signatory
(acting in his capacity as a Director of Trilex
Limited, itself a Director of the company) and
Melanie M. Trent, being persons who, in
accordance with the laws of that territory, are	Witness
acting under the authority of the company
	Melanie Trent
	Authorised Signatory
	Witness
Signed as a deed on behalf of ROWAN (UK)
RELIANCE LIMITED, a company	Gregory M. Hatfield
incorporated in England and Wales, by	Authorised Signatory
Gregory M. Hatfield, being a person who, in
accordance with the laws of that territory, is
acting under the authority of the company
	Witness

G-6

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

G-7

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDIX H

DEED OF GUARANTEE

This Deed of Guarantee (this “Guarantee”) dated August 5, 2013

BETWEEN

(1)Cobalt International Energy, L.P., a Delaware limited partnership (herein called “Operator”); and

(2)Rowan Companies plc, a company incorporated under the laws of England and having its registered office at Mitre House, 160 Aldersgate Street, London EC1A 4DD (herein called the “Guarantor”).

Operator and the Guarantor are each herein referred to as a “Party” and collectively referred to as the “Parties”.

WHEREAS

(A)The Guarantor is the parent company of Rowan Reliance Limited (herein called the “Transferor”) which has entered into an agreement dated August 5, 2013 to provide offshore drilling operations by the Rig ROWAN RELIANCE (including any amendment or supplement to, or restatement of, such agreement) (the “Drilling Contract”).

(B)No later than seven (7) days after the date hereof, the Transferor, Rowan (UK) Reliance Limited, a company incorporated under the laws of England (registration number 8592391) (herein called the “Transferee,” and together with the Transferor, “Contractor”), and Operator shall execute and deliver a deed of partial novation, to be effective as of the date of the Rig’s arrival in the Area of Operations (the “Novation”), assigning and transferring the specified Transferor’s rights, obligations and liabilities under the Drilling Contract in respect of the Work to be performed in the Area of Operations to the Transferee.  Upon any commencement of mobilisation to an area outside the Area of Operations during the term of the Drilling Contract, the specified rights, obligations and liabilities under the Drilling Contract will revert to the Transferor in the manner set out in the Novation.

(C)The Guarantor has agreed to enter into this Guarantee with Operator to guarantee the performance of all present and future obligations and liabilities of Contractor due, owing or incurred under the Drilling Contract or any document referred to in it (including under any amendment, supplement or restatement thereof) (the “Guaranteed Obligations”).

I-1

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(D)Terms not defined otherwise herein shall have the meaning given in the Drilling Contract.

THEREFORE

1.In consideration of Operator entering into the Drilling Contract with Contractor, the Guarantor (as a primary obligor and not merely as a surety) hereby guarantees unconditionally and irrevocably to Operator:

(a)the due and punctual payment by Contractor of all amounts which Contractor is or shall become obliged to pay to Operator in respect of the Guaranteed Obligations; and

(b)the full and complete performance by Contractor of all other terms, covenants, agreements and obligations made or undertaken by or imposed upon Contractor in respect of the Guaranteed Obligations and under the Drilling Contract.

2.The Guarantor’s liabilities under this Guarantee shall in no event or circumstance be greater than those of Contractor under the Drilling Contact.

3.This Guarantee shall be a primary obligation of the Guarantor and accordingly Operator shall not be obligated before enforcing any of its rights and remedies under this Guarantee to take any action or obtain any judgment in any court against Contractor or any other Person, to make or file any claim against or any demand of Contractor, to make, demand, enforce or seek to enforce any claim, right or remedy against Contractor or any other Person, nor to enforce any other security held by it in respect of the obligations of Contractor under the Drilling Contract.

4.This Guarantee shall be a continuing guarantee which shall be and continue in full force and effect notwithstanding the dissolution of Contractor, the execution and delivery of the Novation or any changes in the status, identity, function, control or ownership of Contractor until all Contractor’s obligations under the Drilling Contract have been performed.

5.The Guarantor hereby represents and warrants that:

(a)it is a company duly incorporated under the laws of the place of its incorporation and has power to enter into and perform its obligations under this Guarantee and has all necessary authority to enter into this Guarantee and guarantee the Guaranteed Obligations;

(b)the obligations of the Guarantor hereunder constitute legal, valid and binding obligations on the Guarantor;

(c)its entry into this Guarantee (A) will not contravene any applicable law, regulation, judgment, order or decree of any court or body having jurisdiction over the Guarantor; (B) will not conflict with, or result in any breach of any of the terms of, or constitute a default under, any agreement or other instrument to which the Guarantor is a party and the Guarantor is subject, or by which the

I-2

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

Guarantor, or any of its property, is bound; and (C) will not contravene or conflict with any provision of the Guarantor’s memorandum and articles of association, constitution or by-laws;

(d)the Guarantor’s obligations under this Guarantee rank at least pari passu with the claims of all its other unsecured and unsubordinated creditors, except for obligations mandatorily preferred by law applying to companies generally; and

(e)no event or circumstance is outstanding which constitutes a default under any deed, agreement, document or instrument which is binding on the Guarantor, or to which its assets are subject, which might have a material adverse effect on the Guarantor’s ability to perform its obligations under this Guarantee.

6.The Guarantor as principal obligor and as a separate and independent obligation and liability from its obligations and liabilities in Section 1 above agrees to indemnify and keep indemnified Operator in full and on demand from and against all losses, claims, costs, charges, damages, demands and expenses incurred or sustained by Operator arising out of or in connection with any failure by Contractor to perform or discharge any of its obligations or liabilities under the Drilling Contract.

7.The liability of the Guarantor under this Guarantee shall not be reduced, discharged or otherwise adversely affected by:

(a)any termination, amendment, variation, novation, replacement or supplement of or to any of the Guaranteed Obligations;

(b)any grant of time, indulgence, waiver or concession to Contractor or any other Person;

(c)any insolvency, bankruptcy, liquidation, administration, winding up, incapacity, limitation, disability, the discharge by operation of law, or any change in the constitution, name or style of Contractor or any other Person;

(d)any invalidity, illegality, unenforceability, irregularity or frustration of any actual or purported obligation of Contractor or any other Person in connection with the Guaranteed Obligations; or

(e)anything done or omitted by any Person which, but for this provision, might operate to exonerate or discharge the Guarantor or otherwise reduce or extinguish its liability under this Guarantee.

8.This Guarantee and any non-contractual obligations arising out of or in connection with it shall be governed by and construed in accordance with the laws of the England and Wales.

9.Any dispute between the Parties in connection with or arising out of this Guarantee shall be finally resolved in accordance with the provisions of Article XI of the Drilling Contract.

I-3

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

10.This Guarantee is effective on and from the Effective Date of the Drilling Contract as defined in the Drilling Contract irrespective of the date or dates on which it has been executed.

11.This Guarantee shall remain in effect for the duration of Contractor’s obligations under the Drilling Contract, including any such obligations which survive the termination of the Drilling Contract.

12.No amendment, modification, variation or waiver of this Guarantee shall be effective unless in writing and signed by the Guarantor and Operator.

13.Article XV (Notices) of the Drilling Contract shall apply mutatis mutandis to this Guarantee.

14.This Guarantee may be executed in any number of counterparts, each of which when executed and delivered is an original, but all the counterparts together constitute the same document.

[Signature page follows.]

I-4

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

This document has been executed as a deed and is delivered and takes effect on the date stated at the beginning of it.

Executed as a deed
by ROWAN COMPANIES PLC	)
acting by Lord Colin Moynihan, a director,	)
in the presence of:	)		Director
Executed as a deed
by COBALT INTERNATIONAL ENERGY, L.P.		)
acting by Van P. Whitfield, Chief Operating Officer,		)
in the presence of:	)		Chief Operating Officer

I-5

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

APPENDIX I

REMUNERATION

Operator shall compensate Contractor in accordance with the lump sum amounts and/or at the rates specified herein.

A.SUMMARY OF FEES AND RATES

1.Lump Sum Fees		US$
A.Mobilization Fee		$22,500,000
B.Demobilization Fee		$0.00 (Zero)
2.Day Rates		US$/DAY
A.Operating Rate		$579,900.00
B.Standby Rate		98% of Operating Rate
C.Repair Rate		Zero Rate applicable after expiry of accumulated allowance at Standby Rate
D.Zero Rate		$0.00 (Zero)
E.Force Majeure Rate		98% of Operating Rate
F.Weather Rate		95% of Operating Rate
G.Other Reduced Day Rates		as set forth in Appendix I, Section B(2)(G)
3.Handling Fee	10% of Contractor’s actual and documented costs.

B.RATES OF PAYMENT TO CONTRACTOR

Section A of this Appendix I provides a summary of day rates applicable to this Drilling Contract which shall be used as the basis for Contractor’s invoices to Operator.  Operator shall pay to Contractor for the Work performed and materials, equipment and supplies furnished by Contractor in accordance with the rates in Appendix I, Section A above, which rates (except the Zero Rate) shall be adjusted pursuant to the provisions of Section 3.3.

I-6

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

1.Lump Sum Compensation

Mobilization

Any Mobilization Fee (in the amount provided above) shall be due and payable by Operator to Contractor in accordance with the terms and conditions of Section 2.7(a).

2.Day Rate Compensation

Accurate time records shall be maintained on the daily operation report to allow determination of time spent on any of the day rate services as specified herein.

A.Operating Rate (Appendix I, Section A(2)(A))

The Operating Rate shall be the default rate paid to Contractor by Operator during the time that Work is being performed.  Subject to the applicability of the other rates set forth in this Appendix I, the Operating Rate shall commence on the Term Commencement Date and shall end upon completion of Operator’s last Designated Well (drilled to its planned total depth, unless otherwise modified by Operator in its sole discretion) commenced during the Primary Term, or an Extension Term, as applicable, when all of Operator’s Items are off-loaded and the Rig is moved pursuant to Section 2.7(b).

B.Standby Rate (Appendix I, Section A(2)(B))

The Standby Rate shall be the compensation paid to Contractor by Operator:

(i)during any period of delay when Contractor is unable to proceed because of loop, eddy or other adverse currents (including periods required to repair damage caused by such seas, conditions and currents), or as a direct result of an act, instruction or omission of Operator including the failure of any of Operator’s Items, or the failure of Operator to issue instructions, provide Operator’s Items or furnish services;

(ii)during any period after the Term Commencement Date that the Rig is underway or maneuvering between drilling locations or sailing to the Demobilization Point after the last Designated Well;

(iii)[***]

I-7

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(iv)during any period of delay in the Work due to inspection and testing of a BOP requested by Operator under Section 5.1(e) of this Drilling Contract;

(v)during any period when Contractor suspends operations pursuant to Appendix E, Part B of this Drilling Contract; and

(vi)as may otherwise be specified in this Drilling Contract.

C.Repair Rate  (Appendix I, Section A(2)(C))

Except as otherwise provided in this Drilling Contract, the Repair Rate shall be the compensation paid to Contractor during any period (or periods) of suspension of the Work resulting from the failure, breakdown or malfunction of the Rig or, subject to Appendix I, Sections B(2)(B), B(2)(D), B(2)(E), B(2)(F) and B(3)(B), when the Rig is otherwise unable to perform the Work; provided that (i) if such suspension of the Work results from the failure, breakdown or malfunction of surface equipment, the Standby Rate shall apply to the first twenty-four (24) hours of suspension per month and (ii) if such suspension of the Work results from the failure, breakdown or malfunction of subsea equipment, the Standby Rate shall apply for the first forty-eight (48) hours of such suspension or the hours accumulated below, whichever is greater; provided further that Contractor shall be allowed to accumulate any unused allowance for subsea equipment from month to month, up to a maximum of [***] hours.  The Zero Rate shall then apply after the expiry of any repair allowance provided herein.  Suspensions of the Work for routine maintenance and inspections, such as lubrication, packing of swivels, slipping and cutting lines, servicing the top-drive, pipe-handling systems, and the hoisting/lifting equipment, subsea testing BOP equipment, drill string inspections, changing mud pump consumables, and any certification inspections, shall not be considered repair time for purposes of this provision.

D.Zero Rate (Appendix I, Section A(2)(D))

The Zero Rate shall be the compensation paid to Contractor by Operator,

(i)as may be specified in Sections 2.2(c), 2.2(d), 8.4(b)(i), 8.4(b)(ii), 8.4(d)(i), 8.4(d)(ii) and 14.1, Appendix E, Part A and Appendix I, Sections B(2)(C) and B(3)(C);

(ii)for each day or part thereof, during which the Work is not being performed due to the fault of or breach of this Drilling Contract by Contractor and no other day rate specified in any of Appendix I, Sections B(2)(B), B(2)(C), B(2)(E), B(2)(F), B(2)(G) and B(3)(B) applies;

I-8

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

(iii)during any period when Operator suspends the Work pursuant to Appendix E, Part A of this Drilling Contract; and

(iv)as may otherwise be specified in this Drilling Contract.

E.Force Majeure Rate (Appendix I, Section A(2)(E))

The Force Majeure Rate shall be applicable as set forth in Section 12.1(c).

F.Weather Rate (Appendix I, Section A(2)(F))

Notwithstanding the application of the Force Majeure Rate, when the Work cannot be carried out due to severe weather, including named tropical storms or hurricanes, the Weather Rate shall apply.

G.Other Reduced Day Rates (Sections 5.2(f), 8.6 and 8.12 of this Drilling Contract)

Other reduced day rates shall be applicable as set forth in Sections 5.2(f), 8.6 and 8.12 of this Drilling Contract.

3.BOP Unavailability

Performance of the Work hereunder and the day rates and compensation payable to Contractor as specified herein this Appendix I is based upon the Rig being equipped at all times with two (2) fully operational and Compliant BOPs.  The following provisions shall apply when the Rig is not so equipped:

A.Within the first 180 Days of Deployment

Except for any loss or destruction of, or damage to, a BOP which is governed by Section 8.4(b)(ii) or Section 8.4(d), if a BOP is unavailable for performance of the Work due to certification, inspection (excepting any inspection requested by Operator pursuant to Section 5.1(e) of this Drilling Contract, which shall be done at the Standby Rate pursuant to Appendix I, Section B(2)(B)(iv), and any subsea testing of BOP equipment, which shall be governed by Appendix I, Section B(2)(C)), repair, maintenance, breakdown, failure, malfunction, or otherwise is not in a fully operational and Compliant condition (each such occurrence, “BOP Unavailability”), and such BOP has been deployed below the water line for one hundred and eighty (180) consecutive days or less, then Contractor shall be entitled to any repair allowances provided in Appendix I, Section B(2)(C) for the period from the time at which the Work is stopped hereunder in preparation to pull and retrieve the BOP, including the time needed to secure any Designated Well in progress, until the time that the second BOP is deployed and the point where such Work or drilling was stopped is reached again and operations

I-9

CONFIDENTIAL TREATMENT REQUESTED. INFORMATION FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED IS OMITTED AND MARKED WITH “[***]”. AN UNREDACTED VERSION OF THE DOCUMENT HAS ALSO BEEN FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION AS REQUIRED BY RULE 24B-2 UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED.

resumed, and the Work shall resume at the Operating Rate up to a maximum of thirty (30) days of BOP Unavailability, after which the Standby Rate shall apply until the first BOP is restored to a fully operational and Compliant condition.

B.After 180 Days of Deployment

Except for any loss or destruction of, or damage to, a BOP which is governed by Section 8.4(b)(ii) or Section 8.4(d), if a BOP is subject to BOP Unavailability, and such BOP has been deployed below the water line for more than one hundred and eighty (180) consecutive days, then Contractor shall be entitled to a day rate of ninety percent (90%) of the Standby Rate for the period from the time at which the Work is stopped hereunder in preparation to pull and retrieve the BOP, including the time needed to secure any Designated Well in progress, until the time that the second BOP is deployed and the point where such Work or drilling was stopped is reached again and operations resumed, and the Work shall resume at the Operating Rate up to a maximum of thirty (30) days of BOP Unavailability, after which the Standby Rate shall apply until the first BOP is restored to a fully operational and Compliant condition.

C.Both BOPs Unavailable

In the event that both of the BOPs are subject to BOP Unavailability, then Contractor shall not be entitled to any repair allowances provided in Appendix I, Section B(2)(C) to remedy such BOP Unavailability, and the Zero Rate shall apply until at least one (1) BOP is restored to a fully operational and Compliant condition, deployed, and the point where the Work or drilling was stopped is reached again and operations resumed, and the Work shall resume at the Standby Rate until the second BOP is restored to a fully operational and Compliant condition.

4.Cost of Rig Modifications

The Parties have agreed to outfit the Rig with drill pipe specified by Operator, at a total cost of One Million Seven Hundred and Ninety-Six Thousand Seven Hundred and Twenty-Seven U.S. Dollars and Forty-Five Cents (US $1,796,727.45) (the “Rig Modification Cost”), with such Rig Modification Cost to be amortized over the Primary Term of this Drilling Contract in the amount of One Thousand Eight Hundred and Forty-Six U.S. Dollars (US $1,846.00) and payable every day of the Primary Term.  In the event of termination of this Drilling Contract for any reason whatsoever prior to the expiration of the Primary Term, Contractor shall be entitled to payment, on a lump-sum basis, of the Rig Modification Cost less any payments made in accordance with this Appendix I, Section B(4), regardless of fault.

I-10

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Joseph H. Bryant, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Cobalt International Energy, Inc.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c.

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: October 29, 2013 /s/ JOSEPH H. BRYANT
Joseph H. Bryant
Chairman of the Board of Directors and
Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, John P. Wilkirson, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Cobalt International Energy, Inc.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c.

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: October 29, 2013 /s/ JOHN P. WILKIRSON
John P. Wilkirson
Chief Financial Officer and
Executive Vice President

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the Quarterly Report on Form 10-Q of Cobalt International Energy, Inc. (the "Company") for the quarterly period ended September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Joseph H. Bryant, as Chief Executive Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

        (1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

        (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

By:	/s/ Joseph H. Bryant
	Name:	Joseph H. Bryant
	Title:	Chairman of the Board of Directors and Chief Executive Officer

Date: October 29, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the Quarterly Report on Form 10-Q of Cobalt International Energy, Inc. (the "Company") for the quarterly period ended September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), John P. Wilkirson, as Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

        (1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

        (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

By:	/s/ John P. Wilkirson
	Name:	John P. Wilkirson
	Title:	Chief Financial Officer and Executive Vice President

Date: October 29, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Seismic and Exploration Expenses

9 Months Ended

Sep. 30, 2013

Seismic and Exploration Expenses

Seismic and Exploration Expenses

10. Seismic and Exploration Expenses

        Seismic and exploration expenses consisted of the following:

									For the Period November 10, 2005 (Inception) through September 30, 2013
	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in Thousands)
Seismic costs	$	13,461	$	4,592	$	34,548	$	29,933	$	376,596
Seismic cost recovery(1)		—		—		—		—		(25,126	)
Leasehold delay rentals		944		1,184		4,050		4,062		36,953
Force Majeure expense(2)		—		—		—		—		13,549
Drilling rig and other exploration expenses		150		551		2,832		1,687		29,631
	$	14,555	$	6,327	$	41,430	$	35,682	$	431,603

(1)

This amount represents reimbursement from partners of past seismic costs incurred by the Company.

(2)

This amount represents expenditures resulting from suspension of drilling activities in the U.S. Gulf of Mexico as a result of the explosion and sinking of the Deepwater Horizon drilling rig in the U.S. Gulf of Mexico, the resulting oil spill and the regulatory response thereto and other exploratory expenses.

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Condensed Consolidated Statements of Operations (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended		95 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013
Condensed Consolidated Statements of Operations
Oil and gas revenue			$ 0
Operating costs and expenses:
Seismic and exploration	14,555	6,327	41,430	35,682	431,603
Dry hole expense and impairment	108,321	15,041	212,199	131,720	450,931
General and administrative	22,347	18,916	68,507	52,239	374,448
Depreciation and amortization	440	269	1,345	782	6,097
Total operating costs and expenses	145,663	40,553	323,481	220,423	1,263,079
Operating income (loss)	(145,663)	(40,553)	(323,481)	(220,423)	(1,263,079)
Other income (expense):
Gain on sale of assets			2,993		2,993
Interest income	1,465	1,339	4,610	3,955	19,653
Interest expense	(15,802)		(51,027)		(54,307)
Total other income (expense)	(14,337)	1,339	(43,424)	3,955	(31,661)
Net income (loss) before income tax	(160,000)	(39,214)	(366,905)	(216,468)	(1,294,740)
Income tax expense			0
Net income (loss)	$ (160,000)	$ (39,214)	$ (366,905)	$ (216,468)	$ (1,294,740)
Basic and diluted income (loss) per share (in dollars per share)	$ (0.39)	$ (0.10)	$ (0.90)	$ (0.54)
Basic and diluted weighted average common shares outstanding (in shares)	406,941,392	406,543,628	406,803,860	402,272,534

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Restricted Funds

9 Months Ended

Sep. 30, 2013

Restricted Funds

Restricted Funds

3. Restricted Funds

        Restricted funds consisted of the following:

	September 30, 2013		December 31, 2012
	($ in thousands)
Short-term:
Ensco 8503 escrow account	$	90,315	$	90,440
Collateral on letters of credit for Angola		138,218		—
	$	228,533	$	90,440
Long-term:
Ensco 8503 escrow account		—		90,440
Collateral on letters of credit for Angola		166,529		304,492
Other vendor restricted deposits		172		720
	$	166,701	$	395,652

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Joint Interest and Other Receivables (Tables)

9 Months Ended

Sep. 30, 2013

Joint Interest and Other Receivables

Schedule of joint interest and other receivables

	September 30, 2013		December 31, 2012
	($ in thousands)
Partners in the U.S. Gulf of Mexico	$	45,663	$	52,439
Partners in West Africa(1)		53,223		2,185
Accrued interest on investment securities		8,313		3,647
Vendors' receivables		1,582		1,526
Other		1,072		1,795
Total	$	109,853	$	61,592

(1)

The amount of $53.2 million as of September 30, 2013 includes $30.6 million related to our partners on Block 20 offshore Angola and $22.6 million related to our partners on Blocks 9 and 21 offshore Angola. Although we expect to collect these receivables in full, including $11.3 million that is currently past due, the allocation of the receivable amongst our partners on Blocks 9 and 21 offshore Angola may change as a result of the working interest transfers discussed below.

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Equity Based Compensation

9 Months Ended

Sep. 30, 2013

Equity Based Compensation

Equity Based Compensation

11. Equity Based Compensation

        The Company accounts for stock-based compensation at fair value. The Company grants various types of stock-based awards including stock options, restricted stock and performance-based awards. The fair value of stock option awards is determined using the Black-Scholes-Merton option-pricing model. For restricted stock awards with market conditions, the fair value of the awards is measured using the asset-or-nothing option pricing model. Restricted stock awards without market conditions and the performance-based awards are valued using the market price of the Company's common stock on the grant date. The Company records compensation cost, net of estimated forfeitures, for stock-based compensation awards over the requisite service period except for performance-based awards. For performance-based awards, compensation cost is recognized over the requisite service period as and when the Company determines that the achievement of the performance condition is probable, using the per-share fair value measured at grant date.

        During the nine months ended September 30, 2013, the Company granted a total of 605,940 shares of restricted stock and 959,023 stock options to employees. During the nine months ended September 30, 2013, the Company also granted 11,056 shares of common stock as retainer awards to non-employee directors who elected to be compensated by stock in lieu of cash payments. In addition, the Company granted a total of 34,833 restricted stock units to non-employee directors during the nine months ended September 30, 2013.

        The Company recorded equity based compensation expense, net of forfeitures, of $6.5 million and $4.7 million for the three months ended September 30, 2013 and 2012, respectively, $18.8 million and $16.7 million for the nine months ended September 30, 2013 and 2012, respectively, and $79.5 million for the period November 10, 2005 (inception) through September 30, 2013.

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Property, Plant, and Equipment (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended	95 Months Ended		0 Months Ended	1 Months Ended	3 Months Ended		9 Months Ended		95 Months Ended			0 Months Ended		9 Months Ended						9 Months Ended				9 Months Ended						9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2013 Garden Banks Block 822, Mississippi Canyon Block 605 and Walker Ridge Block 232	Feb. 26, 2013 Unproved oil and gas properties, net	Sep. 30, 2013 Unproved oil and gas properties, net	Sep. 30, 2013 Unproved oil and gas properties, net	Sep. 30, 2012 Unproved oil and gas properties, net	Sep. 30, 2013 Unproved oil and gas properties, net	Sep. 30, 2012 Unproved oil and gas properties, net	Sep. 30, 2013 Unproved oil and gas properties, net	Dec. 31, 2012 Unproved oil and gas properties, net	Feb. 26, 2013 Unproved oil and gas properties, net Mississippi Canyon Block 209	Dec. 20, 2011 Unproved oil and gas properties, net Block 20 offshore Angola	Sep. 30, 2013 Unproved oil and gas properties, net Block 20 offshore Angola	Sep. 30, 2013 Unproved oil and gas properties, net Blocks 9 and 21 offshore Angola and Gabon	Sep. 30, 2013 Unproved oil and gas properties, net Blocks 9 and 21 offshore Angola	Sep. 30, 2013 Unproved oil and gas properties, net Diaba block offshore Gabon	Sep. 30, 2013 Unproved oil and gas properties, net U.S. Gulf of Mexico	Sep. 30, 2013 Exploratory wells in process	Dec. 31, 2012 Exploratory wells in process	Sep. 30, 2013 Computer equipment and software	Dec. 31, 2012 Computer equipment and software	Sep. 30, 2013 Office equipment and furniture	Dec. 31, 2012 Office equipment and furniture	Sep. 30, 2013 Office equipment and furniture Minimum	Sep. 30, 2013 Office equipment and furniture Maximum	Sep. 30, 2013 Vehicles	Dec. 31, 2012 Vehicles	Sep. 30, 2013 Leasehold improvements	Dec. 31, 2012 Leasehold improvements	Sep. 30, 2013 Leasehold improvements Minimum	Sep. 30, 2013 Leasehold improvements Maximum	Sep. 30, 2013 Running tools and equipment
Property, Plant, and Equipment
Estimated Useful Life																									3 years				3 years	5 years	3 years				3 years	10 years	5 years
Unproved oil and gas properties	$ 754,909,000		$ 754,909,000		$ 721,853,000	$ 754,909,000
Less: accumulated valuation allowance	(110,017,000)		(110,017,000)		(78,413,000)	(110,017,000)
Total oil and gas properties, net	1,411,999,000		1,411,999,000		1,094,464,000	1,411,999,000			644,892,000	644,892,000		644,892,000		644,892,000	643,440,000								767,107,000	451,024,000
Property, plant, and equipment, gross	15,492,000		15,492,000		7,825,000	15,492,000																			4,386,000	3,166,000	2,132,000	2,093,000			265,000	268,000	2,392,000	2,298,000			6,317,000
Less: accumulated depreciation and amortization	(3,865,000)		(3,865,000)		(2,533,000)	(3,865,000)
Total other property and equipment	11,627,000		11,627,000		5,292,000	11,627,000
Total property, plant, and equipment, net	1,423,626,000		1,423,626,000		1,099,756,000	1,423,626,000
Old computer equipment and leasehold improvements written off during the period					2,200,000
Depreciation and amortization	440,000	269,000	1,345,000	782,000		6,097,000
Percentage of working interest acquired																	40.00%			40.00%	21.25%
Consideration for the acquisition																	347,100,000
Consideration payable over five years on acquisition																	337,100,000
Period over which consideration is payable																	5 years
Consideration paid on acquisition							37,600,000											165,700,000
Short-term and long-term contractual obligations																		171,400,000
Unproved																			10,800,000
Unproved property acquisition costs, net of valuation allowance, relating to properties offshore																						287,000,000
Total consideration for the sale																5,600,000
Consideration for the sale received at closing date								1,500,000
Additional consideration for the sale receivable on commencement of operations									1,500,000
Contingent consideration for the sale to be receivable on commencement of production								2,600,000
Gain on sale of assets			2,993,000			2,993,000						3,000,000
Lower limit of unproved leasehold costs assessed individually for impairment																						1,000,000
Upper limit of unproved leasehold costs on individual properties included in group amortization									1,000,000	1,000,000		1,000,000		1,000,000
Carrying amount of unproved properties subject to amortization before impairment provision									69,400,000	69,400,000		69,400,000		69,400,000	69,100,000
Lease impairment allowance										$ 31,300,000	$ 2,300,000	$ 36,100,000	$ 57,800,000	$ 114,700,000

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Property, Plant, and Equipment (Tables)

9 Months Ended

Sep. 30, 2013

Property, Plant, and Equipment

Schedule of Property, Plant, and Equipment

	Estimated Useful Life (Years)	September 30, 2013			December 31, 2012
		($ in thousands)
Oil and Gas Properties:
Unproved oil and gas properties		$	754,909		$	721,853
Less: accumulated valuation allowance			(110,017	)		(78,413	)
			644,892			643,440
Exploratory wells in process			767,107			451,024
Total oil and gas properties, net			1,411,999			1,094,464
Other Property and Equipment:
Computer equipment and software	3		4,386			3,166
Office equipment and furniture	3 - 5		2,132			2,093
Vehicles	3		265			268
Leasehold improvements	3 - 10		2,392			2,298
Running tools and equipment	5		6,317			—
			15,492			7,825
Less: accumulated depreciation and amortization(1)			(3,865	)		(2,533	)
Total other property and equipment, net			11,627			5,292
Property, plant, and equipment, net		$	1,423,626		$	1,099,756

(1)

During the year ended December 31, 2012, the Company wrote off $2.2 million of old computer equipment and leasehold improvements which were fully depreciated and which had no impact on the consolidated statements of operations and consolidated statements of cash flow.

Schedule of net changes in capitalized exploratory well costs

	September 30, 2013			December 31, 2012
	($ in thousands)
Beginning of period	$	451,024		$	178,338
Addition to capitalized exploratory and development costs:
U.S. Gulf of Mexico:
Exploratory well costs		111,724			178,295
Development and pre-development well costs		39,084			—
Capitalized interest		5,206			—
West Africa:
Exploratory well costs(1)		320,464			168,309
Pre-development well costs		9,988			—
Capitalized interest		5,685			—
Reclassifications to wells, facilities, and equipment based on determination of proved reserves		—			—
Amounts charged to expense(2)		(176,068	)		(73,918	)
End of period	$	767,107		$	451,024

(1)

This amount includes $116.0 million of total drilling costs associated with the Mavinga #1 exploratory well, of which $103.5 million has been capitalized as of September 30, 2013 and will remain suspended pending further evaluation of the well to determine possible utilization for the development of the Mavinga field.

(2)

The amount of $176.1 million for the nine months ended September 30, 2013 represents $64.1 million of impairment charges on the Ardennes #1 exploratory well which did not encounter commercial hydrocarbons, $82.4 million of impairment charges related to the lowest drilled interval evaluated by the Cameia #2 drill stem test, which failed to flow measurable hydrocarbons, $17.1 million of impairment charges on the Diaman #1 exploratory well which needed to be re-spud due to mechanical problems with the wellbore, and $12.5 million of impairment charges related to the lowest interval beneath the pay zone that was drilled by the Mavinga #1 exploratory well and determined to have no further utility. The amount of $73.9 million for the year ended December 31, 2012 represents impairment charges on exploratory wells, including $4.1 million for the Heidelberg #3 sidetrack well, $8.1 million for the Ligurian #1 exploratory well, $49.0 million for the Ligurian #2 exploratory well and $12.7 million for the Shenandoah #2 appraisal well.

Schedule of cumulative costs of capitalized exploratory well costs

	September 30, 2013		December 31, 2012
	($ in thousands)
Cumulative costs:
U.S. Gulf of Mexico
Exploratory well costs	$	215,395	$	208,275
Development and pre-development well costs		79,572		—
Capitalized interest		5,206		—
West Africa
Exploratory well costs		447,277		242,749
Pre-development well costs		13,972		—
Capitalized interest		5,685		—
	$	767,107	$	451,024
Well costs capitalized for a period greater than one year after completion of drilling (included in table above)	$	286,968	$	194,853

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Measurements

Significant financial instruments as categorized by the fair value measurement hierarchy

	Level 1				Level 2
									Balance as of September 30, 2013
	Carrying Value		Fair Value(1)		Carrying Value		Fair Value(1)
	($ in thousands)
Cash and cash equivalents:
Cash	$	34,001	$	34,001	$	—	$	—	$	34,001
Money market funds		89,497		89,497		—		—		89,497
Commercial paper		—		—		72,014		72,014		72,014
Certificate of deposits		—		—		25,000		25,000		25,000
Subtotal		123,498		123,498		97,014		97,014		220,512
Short-term restricted funds:
U.S. Treasury bills		—		—		90,315		90,315		90,315
U.S. Treasury notes		—		—		138,218		138,218		138,218
Subtotal		—		—		228,533		228,533		228,533
Short-term investments:
Corporate bonds		—		—		735,586		735,586		735,586
Commercial paper		—		—		440,966		440,966		440,966
Certificates of deposits		—		—		45,000		45,000		45,000
Subtotal		—		—		1,221,552		1,221,552		1,221,552
Long-term restricted funds:
Cash		172		172		—		—		172
Money market funds		371		371		—		—		371
U.S. Treasury notes		—		—		166,158		166,158		166,158
Subtotal		543		543		166,158		166,158		166,701
Long-term investments:
Corporate bonds		—		—		200,597		200,597		200,597
Subtotal		—		—		200,597		200,597		200,597
Total	$	124,041	$	124,041	$	1,913,854	$	1,913,854	$	2,037,895

	Level 1				Level 2
									Balance as of December 31, 2012
	Carrying Value		Fair Value(1)		Carrying Value		Fair Value(1)
	($ in thousands)
Cash and cash equivalents:
Cash	$	65,935	$	65,935	$	—	$	—	$	65,935
Money market funds		1,105,148		1,105,148		—		—		1,105,148
Commercial paper		—		—		247,206		247,206		247,206
Corporate bonds		—		—		7,526		7,526		7,526
Subtotal		1,171,083		1,171,083		254,732		254,732		1,425,815
Short-term restricted funds:
U.S. Treasury bills		—		—		90,440		90,440		90,440
Subtotal		—		—		90,440		90,440		90,440
Short-term investments:
Corporate bonds		—		—		466,898		466,898		466,898
Commercial paper		—		—		315,769		315,769		315,769
Certificates of deposits		—		—		7,001		7,001		7,001
Subtotal		—		—		789,668		789,668		789,668
Long-term restricted funds:
Money market funds		2,318		2,318		—		—		2,318
U.S. Treasury bills		—		—		178,216		178,216		178,216
U.S. Treasury notes		—		—		215,118		215,118		215,118
Subtotal		2,318		2,318		393,334		393,334		395,652
Long-term investments:
Corporate bonds		—		—		36,267		36,267		36,267
Subtotal		—		—		36,267		36,267		36,267
Total	$	1,173,401	$	1,173,401	$	1,564,441	$	1,564,441	$	2,737,842

(1)

As of September 30, 2013 and December 31, 2012, the Company did not record any OTTI on these assets.

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Restricted Funds (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Restricted Funds
Short-term restricted funds	$ 228,533	$ 90,440
Long-term restricted funds	166,701	395,652
Ensco 8503 escrow account
Restricted Funds
Short-term restricted funds	90,315	90,440
Long-term restricted funds		90,440
Collateral on letters of credit for Angola
Restricted Funds
Short-term restricted funds	138,218
Long-term restricted funds	166,529	304,492
Other vendor restricted deposits
Restricted Funds
Long-term restricted funds	$ 172	$ 720

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Long-term Debt (Details) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	9 Months Ended	95 Months Ended		0 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2012	Dec. 17, 2012 Notes	Sep. 30, 2013 Notes	Dec. 31, 2012 Notes
Debt instrument
Aggregate principal amount of notes issued				$ 1,380,000,000
Interest rate (as a percent)			2.625%	2.625%	2.625%	2.625%
Interest paid	16,502,000	16,502,000			16,500,000
Initial conversion rate of common stock				0.028023
Initial conversion price per share of common stock (in dollars per share)				$ 35.68
Number of underlying shares that the holder of the debt instrument would receive upon conversion				38.7
Repurchase price as a percentage of principal amount of debt instrument				100.00%
Specified minimum percentage of principal amount, the holders of which may declare all principal, accrued and unpaid interest to be due and payable immediately, upon the occurrence of an Event of Default				25.00%
Percentage of principal amount, which may be declared by holders of a specified principal amount to be due and payable immediately upon occurrence of an Event of Default				100.00%
Fair value of the notes excluding conversion feature at the date of issuance				989,500,000
Effective interest rate used to amortize liability component of debt issue costs (as a percent)				8.40%
Debt issue cost				32,200,000
Debt issue cost allocated to the liability component				23,100,000
Debt issue cost allocated to the equity component				9,100,000	9,124,000	9,124,000
Carrying amounts of the liability components
Principal Amount					1,380,000,000	1,380,000,000
Unamortized discount					(355,555,000)	(388,809,000)
Carrying amount of the liability components	1,024,445,000	1,024,445,000	991,191,000		1,024,445,000	991,191,000
Remaining term of debt					6 years 3 months
Carrying amounts of the equity components
Debt discount relating to value of conversion option					390,540,000	390,540,000
Debt issue costs				(9,100,000)	(9,124,000)	(9,124,000)
Carrying amount of the equity components					381,416,000	381,416,000
Fair value of the notes excluding conversion feature					$ 1,028,800,000	$ 989,500,000

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Information

Schedule of segment information by geographic operating segment

	United States			West Africa			Total
	($ in thousands)
Three months ended September 30, 2013
Operating costs and expense	$	122,995		$	22,668		$	145,663
Operating income (loss)		(122,995	)		(22,668	)		(145,663	)
Other income (expense)								(14,337	)
Net income (loss)							$	(160,000	)
Additions to Property and Equipment, net(1)	$	1,329		$	148,262		$	149,591
Three months ended September 30, 2012
Operating costs and expense	$	(32,593	)	$	(7,960	)	$	(40,553	)
Operating income (loss)		(32,593	)		(7,960	)		(40,553	)
Other income (expense)								1,339
Net income (loss)							$	(39,214	)
Additions to Property and Equipment, net(1)	$	42,851		$	51,946		$	94,797

	United States			West Africa			Total
	($ in thousands)
Nine months ended September 30, 2013
Operating costs and expense	$	167,817		$	155,664		$	323,481
Operating income (loss)		(167,817	)		(155,664	)		(323,481	)
Other income (expense)								(43,424	)
Net income (loss)							$	(366,905	)
Additions to Property and Equipment, net(1)	$	93,657		$	230,212		$	323,869
Nine months ended September 30, 2012
Operating costs and expense	$	(189,171	)	$	(31,252	)	$	(220,423	)
Operating income (loss)		(189,171	)		(31,252	)		(220,423	)
Other income (expense)								3,955
Net income (loss)							$	(216,468	)
Additions to Property and Equipment, net(1)	$	(7,438	)	$	170,235		$	162,797

(1)

These amounts are net of accumulated allowance for impairment on oil and gas properties and accumulated depreciation and amortization on other property and equipment.

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Seismic and Exploration Expenses (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		95 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013
Seismic and Exploration Expenses
Seismic costs	$ 13,461	$ 4,592	$ 34,548	$ 29,933	$ 376,596
Seismic cost recovery					(25,126)
Leasehold delay rentals	944	1,184	4,050	4,062	36,953
Force Majeure expense					13,549
Drilling rig and other exploration expenses	150	551	2,832	1,687	29,631
Total seismic and exploration expenses	$ 14,555	$ 6,327	$ 41,430	$ 35,682	$ 431,603

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Investments (Tables)

9 Months Ended

Sep. 30, 2013

Investments

Schedule of fair value of held-to-maturity securities recorded at amortized cost

	September 30, 2013		December 31, 2012
	($ in thousands)
U.S. Treasury securities	$	394,690	$	483,775
Corporate securities		936,183		510,691
Commercial paper		512,981		562,975
Certificates of deposit		70,000		7,000
Total	$	1,913,854	$	1,564,441

Schedule of held-to-maturity securities included in the entity's condensed consolidated balance sheets

	September 30, 2013		December 31, 2012
	($ in thousands)
Cash and cash equivalents	$	97,014	$	254,732
Short-term restricted funds		228,533		90,440
Short-term investments		1,221,552		789,668
Long-term restricted funds		166,158		393,334
Long-term investments		200,597		36,267
	$	1,913,854	$	1,564,441

Schedule of contractual maturities of held-to-maturity securities

	September 30, 2013				December 31, 2012
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	($ in thousands)
Within 1 year	$	1,713,257	$	1,713,257	$	1,528,174	$	1,528,174
After 1 year		200,597		200,597		36,267		36,267
	$	1,913,854	$	1,913,854	$	1,564,441	$	1,564,441

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Condensed Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity (Parenthetical)	Dec. 31, 2012
Condensed Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity
Interest rate (as a percent)	2.625%

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

General

        Cobalt International Energy, Inc. (the "Company") is incorporated in the state of Delaware. The Company is an independent, oil-focused exploration and production company with an extensive below salt prospect inventory in the deepwater of the U.S. Gulf of Mexico and offshore Angola and Gabon in West Africa. All of the Company's prospects are oil-focused. To date, the Company's drilling efforts have resulted in discoveries in the U.S. Gulf of Mexico at North Platte, Heidelberg and Shenandoah, offshore Angola at Cameia, Lontra and Mavinga, and offshore Gabon at Diaman. The Company's plan is to continue to mature and drill what it believes are its most promising exploration prospects in the deepwater U.S. Gulf of Mexico and the deepwater offshore Angola and Gabon as it further appraises, evaluates and progresses its existing discoveries toward potential project sanction and development. The Company operates its business in two geographic segments: the U.S. Gulf of Mexico and West Africa.

        The terms "Company," "Cobalt," "we," "us," "our," "ours," and similar terms refer to Cobalt International Energy, Inc. unless the context indicates otherwise.

Basis of Presentation

        The accompanying unaudited condensed consolidated financial statements include the financial statements of Cobalt International Energy, Inc. and all of its wholly-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. Because the Company is a development stage enterprise, it has presented its financial statements in accordance with accounting guidance related to "Development Stage Entities."

        The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles ("GAAP") for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission ("SEC"). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for interim periods are not necessarily indicative of the results that may be presented for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company's Annual Report on Form 10-K for the year ended December 31, 2012.

Reclassifications

        Certain reclassifications have been made to prior periods' financial statements to conform to the current presentation in the unaudited condensed consolidated statements of cash flows.

Use of Estimates

        The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by the Company include (i) accruals related to expenses, (ii) assumptions used in estimating fair value of equity based awards and the fair value of the liability component of the convertible senior notes and (iii) assumptions used in impairment testing. Although the Company believes these estimates are reasonable, actual results could differ from these estimates.

Investments

        The Company's policy on accounting for its investments, which consist entirely of debt securities, is based on the accounting guidance relating to "Accounting for Certain Investments in Debt and Equity Securities." The Company considers all highly liquid interest-earning investments with a maturity of three months or less at the date of purchase to be cash equivalents. Investments with original maturities of greater than three months and remaining maturities of less than one year are classified as short-term investments. Investments with maturities beyond one year are classified as long-term investments. The debt securities are carried at amortized costs and classified as held-to-maturity securities as the Company has the positive intent and ability to hold them until they mature. The net carrying value of held-to-maturity securities is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the securities. Held-to-maturity securities are stated at amortized cost, which approximates fair market value as of September 30, 2013 and December 31, 2012. Income related to these securities is reported as a component of interest income in the Company's condensed consolidated statement of operations. See Note 5—Investments.

        Investments are considered to be impaired when a decline in fair value is determined to be other-than-temporary. The Company conducts a regular assessment of its debt securities with unrealized losses to determine whether securities have other-than-temporary impairment ("OTTI"). This assessment considers, among other factors, the nature of the securities, credit rating or financial condition of the issuer, the extent and duration of the unrealized loss, market conditions and whether the Company intends to sell or whether it is more likely than not that the Company will be required to sell the debt securities. As of September 30, 2013 and December 31, 2012, the Company has no OTTI in its debt securities.

Capitalized Interest

        For exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 7—Property, Plant, and Equipment and Note 8—Long-term Debt.

Earnings (Loss) Per Share

        Basic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted income (loss) per share should include the potential dilutive impact of non-vested restricted shares, non-vested restricted stock units, outstanding stock options and 2.625% convertible senior notes due 2019, during the period, unless their effect is anti-dilutive. For the three months and nine months ended September 30, 2013, 6,744,278 shares of non-vested restricted stock, non-vested restricted stock units, outstanding stock options and 2.625% convertible senior notes due 2019, were excluded from the diluted income (loss) per share because they are anti-dilutive. For the three months and nine months ended September 30, 2012, 5,594,092 shares of non-vested restricted stock, non-vested restricted stock units and outstanding stock options were excluded from the diluted income (loss) per share because they are anti-dilutive.

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Joint Interest and Other Receivables

9 Months Ended

Sep. 30, 2013

Joint Interest and Other Receivables

Joint Interest and Other Receivables

4. Joint Interest and Other Receivables

        Joint interest and other receivables result primarily from billing shared costs under the respective operating agreements to the Company's partners. These are usually settled within 30 days of the invoice date.

	September 30, 2013		December 31, 2012
	($ in thousands)
Partners in the U.S. Gulf of Mexico	$	45,663	$	52,439
Partners in West Africa(1)		53,223		2,185
Accrued interest on investment securities		8,313		3,647
Vendors' receivables		1,582		1,526
Other		1,072		1,795
Total	$	109,853	$	61,592

(1)

The amount of $53.2 million as of September 30, 2013 includes $30.6 million related to our partners on Block 20 offshore Angola and $22.6 million related to our partners on Blocks 9 and 21 offshore Angola. Although we expect to collect these receivables in full, including $11.3 million that is currently past due, the allocation of the receivable amongst our partners on Blocks 9 and 21 offshore Angola may change as a result of the working interest transfers discussed below.

        On September 19, 2013, we received a letter from Sociedade Nacional de Combustíveis de Angola—Empresa Pública notifying us that Nazaki Oil and Gáz, S.A. had transferred a 15% working interest in each of Blocks 9 and 21 offshore Angola out of its 30% working interest in each block to Sonangol Pesquisa e Produção, S.A. ("Sonangol P&P"). The letter stated that these transfers were effective as of March 14, 2013 for Block 9 and February 18, 2013 for Block 21, corresponding to the dates of the executive decrees from the Angola Ministry of Petroleum authorizing such transfers. As a result of these transfers, Sonangol P&P now has a working interest of 35% and paying interest of 18.75% (which is applicable only during the exploration phase on Blocks 9 and 21) in each of Blocks 9 and 21. Our working interest of 40% and paying interest of 62.5% (which is applicable only during the exploration phase on Blocks 9 and 21) in each of Blocks 9 and 21 remains unchanged as a result of these transfers. We are the operator of Blocks 9 and 21.

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Cash and Cash Equivalents

9 Months Ended

Sep. 30, 2013

Cash and Cash Equivalents

Cash and Cash Equivalents

2. Cash and Cash Equivalents

        Cash and cash equivalents consisted of the following:

	September 30, 2013		December 31, 2012
	($ in thousands)
Cash at banks	$	34,001	$	65,935
Money market funds		89,497		1,105,148
Held-to-maturity securities(1)		97,014		254,732
	$	220,512	$	1,425,815

(1)

These securities mature three months or less from the date of purchase.

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Long-term Debt (Details 2) (USD $)	3 Months Ended	9 Months Ended	95 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
Long-term Debt
Interest expense associated with accrued interest	$ 3,956,000	$ 16,276,000	$ 17,570,000
Interest expense associated with accretion of debt discount	11,307,000	33,254,000	35,165,000
Interest expense associated with amortization of debt issue costs	539,000	1,497,000	1,572,000
Total	15,802,000	51,027,000	54,307,000
Capitalized interest costs	$ 5,100,000	$ 10,900,000

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Long-term Debt (Tables)

9 Months Ended

Sep. 30, 2013

Long-term Debt

Schedule of the carrying amounts of the liability components of the Notes

	September 30, 2013							December 31, 2012
	Principal Amount		Unamortized discount(1)			Carrying Amount		Principal Amount		Unamortized discount			Carrying Amount
	($ in thousands)
Carrying amount of liability component
2.625% convertible senior notes	$	1,380,000	$	(355,555	)	$	1,024,445	$	1,380,000	$	(388,809	)	$	991,191

(1)

Unamortized discount will be amortized over the remaining life of the Notes which is 6.25 years.

Schedule of carrying amounts of the equity components of the Notes

	September 30, 2013			December 31, 2012
	($ in thousands)
Debt discount relating to value of conversion option	$	390,540		$	390,540
Debt issue costs		(9,124	)		(9,124	)
Total	$	381,416		$	381,416

Schedule of interest expense

									For the Period November 10, 2005 (Inception) through September 30, 2013
	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in thousands)
Interest expense associated with accrued interest(1)	$	3,956	$	—	$	16,276	$	—	$	17,570
Interest expense associated with accretion of debt discount		11,307		—		33,254		—		35,165
Interest expense associated with amortization of debt issue costs		539		—		1,497		—		1,572
Total	$	15,802	$	—	$	51,027	$	—	$	54,307

(1)

The $4.0 million and $16.3 million for the three and nine months ended September 30, 2013, respectively, represent interest expense net of capitalized amount of $5.1 million and $10.9 million, respectively.

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Summary of Significant Accounting Policies (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Segment	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013 2.625% convertible senior notes due 2019	Dec. 31, 2012 2.625% convertible senior notes due 2019	Dec. 17, 2012 2.625% convertible senior notes due 2019
Summary of Significant Accounting Policies
Number of geographic segments			2
Investments
Maximum term of maturity to classify highly liquid interest earning investments as cash equivalent			3 months
Minimum term of maturity to classify an investment as short-term investment			3 months
Maximum term of maturity to classify an investment as short-term investment			1 year
OTTI in debt securities	$ 0		$ 0		$ 0
Earnings (Loss) Per Share
Shares of non-vested restricted stock, non vested restricted stock units, outstanding stock options and 2.625% convertible senior notes due 2019 excluded from the diluted income (loss) per share calculation	6,744,278		6,744,278
Shares of non-vested restricted stock, non-vested restricted stock units and outstanding stock excluded from the diluted income (loss) per share calculation		5,594,092		5,594,092
Earnings (Loss) Per Share
Interest rate (as a percent)					2.625%	2.625%	2.625%	2.625%

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Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	$ 1,913,854	$ 1,564,441
Fair Value	1,913,854	1,564,441
Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	2,037,895	2,737,842
Cash and cash equivalents
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	97,014	254,732
Cash and cash equivalents | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	220,512	1,425,815
Cash and cash equivalents | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	34,001	65,935
Cash and cash equivalents | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	89,497	1,105,148
Cash and cash equivalents | Commercial paper | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	72,014	247,206
Cash and cash equivalents | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		7,526
Cash and cash equivalents | Certificates of deposits | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	25,000
Short-term restricted funds
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	228,533	90,440
Short-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	228,533	90,440
Short-term restricted funds | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	90,315	90,440
Short-term restricted funds | U.S. Treasury notes | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	138,218
Short-term investments
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	1,221,552	789,668
Short-term investments | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	1,221,552	789,668
Short-term investments | Commercial paper | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	440,966	315,769
Short-term investments | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	735,586	466,898
Short-term investments | Certificates of deposits | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	45,000	7,001
Long-term restricted funds
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	166,158	393,334
Long-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	166,701	395,652
Long-term restricted funds | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	172
Long-term restricted funds | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	371	2,318
Long-term restricted funds | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		178,216
Long-term restricted funds | U.S. Treasury notes | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	166,158	215,118
Long-term investments
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	200,597	36,267
Long-term investments | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	200,597	36,267
Long-term investments | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	200,597	36,267
Level 1 | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	124,041	1,173,401
Fair Value	124,041	1,173,401
Level 1 | Cash and cash equivalents | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	123,498	1,171,083
Fair Value	123,498	1,171,083
Level 1 | Cash and cash equivalents | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	34,001	65,935
Fair Value	34,001	65,935
Level 1 | Cash and cash equivalents | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	89,497	1,105,148
Fair Value	89,497	1,105,148
Level 1 | Long-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	543	2,318
Fair Value	543	2,318
Level 1 | Long-term restricted funds | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	172
Fair Value	172
Level 1 | Long-term restricted funds | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	371	2,318
Fair Value	371	2,318
Level 2 | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	1,913,854	1,564,441
Fair Value	1,913,854	1,564,441
Level 2 | Cash and cash equivalents | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	97,014	254,732
Fair Value	97,014	254,732
Level 2 | Cash and cash equivalents | Commercial paper | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	72,014	247,206
Fair Value	72,014	247,206
Level 2 | Cash and cash equivalents | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value		7,526
Fair Value		7,526
Level 2 | Cash and cash equivalents | Certificates of deposits | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	25,000
Fair Value	25,000
Level 2 | Short-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	228,533	90,440
Fair Value	228,533	90,440
Level 2 | Short-term restricted funds | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	90,315	90,440
Fair Value	90,315	90,440
Level 2 | Short-term restricted funds | U.S. Treasury notes | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	138,218
Fair Value	138,218
Level 2 | Short-term investments | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	1,221,552	789,668
Fair Value	1,221,552	789,668
Level 2 | Short-term investments | Commercial paper | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	440,966	315,769
Fair Value	440,966	315,769
Level 2 | Short-term investments | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	735,586	466,898
Fair Value	735,586	466,898
Level 2 | Short-term investments | Certificates of deposits | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	45,000	7,001
Fair Value	45,000	7,001
Level 2 | Long-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	166,158	393,334
Fair Value	166,158	393,334
Level 2 | Long-term restricted funds | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value		178,216
Fair Value		178,216
Level 2 | Long-term restricted funds | U.S. Treasury notes | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	166,158	215,118
Fair Value	166,158	215,118
Level 2 | Long-term investments | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	200,597	36,267
Fair Value	200,597	36,267
Level 2 | Long-term investments | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Carrying Value	200,597	36,267
Fair Value	$ 200,597	$ 36,267

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		86 Months Ended	95 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Segment	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013
Segment Information
Number of geographic operating segments			2
Segment Information
Operating costs and expense	$ 145,663	$ 40,553	$ 323,481	$ 220,423		$ 1,263,079
Operating income (loss)	(145,663)	(40,553)	(323,481)	(220,423)		(1,263,079)
Other income (expense)	(14,337)	1,339	(43,424)	3,955		(31,661)
Net income (loss)	(160,000)	(39,214)	(366,905)	(216,468)	(927,835)	(1,294,740)
Additions to Property and Equipment, net	149,591	94,797	323,869	162,797
United States
Segment Information
Operating costs and expense	122,995	(32,593)	167,817	(189,171)
Operating income (loss)	(122,995)	(32,593)	(167,817)	(189,171)
Additions to Property and Equipment, net	1,329	42,851	93,657	(7,438)
West Africa
Segment Information
Operating costs and expense	22,668	(7,960)	155,664	(31,252)
Operating income (loss)	(22,668)	(7,960)	(155,664)	(31,252)
Additions to Property and Equipment, net	$ 148,262	$ 51,946	$ 230,212	$ 170,235

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Condensed Consolidated Balance Sheets
Oil and gas properties, successful efforts method of accounting, accumulated depletion (in dollars)	$ 0	$ 0
Other property and equipment, accumulated depreciation and amortization (in dollars)	$ 3,865	$ 2,533
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares issued	406,943,582	406,596,884
Common stock, shares outstanding	406,943,582	406,596,884

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Property, Plant, and Equipment

9 Months Ended

Sep. 30, 2013

Property, Plant, and Equipment

Property, Plant, and Equipment

7. Property, Plant, and Equipment

        Property, plant, and equipment is stated at cost less accumulated depreciation/amortization and consisted of the following:

	Estimated Useful Life (Years)	September 30, 2013			December 31, 2012
		($ in thousands)
Oil and Gas Properties:
Unproved oil and gas properties		$	754,909		$	721,853
Less: accumulated valuation allowance			(110,017	)		(78,413	)
			644,892			643,440
Exploratory wells in process			767,107			451,024
Total oil and gas properties, net			1,411,999			1,094,464
Other Property and Equipment:
Computer equipment and software	3		4,386			3,166
Office equipment and furniture	3 - 5		2,132			2,093
Vehicles	3		265			268
Leasehold improvements	3 - 10		2,392			2,298
Running tools and equipment	5		6,317			—
			15,492			7,825
Less: accumulated depreciation and amortization(1)			(3,865	)		(2,533	)
Total other property and equipment, net			11,627			5,292
Property, plant, and equipment, net		$	1,423,626		$	1,099,756

(1)

During the year ended December 31, 2012, the Company wrote off $2.2 million of old computer equipment and leasehold improvements which were fully depreciated and which had no impact on the consolidated statements of operations and consolidated statements of cash flow.

        The Company recorded $0.4 million and $0.3 million for the three months ended September 30, 2013 and 2012, respectively, $1.3 million and $0.8 million for the nine months ended September 30, 2013 and 2012, respectively, and $6.1 million of depreciation and amortization for the period November 10, 2005 (inception) through September 30, 2013, respectively.

Unproved Oil and Gas Properties

        On December 20, 2011, the Company acquired a 40% working interest in Block 20 offshore Angola for a total consideration of $347.1 million, of which $337.1 million is contractually scheduled to be paid over five years commencing in January 2012. As of September 30, 2013, out of the $337.1 million, $165.7 million has been paid and the remaining $171.4 million was accrued in short-term and long-term contractual obligations. See Note 9—Contractual Obligations. In addition to the Block 20 interests, the Company has $10.8 million of unproved property acquisition costs relating to its 40% interests in Blocks 9 and 21 offshore Angola and its 21.25% working interest in the Diaba block offshore Gabon.

        As of September 30, 2013, the Company also has $287.0 million of unproved property acquisition costs, net of valuation allowance for impairment, relating to its U.S. Gulf of Mexico properties. On February 26, 2013, the Company executed a Purchase and Sale agreement (the "PSA") to sell its ownership interests on an unproved oil and gas property on Mississippi Canyon Block 209 for a total consideration of $5.6 million. The Company received $1.5 million at closing and an additional $1.5 million in September 2013 when the buyer commenced operations on the property. Pursuant to the terms and conditions of the PSA, the Company will receive the remaining $2.6 million contingent upon the purchaser's commencement of production on this property in the future. For the nine months ended September 30, 2013, the Company recognized a gain of $3.0 million on the sale of assets as a result of this transaction. During the nine months ended September 30, 2013, the Company paid a total consideration of $37.6 million for acquisition of ownership interests in unproved oil and gas properties on Garden Banks Block 822, Mississippi Canyon Block 605 and Walker Ridge Block 232 in the U.S. Gulf of Mexico.

        As of September 30, 2013 and December 31, 2012, the Company has a net total of $644.9 million and $643.4 million, respectively, of unproved property acquisition costs on the condensed consolidated balance sheets.

        Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent associated with successful exploration activities. There are no impairment indicators to date that would require the Company to impair the unproved properties in Blocks 9, 20, and 21 offshore Angola and in the Diaba block offshore Gabon. Oil and gas leases for unproved properties in the U.S. Gulf of Mexico with carrying value greater than $1.0 million are assessed individually for impairment based on the Company's current exploration plans and an allowance for impairment is provided if impairment is indicated. Leases that are individually less than $1.0 million in carrying value or are near expiration are amortized on a group basis over the average terms of the leases at rates that provide for full amortization of leases upon lease expiration. These leases have expiration dates ranging from 2013 through 2022. As of September 30, 2013 and December 31, 2012, the balance for unproved properties that were subject to amortization before impairment provision was $69.4 million and $69.1 million, respectively. The Company recorded a lease impairment allowance of $31.3 million and $2.3 million for the three months ended September 30, 2013 and 2012, respectively, $36.1 million and $57.8 million for the nine months ended September 30, 2013 and 2012, respectively, and $114.7 million for the period November 10, 2005 (inception) through September 30, 2013.

Capitalized Costs

        If an exploratory well provides evidence as to the existence of sufficient quantities of hydrocarbons to justify potential completion as a producing well, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas (generally, deepwater and international locations) depending upon, among other things, (i) the amount of hydrocarbons discovered, (ii) the outcome of planned geological and engineering studies, (iii) the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan and (iv) the requirement for government sanctioning in international locations before proceeding with development activities.

        The following tables reflect the Company's net changes in and the cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs):

	September 30, 2013			December 31, 2012
	($ in thousands)
Beginning of period	$	451,024		$	178,338
Addition to capitalized exploratory and development costs:
U.S. Gulf of Mexico:
Exploratory well costs		111,724			178,295
Development and pre-development well costs		39,084			—
Capitalized interest		5,206			—
West Africa:
Exploratory well costs(1)		320,464			168,309
Pre-development well costs		9,988			—
Capitalized interest		5,685			—
Reclassifications to wells, facilities, and equipment based on determination of proved reserves		—			—
Amounts charged to expense(2)		(176,068	)		(73,918	)
End of period	$	767,107		$	451,024

(1)

This amount includes $116.0 million of total drilling costs associated with the Mavinga #1 exploratory well, of which $103.5 million has been capitalized as of September 30, 2013 and will remain suspended pending further evaluation of the well to determine possible utilization for the development of the Mavinga field.

(2)

The amount of $176.1 million for the nine months ended September 30, 2013 represents $64.1 million of impairment charges on the Ardennes #1 exploratory well which did not encounter commercial hydrocarbons, $82.4 million of impairment charges related to the lowest drilled interval evaluated by the Cameia #2 drill stem test, which failed to flow measurable hydrocarbons, $17.1 million of impairment charges on the Diaman #1 exploratory well which needed to be re-spud due to mechanical problems with the wellbore, and $12.5 million of impairment charges related to the lowest interval beneath the pay zone that was drilled by the Mavinga #1 exploratory well and determined to have no further utility. The amount of $73.9 million for the year ended December 31, 2012 represents impairment charges on exploratory wells, including $4.1 million for the Heidelberg #3 sidetrack well, $8.1 million for the Ligurian #1 exploratory well, $49.0 million for the Ligurian #2 exploratory well and $12.7 million for the Shenandoah #2 appraisal well.

	September 30, 2013		December 31, 2012
	($ in thousands)
Cumulative costs:
U.S. Gulf of Mexico
Exploratory well costs	$	215,395	$	208,275
Development and pre-development well costs		79,572		—
Capitalized interest		5,206		—
West Africa
Exploratory well costs		447,277		242,749
Pre-development well costs		13,972		—
Capitalized interest		5,685		—
	$	767,107	$	451,024
Well costs capitalized for a period greater than one year after completion of drilling (included in table above)	$	286,968	$	194,853

        As of September 30, 2013, capitalized well costs that have been suspended longer than one year are associated with the Shenandoah, Heidelberg, North Platte and Cameia discoveries. These well costs except for Heidelberg are suspended pending ongoing evaluation including, but not limited to, results of additional appraisal drilling, well-test analysis, additional geological and geophysical data and approval of a development plan. Management believes these discoveries exhibit sufficient indications of hydrocarbons to justify potential development and is actively pursuing efforts to fully assess them. If additional information becomes available that raises substantial doubt as to the economic or operational viability of these discoveries, the associated costs will be expensed at that time. The Heidelberg discovery has been sanctioned for development and the Heidelberg capitalized exploratory and appraisal well costs were reclassified to development well costs as of September 30, 2013.

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Condensed Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity (USD $) In Thousands	Total	Class A Limited Partners	Class B Limited Partners	Class C Limited Partners	Common Stock	Additional Paid-in Capital	Accumulated Deficit During Development Stage
Balance (Inception) at Nov. 10, 2005
Class A limited partners' contributions	$ 1,256,738	$ 1,256,738
Class B & C limited partners' equity compensation	7,718		6,984	734
Common stock issued upon corporate reorganization		(1,256,738)	(6,984)	(734)	2,743	1,261,713
Common stock issued at initial public offering, net of offering costs	807,259				630	806,629
Common stock issued at private placement	42,188				32	42,156
Common stock issued at the closing of the over-allotment portion of initial public offering, net of offering costs	101,256				80	101,176
Common stock issued at public offering, net of costs	967,512				538	966,974
Common stock issued for restricted stock and stock options					44	(44)
Equity based compensation	52,989					52,989
Common stock withheld for taxes on equity based compensation	(361)				(1)	(360)
Exercise of stock options	338					338
Conversion option relating to 2.625% convertible senior notes, net of allocated costs	381,416					381,416
Net income (loss)	(927,835)						(927,835)
Balance at Dec. 31, 2012	2,689,218				4,066	3,612,987	(927,835)
Common stock issued for restricted stock and stock options					3	(3)
Equity based compensation	18,795					18,795
Exercise of stock options	198					198
Net income (loss)	(366,905)						(366,905)
Balance at Sep. 30, 2013	$ 2,341,306				$ 4,069	$ 3,631,977	$ (1,294,740)

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 220,512	$ 1,425,815
Joint interest and other receivables	109,853	61,592
Prepaid expenses and other current assets	26,423	23,941
Inventory	83,225	65,286
Short-term restricted funds	228,533	90,440
Short-term investments	1,221,552	789,668
Total current assets	1,890,098	2,456,742
Property, plant, and equipment:
Oil and gas properties, successful efforts method of accounting, net of accumulated depletion of $-0-	1,411,999	1,094,464
Other property and equipment, net of accumulated depreciation and amortization of $3,865 and $2,533, as of September 30, 2013 and December 31, 2012, respectively	11,627	5,292
Total property, plant, and equipment, net	1,423,626	1,099,756
Long-term restricted funds	166,701	395,652
Long-term investments	200,597	36,267
Other assets	34,809	23,042
Total assets	3,715,831	4,011,459
Current liabilities:
Trade and other accounts payable	10,418	67,876
Accrued liabilities	163,056	44,061
Short-term contractual obligations	49,019	49,019
Total current liabilities	222,493	160,956
Long-term debt	1,024,445	991,191
Long-term contractual obligations	124,901	168,238
Other long-term liabilities	2,686	1,856
Total long-term liabilities	1,152,032	1,161,285
Stockholders' Equity:
Common stock, $0.01 par value per share; 2,000,000,000 shares authorized, 406,943,582 and 406,596,884 issued and outstanding as of September 30, 2013 and December 31, 2012, respectively	4,069	4,066
Additional paid-in capital	3,631,977	3,612,987
Accumulated deficit during the development stage	(1,294,740)	(927,835)
Total stockholders' equity	2,341,306	2,689,218
Total liabilities and stockholders' equity	$ 3,715,831	$ 4,011,459

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Contractual Obligations (Tables)

9 Months Ended

Sep. 30, 2013

Contractual Obligations

Summary of components of short-term and long-term contractual obligations

	September 30, 2013		December 31, 2012
	($ in thousands)
Short-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	150	$	150
Social obligation payments for Block 21, offshore Angola		300		300
Social obligation and bonus payments for Block 20, offshore Angola(1)		48,569		48,569
	$	49,019	$	49,019
Long-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	668	$	848
Social obligation payments for Block 21, offshore Angola		1,382		1,684
Social obligation and bonus payments for Block 20, offshore Angola(1)		122,851		165,706
	$	124,901	$	168,238

(1)

The total amount of social obligation payments for Block 20 has been capitalized. See Note 7—Property, Plant, and Equipment.

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Restricted Funds (Tables)

9 Months Ended

Sep. 30, 2013

Restricted Funds

Schedule of restricted funds

	September 30, 2013		December 31, 2012
	($ in thousands)
Short-term:
Ensco 8503 escrow account	$	90,315	$	90,440
Collateral on letters of credit for Angola		138,218		—
	$	228,533	$	90,440
Long-term:
Ensco 8503 escrow account		—		90,440
Collateral on letters of credit for Angola		166,529		304,492
Other vendor restricted deposits		172		720
	$	166,701	$	395,652

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Equity Based Compensation (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended		95 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013
Number of Stock Options
Equity based compensation expense, net of forfeitures recognized	$ 6,500	$ 4,700	$ 18,795	$ 16,650	$ 79,501
Restricted Stock
Number of shares relating to award
Granted (in shares)			605,940
Restricted Stock | Non-employee directors
Number of shares relating to award
Granted (in shares)			34,833
Retainer awards | Non-employee directors | Common Stock
Number of shares relating to award
Granted (in shares)			11,056
Stock options
Number of Stock Options
Granted (in shares)			959,023

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Property, Plant, and Equipment (Details 2) (USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	$ 451,024	$ 178,338
Addition to capitalized exploratory and development costs	176,100
Amounts charged to expense	(176,068)	(73,918)
End of period	767,107	451,024
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	767,107	451,024
Well costs capitalized for a period greater than one year after completion of drilling	286,968	194,853
Mavinga #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense	(12,500)
Diaman #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense	(17,100)
Cameia #2 Drill Stem Test
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense	(82,400)
Ligurian #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense		(8,100)
Shenandoah #2 Appraisal Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense		(12,700)
Ligurian #2 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense		(49,000)
Heidelberg #3 Appraisal Well Side Track
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense		(4,100)
Ardennes #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense	(64,100)
U.S. Gulf of Mexico | Exploratory well costs
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	208,275
Addition to capitalized exploratory and development costs	111,724	178,295
End of period	215,395	208,275
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	215,395	208,275
U.S. Gulf of Mexico | Development and pre-development well costs
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory and development costs	39,084
End of period	79,572
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	79,572
U.S. Gulf of Mexico | Capitalized interest
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory and development costs	5,206
End of period	5,206
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	5,206
West Africa | Exploratory well costs
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	242,749
Addition to capitalized exploratory and development costs	320,464	168,309
End of period	447,277	242,749
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	447,277	242,749
West Africa | Capitalized interest
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory and development costs	5,685
End of period	5,685
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	5,685
West Africa | Pre-development well costs
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory and development costs	9,988
End of period	13,972
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	13,972
West Africa | Mavinga #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory and development costs	116,000
End of period	103,500
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	$ 103,500

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Joint Interest and Other Receivables (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Block 9, offshore Angola	Sep. 19, 2013 Block 9, offshore Angola	Sep. 30, 2013 Block 9, offshore Angola Sonangol P&P	Sep. 19, 2013 Block 9, offshore Angola Sonangol P&P	Sep. 30, 2013 Block 21, offshore Angola	Sep. 19, 2013 Block 21, offshore Angola	Sep. 30, 2013 Block 21, offshore Angola Sonangol P&P	Sep. 19, 2013 Block 21, offshore Angola Sonangol P&P	Sep. 30, 2013 Partners in the U.S. Gulf of Mexico	Dec. 31, 2012 Partners in the U.S. Gulf of Mexico	Sep. 30, 2013 Partners in West Africa	Dec. 31, 2012 Partners in West Africa	Sep. 30, 2013 Partners in West Africa Block 20, offshore Angola	Sep. 30, 2013 Partners in West Africa Blocks 9 and 21 offshore Angola
Joint Interest and Other Receivables
Settlement period for bills under operating agreements	30 days
Joint Interest Receivables
Receivable attributable to joint interest partners											$ 45,663,000	$ 52,439,000	$ 53,223,000	$ 2,185,000	$ 30,600,000	$ 22,600,000
Accrued interest on investment securities	8,313,000	3,647,000
Vendors' receivables	1,582,000	1,526,000
Other	1,072,000	1,795,000
Total	109,853,000	61,592,000
Joint interest and other receivables which became past due																$ 11,300,000
Percentage of working interest transferred						15.00%				15.00%
Percentage of working interest held			40.00%	30.00%	35.00%		40.00%	30.00%	35.00%
Percentage of working paying interest			62.50%		18.75%		62.50%		18.75%

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Investments (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Investments
Fair market value	$ 1,913,854	$ 1,564,441
Held-to-maturities, Carrying value
Within 1 year	1,713,257	1,528,174
After 1 year	200,597	36,267
Total	1,913,854	1,564,441
Held-to-maturity securities, Estimated fair value
Within 1 year	1,713,257	1,528,174
After 1 year	200,597	36,267
Total	1,913,854	1,564,441
Cash and cash equivalents
Investments
Fair market value	97,014	254,732
Short-term restricted funds
Investments
Fair market value	228,533	90,440
Short-term investments
Investments
Fair market value	1,221,552	789,668
Long-term restricted funds
Investments
Fair market value	166,158	393,334
Long-term investments
Investments
Fair market value	200,597	36,267
U.S. Treasury securities
Investments
Fair market value	394,690	483,775
Corporate securities
Investments
Fair market value	936,183	510,691
Commercial paper
Investments
Fair market value	512,981	562,975
Certificates of deposit
Investments
Fair market value	$ 70,000	$ 7,000

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Fair Value Measurements

9 Months Ended

Sep. 30, 2013

Fair Value Measurements

Fair Value Measurements

6. Fair Value Measurements

        The fair values of the Company's cash and cash equivalents, joint interest and other receivables, restricted funds and investments approximate their carrying amounts due to their short-term duration. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. The Company categorizes each of its fair value measurements as applicable to one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. The levels are:

•         Level 1—Quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities. This category includes the Company's cash and money market funds.

          Level 2—Quoted prices in non-active markets or in active markets for similar assets or liabilities, and inputs other than quoted prices that are observable, for the asset or liability, either directly or indirectly, for substantially the full contractual term of the asset or liability being measured. This category includes the Company's U.S. Treasury bills, U.S. Treasury notes, U.S. Government agency securities, commercial paper, corporate bonds, municipal bonds and certificates of deposits.

          Level 3—Inputs that are generally unobservable and typically reflect management's estimate of assumptions that market participants would use in pricing the asset or liability. The Company does not currently have any financial instruments categorized as Level 3.

        The following tables summarize the Company's significant financial instruments as categorized by the fair value measurement hierarchy:

	Level 1				Level 2
									Balance as of September 30, 2013
	Carrying Value		Fair Value(1)		Carrying Value		Fair Value(1)
	($ in thousands)
Cash and cash equivalents:
Cash	$	34,001	$	34,001	$	—	$	—	$	34,001
Money market funds		89,497		89,497		—		—		89,497
Commercial paper		—		—		72,014		72,014		72,014
Certificate of deposits		—		—		25,000		25,000		25,000
Subtotal		123,498		123,498		97,014		97,014		220,512
Short-term restricted funds:
U.S. Treasury bills		—		—		90,315		90,315		90,315
U.S. Treasury notes		—		—		138,218		138,218		138,218
Subtotal		—		—		228,533		228,533		228,533
Short-term investments:
Corporate bonds		—		—		735,586		735,586		735,586
Commercial paper		—		—		440,966		440,966		440,966
Certificates of deposits		—		—		45,000		45,000		45,000
Subtotal		—		—		1,221,552		1,221,552		1,221,552
Long-term restricted funds:
Cash		172		172		—		—		172
Money market funds		371		371		—		—		371
U.S. Treasury notes		—		—		166,158		166,158		166,158
Subtotal		543		543		166,158		166,158		166,701
Long-term investments:
Corporate bonds		—		—		200,597		200,597		200,597
Subtotal		—		—		200,597		200,597		200,597
Total	$	124,041	$	124,041	$	1,913,854	$	1,913,854	$	2,037,895

	Level 1				Level 2
									Balance as of December 31, 2012
	Carrying Value		Fair Value(1)		Carrying Value		Fair Value(1)
	($ in thousands)
Cash and cash equivalents:
Cash	$	65,935	$	65,935	$	—	$	—	$	65,935
Money market funds		1,105,148		1,105,148		—		—		1,105,148
Commercial paper		—		—		247,206		247,206		247,206
Corporate bonds		—		—		7,526		7,526		7,526
Subtotal		1,171,083		1,171,083		254,732		254,732		1,425,815
Short-term restricted funds:
U.S. Treasury bills		—		—		90,440		90,440		90,440
Subtotal		—		—		90,440		90,440		90,440
Short-term investments:
Corporate bonds		—		—		466,898		466,898		466,898
Commercial paper		—		—		315,769		315,769		315,769
Certificates of deposits		—		—		7,001		7,001		7,001
Subtotal		—		—		789,668		789,668		789,668
Long-term restricted funds:
Money market funds		2,318		2,318		—		—		2,318
U.S. Treasury bills		—		—		178,216		178,216		178,216
U.S. Treasury notes		—		—		215,118		215,118		215,118
Subtotal		2,318		2,318		393,334		393,334		395,652
Long-term investments:
Corporate bonds		—		—		36,267		36,267		36,267
Subtotal		—		—		36,267		36,267		36,267
Total	$	1,173,401	$	1,173,401	$	1,564,441	$	1,564,441	$	2,737,842

(1)

As of September 30, 2013 and December 31, 2012, the Company did not record any OTTI on these assets.

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Seismic and Exploration Expenses (Tables)

9 Months Ended

Sep. 30, 2013

Seismic and Exploration Expenses

Schedule of seismic and exploration expenses

									For the Period November 10, 2005 (Inception) through September 30, 2013
	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in Thousands)
Seismic costs	$	13,461	$	4,592	$	34,548	$	29,933	$	376,596
Seismic cost recovery(1)		—		—		—		—		(25,126	)
Leasehold delay rentals		944		1,184		4,050		4,062		36,953
Force Majeure expense(2)		—		—		—		—		13,549
Drilling rig and other exploration expenses		150		551		2,832		1,687		29,631
	$	14,555	$	6,327	$	41,430	$	35,682	$	431,603

(1)

This amount represents reimbursement from partners of past seismic costs incurred by the Company.

(2)

This amount represents expenditures resulting from suspension of drilling activities in the U.S. Gulf of Mexico as a result of the explosion and sinking of the Deepwater Horizon drilling rig in the U.S. Gulf of Mexico, the resulting oil spill and the regulatory response thereto and other exploratory expenses.

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Contractual Obligations (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Contractual obligations
Short-term Contractual Obligations: Social obligation payments	$ 49,019	$ 49,019
Long-term Contractual Obligations: Social obligation payments	124,901	168,238
Block 9, offshore Angola
Contractual obligations
Short-term Contractual Obligations: Social obligation payments	150	150
Long-term Contractual Obligations: Social obligation payments	668	848
Block 21, offshore Angola
Contractual obligations
Short-term Contractual Obligations: Social obligation payments	300	300
Long-term Contractual Obligations: Social obligation payments	1,382	1,684
Block 20, offshore Angola
Contractual obligations
Short-term Contractual Obligations: Social obligation payments	48,569	48,569
Long-term Contractual Obligations: Social obligation payments	$ 122,851	$ 165,706

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Contractual Obligations

9 Months Ended

Sep. 30, 2013

Contractual Obligations

Contractual Obligations

9. Contractual Obligations

        The short-term and long-term contractual obligations consist of the following:

	September 30, 2013		December 31, 2012
	($ in thousands)
Short-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	150	$	150
Social obligation payments for Block 21, offshore Angola		300		300
Social obligation and bonus payments for Block 20, offshore Angola(1)		48,569		48,569
	$	49,019	$	49,019
Long-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	668	$	848
Social obligation payments for Block 21, offshore Angola		1,382		1,684
Social obligation and bonus payments for Block 20, offshore Angola(1)		122,851		165,706
	$	124,901	$	168,238

(1)

The total amount of social obligation payments for Block 20 has been capitalized. See Note 7—Property, Plant, and Equipment.

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Investments

9 Months Ended

Sep. 30, 2013

Investments

Investments

5. Investments

        The Company's investments in held-to-maturity securities which are recorded at amortized cost and approximate fair market value as of September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013		December 31, 2012
	($ in thousands)
U.S. Treasury securities	$	394,690	$	483,775
Corporate securities		936,183		510,691
Commercial paper		512,981		562,975
Certificates of deposit		70,000		7,000
Total	$	1,913,854	$	1,564,441

        The Company's condensed consolidated balance sheet included the following held-to-maturity securities:

	September 30, 2013		December 31, 2012
	($ in thousands)
Cash and cash equivalents	$	97,014	$	254,732
Short-term restricted funds		228,533		90,440
Short-term investments		1,221,552		789,668
Long-term restricted funds		166,158		393,334
Long-term investments		200,597		36,267
	$	1,913,854	$	1,564,441

        The contractual maturities of these held-to-maturity securities as of September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	($ in thousands)
Within 1 year	$	1,713,257	$	1,713,257	$	1,528,174	$	1,528,174
After 1 year		200,597		200,597		36,267		36,267
	$	1,913,854	$	1,913,854	$	1,564,441	$	1,564,441

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended		95 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013
Cash flows provided from operating activities
Net income (loss)	$ (366,905)	$ (216,468)	$ (1,294,740)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation and amortization	1,345	782	6,097
Dry hole expense and impairment of unproved properties	212,199	131,720	450,931
Gain on sale of assets	(2,993)		(2,993)
Equity based compensation	18,795	16,650	79,501
Amortization of premium (accretion of discount) on investments	17,043	13,269	51,584
Amortization of debt discount	34,751		36,500
Other			558
Changes in operating assets and liabilities:
Joint interest and other receivables	(48,218)	(32,171)	(113,413)
Inventory	(17,939)	(3,627)	(83,225)
Prepaid expense and other current assets	(2,482)	6,919	(26,423)
Deferred charges	(13,264)	2,769	(13,264)
Trade and other accounts payable	(57,459)	(53,892)	10,418
Accrued liabilities and other	(14,856)	(7,344)	22,018
Net cash provided by (used in) operating activities	(239,983)	(141,393)	(876,451)
Cash flows from investing activities
Capital expenditures for oil and gas properties	(80,439)	(130,719)	(927,387)
Capital expenditures for other property and equipment	(7,689)	(3,376)	(17,733)
Exploratory wells drilling in process	(356,764)	(228,299)	(956,846)
Proceeds from sale of oil and gas properties	3,006		342,007
Change in restricted funds	90,372	51,076	(221,710)
Proceeds from maturity of investment securities	1,003,020	768,230	3,602,074
Purchase of investment securities	(1,615,834)	(970,709)	(5,245,771)
Net cash provided by (used in) investing activities	(964,328)	(513,797)	(3,425,366)
Cash flows from financing activities
Capital contributions prior to IPO-Class A limited partners			1,256,180
Proceeds from initial public offering, net of costs			950,702
Proceeds from public offerings, net of costs		489,309	967,513
Proceeds from debt offering, net of costs	(1,190)		1,347,760
Proceeds from stock option exercises	198	275	536
Payments for common stock withheld for taxes on equity based compensation		(170)	(362)
Net cash provided by (used in) financing activities	(992)	489,414	4,522,329
Net increase (decrease) in cash and cash equivalents	(1,205,303)	(165,776)	220,512
Cash and cash equivalents, beginning of period	1,425,815	292,546
Cash and cash equivalents, end of period	220,512	126,770	220,512
Cash paid for interest	16,502		16,502
Non-Cash Disclosures
Changes in accrued capital expenditures	(92,534)	270,031	135,389
Transfer of investment securities to and from restricted funds	$ 26	$ 178,830	$ 178,804

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Cash and Cash Equivalents (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Cash and Cash Equivalents
Cash at banks	$ 34,001	$ 65,935
Money market funds	89,497	1,105,148
Held-to-maturity securities	97,014	254,732
Total	$ 220,512	$ 1,425,815	$ 126,770	$ 292,546
Maturity period of held-to-maturity securities	3 months	3 months

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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Information

Segment Information

12. Segment Information

        The Company currently has two geographic operating segments for its exploratory operations. The operating segments are focused in the deepwater U.S. Gulf of Mexico and offshore West Africa. The following tables provide the geographic operating segment information for the three and nine months ended September 30, 2013 and 2012:

	United States			West Africa			Total
	($ in thousands)
Three months ended September 30, 2013
Operating costs and expense	$	122,995		$	22,668		$	145,663
Operating income (loss)		(122,995	)		(22,668	)		(145,663	)
Other income (expense)								(14,337	)
Net income (loss)							$	(160,000	)
Additions to Property and Equipment, net(1)	$	1,329		$	148,262		$	149,591
Three months ended September 30, 2012
Operating costs and expense	$	(32,593	)	$	(7,960	)	$	(40,553	)
Operating income (loss)		(32,593	)		(7,960	)		(40,553	)
Other income (expense)								1,339
Net income (loss)							$	(39,214	)
Additions to Property and Equipment, net(1)	$	42,851		$	51,946		$	94,797

	United States			West Africa			Total
	($ in thousands)
Nine months ended September 30, 2013
Operating costs and expense	$	167,817		$	155,664		$	323,481
Operating income (loss)		(167,817	)		(155,664	)		(323,481	)
Other income (expense)								(43,424	)
Net income (loss)							$	(366,905	)
Additions to Property and Equipment, net(1)	$	93,657		$	230,212		$	323,869
Nine months ended September 30, 2012
Operating costs and expense	$	(189,171	)	$	(31,252	)	$	(220,423	)
Operating income (loss)		(189,171	)		(31,252	)		(220,423	)
Other income (expense)								3,955
Net income (loss)							$	(216,468	)
Additions to Property and Equipment, net(1)	$	(7,438	)	$	170,235		$	162,797

(1)

These amounts are net of accumulated allowance for impairment on oil and gas properties and accumulated depreciation and amortization on other property and equipment.

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Long-term Debt

9 Months Ended

Sep. 30, 2013

Long-term Debt

Long-term Debt

8. Long-term Debt

        On December 17, 2012, the Company issued $1.38 billion aggregate principal amount of its 2.625% convertible senior notes due 2019 (the "Notes"). The Notes are the Company's senior unsecured obligations and interest is payable semi-annually in arrears on June 1 and December 1 of each year. For the nine months ended September 30, 2013, the Company paid $16.5 million in interest on the notes. The Notes will mature on December 1, 2019, unless earlier repurchased or converted in accordance with the terms of the Notes. The Notes may be converted at the option of the holder at any time prior to 5:00 p.m., New York City time, on the second scheduled trading day immediately preceding the maturity date, in multiples of $1,000 principal amount. The Notes are convertible at an initial conversion rate of 28.023 shares of common stock per $1,000 principal amount, representing an initial conversion price of approximately $35.68 per share for a total of approximately 38.7 million underlying shares. The conversion rate is subject to adjustment upon the occurrence of

certain events, as defined in the indenture governing the Notes, but will not be adjusted for any accrued and unpaid interest except in limited circumstances. Upon conversion, the Company's conversion obligation may be satisfied, at the Company's option, in cash, shares of common stock or a combination of cash and shares of common stock.

        Holders of the Notes who convert their Notes in connection with a "make-whole fundamental change", as defined in the indenture governing the Notes, may be entitled to a make-whole premium in the form of an increase in the conversion rate. Additionally, in the event of a fundamental change, as defined in the indenture governing the Notes, holders of the Notes may require the Company to repurchase for cash all or a portion of their Notes equal to $1,000 or a multiple of $1,000 at a fundamental change repurchase price equal to 100% of the principal amount of Notes, plus accrued and unpaid interest, if any, to, but not including, the fundamental change repurchase date.

        Upon the occurrence of an Event of Default, as defined within the Indenture governing the Notes, the Trustee or the Holders of at least 25% in aggregate principal amount of the Notes then outstanding may declare 100% of the principal of, and accrued and unpaid interest on, all the Notes to be due and payable immediately.

        In accordance with accounting guidance relating to, "Debt with Conversion and Other Options", the Company separately accounts for the liability and equity conversion components of the Notes due to the Company's option to settle the conversion obligation in cash. The fair value of the debt excluding the conversion feature at the date of issuance was estimated to be approximately $989.5 million and was calculated based on the fair value of similar non-convertible debt instruments. The resulting value of the conversion option of $390.5 million was recognized as a debt discount and recorded as additional paid-in capital on the Company's consolidated balance sheets. Total debt issue cost on the Notes was $32.2 million of which $23.1 million was allocated to the liability component of the Notes and $9.1 million to the equity component of the Notes. The debt discount and the liability component of the debt issue costs are amortized over the term of the Notes. The effective interest rate used to amortize the debt discount and the liability component of the debt issue costs was approximately 8.40% based on the Company's estimated non-convertible borrowing rate as of the date the Notes were issued. Since the Company incurred losses for all periods, the impact of the conversion option would be anti-dilutive to the earnings per share and therefore was not included in the calculation.

        The carrying amounts of the liability components of the Notes were as follows:

	September 30, 2013							December 31, 2012
	Principal Amount		Unamortized discount(1)			Carrying Amount		Principal Amount		Unamortized discount			Carrying Amount
	($ in thousands)
Carrying amount of liability component
2.625% convertible senior notes	$	1,380,000	$	(355,555	)	$	1,024,445	$	1,380,000	$	(388,809	)	$	991,191

(1)

Unamortized discount will be amortized over the remaining life of the Notes which is 6.25 years.

        The carrying amounts of the equity components of the Notes were as follows:

	September 30, 2013			December 31, 2012
	($ in thousands)
Debt discount relating to value of conversion option	$	390,540		$	390,540
Debt issue costs		(9,124	)		(9,124	)
Total	$	381,416		$	381,416

        Fair Value    The fair value of the Notes excluding the conversion feature was $1,028.8 million and $989.5 million as of September 30, 2013 and December 31, 2012, respectively, and was calculated based on the fair value of similar non-convertible debt instruments (level 2) since an observable quoted price of the Notes or a similar asset or liability is not readily available.

        Interest expense was as follows:

									For the Period November 10, 2005 (Inception) through September 30, 2013
	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	($ in thousands)
Interest expense associated with accrued interest(1)	$	3,956	$	—	$	16,276	$	—	$	17,570
Interest expense associated with accretion of debt discount		11,307		—		33,254		—		35,165
Interest expense associated with amortization of debt issue costs		539		—		1,497		—		1,572
Total	$	15,802	$	—	$	51,027	$	—	$	54,307

(1)

The $4.0 million and $16.3 million for the three and nine months ended September 30, 2013, respectively, represent interest expense net of capitalized amount of $5.1 million and $10.9 million, respectively.

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Cash and Cash Equivalents (Tables)

9 Months Ended

Sep. 30, 2013

Cash and Cash Equivalents

Cash and cash equivalents

	September 30, 2013		December 31, 2012
	($ in thousands)
Cash at banks	$	34,001	$	65,935
Money market funds		89,497		1,105,148
Held-to-maturity securities(1)		97,014		254,732
	$	220,512	$	1,425,815

(1)

These securities mature three months or less from the date of purchase.

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Contingencies

9 Months Ended

Sep. 30, 2013

Contingencies

Contingencies

13. Contingencies

        The Company is not currently party to any legal proceedings. However, from time to time the Company may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. It is not presently possible to determine whether any such matters will have a material adverse effect on the Company's consolidated financial position, results of operations, or liquidity.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013
Document and Entity Information
Entity Registrant Name	Cobalt International Energy, Inc.
Entity Central Index Key	0001471261
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	411,288,613
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2013

Summary of Significant Accounting Policies

Basis of Presentation

Basis of Presentation

        The accompanying unaudited condensed consolidated financial statements include the financial statements of Cobalt International Energy, Inc. and all of its wholly-owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. Because the Company is a development stage enterprise, it has presented its financial statements in accordance with accounting guidance related to "Development Stage Entities."

        The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles ("GAAP") for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission ("SEC"). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for interim periods are not necessarily indicative of the results that may be presented for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company's Annual Report on Form 10-K for the year ended December 31, 2012.

Reclassifications

Reclassifications

        Certain reclassifications have been made to prior periods' financial statements to conform to the current presentation in the unaudited condensed consolidated statements of cash flows.

Use of Estimates

Use of Estimates

        The preparation of financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by the Company include (i) accruals related to expenses, (ii) assumptions used in estimating fair value of equity based awards and the fair value of the liability component of the convertible senior notes and (iii) assumptions used in impairment testing. Although the Company believes these estimates are reasonable, actual results could differ from these estimates.

Investments

Investments

        The Company's policy on accounting for its investments, which consist entirely of debt securities, is based on the accounting guidance relating to "Accounting for Certain Investments in Debt and Equity Securities." The Company considers all highly liquid interest-earning investments with a maturity of three months or less at the date of purchase to be cash equivalents. Investments with original maturities of greater than three months and remaining maturities of less than one year are classified as short-term investments. Investments with maturities beyond one year are classified as long-term investments. The debt securities are carried at amortized costs and classified as held-to-maturity securities as the Company has the positive intent and ability to hold them until they mature. The net carrying value of held-to-maturity securities is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the securities. Held-to-maturity securities are stated at amortized cost, which approximates fair market value as of September 30, 2013 and December 31, 2012. Income related to these securities is reported as a component of interest income in the Company's condensed consolidated statement of operations. See Note 5—Investments.

        Investments are considered to be impaired when a decline in fair value is determined to be other-than-temporary. The Company conducts a regular assessment of its debt securities with unrealized losses to determine whether securities have other-than-temporary impairment ("OTTI"). This assessment considers, among other factors, the nature of the securities, credit rating or financial condition of the issuer, the extent and duration of the unrealized loss, market conditions and whether the Company intends to sell or whether it is more likely than not that the Company will be required to sell the debt securities. As of September 30, 2013 and December 31, 2012, the Company has no OTTI in its debt securities.

Capitalized Interest

Capitalized Interest

        For exploration and development projects that have not commenced production, interest is capitalized as part of the historical cost of developing and constructing assets. Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. See Note 7—Property, Plant, and Equipment and Note 8—Long-term Debt.

Earnings (Loss) Per Share

Earnings (Loss) Per Share

        Basic income (loss) per share was calculated by dividing net income or loss applicable to common shares by the weighted average number of common shares outstanding during the periods presented. The calculation of diluted income (loss) per share should include the potential dilutive impact of non-vested restricted shares, non-vested restricted stock units, outstanding stock options and 2.625% convertible senior notes due 2019, during the period, unless their effect is anti-dilutive. For the three months and nine months ended September 30, 2013, 6,744,278 shares of non-vested restricted stock, non-vested restricted stock units, outstanding stock options and 2.625% convertible senior notes due 2019, were excluded from the diluted income (loss) per share because they are anti-dilutive. For the three months and nine months ended September 30, 2012, 5,594,092 shares of non-vested restricted stock, non-vested restricted stock units and outstanding stock options were excluded from the diluted income (loss) per share because they are anti-dilutive.