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

Form 10-K

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
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, TX 77024 (Address of principal executive offices, including zip code)

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

         Securities registered pursuant to Section 12(b) of the Securities Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common stock, $0.01 par value	The New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Securities Act: None

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

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

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

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 Securities Act). Yes o    No ý

         As of June 30, 2012, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the registrant's common stock held by non-affiliates was approximately $4.3 billion.

         As of December 31, 2012, the registrant had 410,635,097 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's proxy statement relating to the 2013 Annual Meeting of Shareholders, to be filed within 120 days of the end of the fiscal year covered by this report, are incorporated by reference into Part III of this Annual Report on Form 10-K.

Cobalt International Energy, Inc.

Item No.		Page No.
	PART I
1	Business		3
1A	Risk Factors		42
1B	Unresolved Staff Comments		62
2	Properties		62
3	Legal Proceedings		62
4	Mine Safety Disclosures		62
	PART II
5	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		63
6	Selected Financial Data		64
7	Management's Discussion and Analysis of Financial Condition and Results of Operations		67
7A	Quantitative and Qualitative Disclosures About Market Risk		81
8	Financial Statements and Supplementary Data		82
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		82
9A	Controls and Procedures		82
9B	Other Information		83
	PART III
10	Directors, Executive Officers and Corporate Governance		84
11	Executive Compensation		84
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		84
13	Certain Relationships and Related Transactions, and Director Independence		84
14	Principal Accountant Fees and Services		84
	Glossary of Selected Oil and Gas Terms		84
	PART IV
15	Exhibits and Financial Statement Schedules		89
	Signatures		94

PART I

Cautionary Note Regarding Forward-Looking Statements

        This Annual Report on Form 10-K contains estimates and forward-looking statements, principally in "Business," "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 this Annual Report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this Annual Report on Form 10-K 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:

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the discovery and development of oil and gas reserves;

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

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the timing and success of our appraisal and development activities;

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projected and targeted capital expenditures and other costs and commitments;

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

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

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

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our ability to obtain financing;

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

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

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

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

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

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competition;

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the volatility of oil prices;

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

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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;

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

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military operations, terrorist acts, wars or embargoes;

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

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the cost and availability of adequate insurance coverage; and

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other risk factors discussed in the "Risk Factors" section of this Annual Report on Form 10-K.

        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 Annual Report on Form 10-K 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.

Item 1.    Business

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 both the U.S. Gulf of Mexico at North Platte, Heidelberg and Shenandoah and offshore Angola at Cameia. Our plan is to continue to mature and drill what we believe are our most promising 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.

U.S. Gulf of Mexico Segment

Overview

        Our oil-focused exploration efforts target subsalt Miocene and Inboard Lower Tertiary horizons in the deepwater U.S. Gulf of Mexico. To date, we have drilled as operator four exploratory wells in the deepwater U.S. Gulf of Mexico (North Platte #1, Ligurian #1 and #2, and Criollo #1) and participated as a non-operator in three exploratory wells (Heidelberg #1, Shenandoah #1 and Firefox #1) and three appraisal wells (Heidelberg #2, Heidelberg #3, and Shenandoah #2R). These drilling efforts have resulted in the North Platte, Heidelberg and Shenandoah oil discoveries. We are currently drilling as operator the Ardennes #1 exploratory well.

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        The following sections detail our U.S. Gulf of Mexico business:

Geologic Overview	Page 4
Prospect Identification and Lease Acquisition	Page 5
Prospects and Plans for Exploration	Page 6
Plans for Appraisal	Page 7
Discoveries and Plans for Development	Page 8
Drilling Rigs	Page 11
Prior Drilling Results and Drilling Statistics	Page 11
Strategic Relationships	Page 13

Geologic Overview

        Deepwater U.S. Gulf of Mexico exploration plays rely on hydrocarbons generated from several rich oil-prone source rocks. Rivers draining the North American continent provided vast quantities of sand, silt and mud to the Gulf of Mexico through major deltas similar to the present-day Mississippi and Rio Grande deltas. Sandstone reservoirs in two main geological formations, the Miocene and Inboard Lower Tertiary horizons, were ultimately transported and deposited into mini-basins and on the paleo-basin floor. Hydrocarbon seals are provided by salts and the muds integral to the depositional system.

        One of the most important aspects of the deepwater U.S. Gulf of Mexico is the presence of salt. Deposited early in the basin's history, salt is key to both the region's complexity and its longevity as an exploration province. The upward movement of salt, through the surrounding rock, formed most of the structures in the present-day deepwater U.S. Gulf of Mexico. The interaction of sediment load and salt movement partitioned the hydrocarbons into numerous moderate-size accumulations rather than just a few super-giant fields.

        Much of the deepwater province is covered by a salt canopy, which has historically prevented the oil and gas industry from effectively exploring the region's potential. This region has garnered additional interest from the industry with advances in seismic technology, which has provided clearer imaging beneath the salt canopy. Regional geologic reconstructions postulated the presence of mature source rock, reservoir, and trapping configurations in the subsalt region, but only since the advent of 3-D depth-migrated seismic data have geoscientists been able to identify exploration prospects beneath the extensive salt canopy. Our oil-focused exploration efforts primarily target subsalt Miocene and Inboard Lower Tertiary horizons in the deepwater U.S. Gulf of Mexico. These horizons are characterized by well-defined hydrocarbon systems, comprised primarily of high-quality source rock and crude oil, and contain several of the most significant hydrocarbon discoveries in the deepwater U.S. Gulf of Mexico.

        Miocene.    The subsalt Miocene trend is an established play in the deepwater U.S. Gulf of Mexico. Discoveries in this trend include Heidelberg, Thunder Horse, Atlantis, Tahiti, Mad Dog, and Knotty Head. This trend is characterized by high quality reservoirs and fluid properties, resulting in high production well rates and recovery factors. We believe the primary geologic risk in this trend is the seal capacity required to trap hydrocarbons. To address this risk, we have conducted extensive regional studies, including proprietary seismic processing, proprietary pore pressure modeling, as well as other geological and geophysical predictive techniques, to better define the seal capacity for each prospect in the trend.

        Inboard Lower Tertiary.    The Lower Tertiary horizon is an older formation than the Miocene, and, as such, is generally deeper, with greater geologic complexity, than the Miocene play. Although to date there has been limited commercial production from the Lower Tertiary horizon, the industry has been successful in terms of locating and drilling large hydrocarbon-bearing structures in this horizon. The reservoir quality of the Lower Tertiary has proven to be highly variable. Some regions, including those

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areas in which many of the historical Lower Tertiary discoveries have been made, exhibit lower permeability and generally lower natural gas content compared to the Miocene horizon.

        However, a sub-region in the Lower Tertiary that has exhibited reservoir characteristics more similar to that of existing Miocene discoveries is the Inboard Lower Tertiary trend, which includes our North Platte and Shenandoah discoveries. The Inboard Lower Tertiary is an emerging trend located to the northwest of existing Outboard Lower Tertiary fields such as St. Malo, Jack and Cascade. We were an early mover in the Inboard Lower Tertiary trend, targeting specific lease blocks as early as 2006. We believe our Inboard Lower Tertiary blocks are characterized by large, well-defined structures of a similar size to historic Outboard Lower Tertiary discoveries, but are differentiated by what we believe to be better reservoir quality. Our technical team's hypothesis regarding the region's potentially higher-quality reservoir properties was supported by our North Platte and Shenandoah discoveries. We believe we hold a significant leasehold position in the emerging Inboard Lower Tertiary.

Prospect Identification and Lease Acquisition

        Our business model in the deepwater U.S. Gulf of Mexico begins with prospect identification and lease acquisition. Our approach is based on a thorough, basin-wide understanding of the geologic trends within our focus areas. From our inception, we have been focused on acquiring and reprocessing the highest quality seismic data available, including the application of advanced imaging technology, such as wide-azimuth seismic. This approach differs considerably from often-followed industry practice of acquiring more narrowly focused, prospect-specific data on a block-by-block basis. In the deepwater U.S. Gulf of Mexico, we have licenses covering approximately 18.3 million acres (74,000 square kilometers) of processed 3-D depth-migrated seismic data and approximately 2.8 million acres (11,400 square kilometers) of wide-azimuth 3-D depth data. In addition, we have performed proprietary reprocessing on approximately 4.2 million acres (17,000 square kilometers) of 3-D seismic data to enhance image quality and velocity model confidence. Our proprietary seismic reprocessing was performed by third-party geophysical providers using leading-edge technologies, including reverse time migration algorithms for pre-stack depth migration and 3-D surface related multiple elimination (SRME) for multiple attenuation. We also have licensed approximately 78,000 line miles (125,530 kilometers) of 2-D pre-stack depth-migrated seismic data in the deepwater U.S. Gulf of Mexico.

        Our approach to data acquisition entails analyzing regional data, including industry well results, to understand a given trend's specific geology and defining those areas that offer the highest potential for large hydrocarbon deposits. After these areas are identified, we seek to acquire and reprocess the highest resolution subsurface data available in the potential prospect's direct vicinity. This includes advanced imaging information, such as wide-azimuth studies, to further our understanding of a particular reservoir's characteristics, including both trapping mechanics and fluid migration patterns. Reprocessing is accomplished through a series of model building steps that incorporate the geometry of the salt and below salt geology to optimize the final image. In addition, we gather publicly available information, such as well logs, press releases and industry intelligence, which we use to evaluate industry results and activities in order to understand the relationships between industry-drilled prospects and our portfolio of undrilled prospects.

        Once a prospect is identified and analyzed, we may seek to acquire leasehold title to the related lease blocks. Leasehold acquisition occurs from one of two sources: from the U.S. government through lease sales or from other oil and gas companies through direct purchases, trades or farm-in arrangements. The leasehold acquisition provides us with title to specific blocks that we believe includes the entire prospect or a portion thereof.

        As of December 31, 2012, we owned working interests in 246 blocks within the deepwater U.S. Gulf of Mexico, representing approximately 1.4 million gross (0.7 million net) undeveloped acres. We do not currently own any developed acreage in the deepwater U.S. Gulf of Mexico as development

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plans for Heidelberg, Shenandoah and North Platte are not yet sanctioned and therefore the acreage associated with those discoveries remains classified as undeveloped. We currently estimate that the North Platte prospect covers leases representing 34,560 gross (20,736 net) acres, the Heidelberg prospect covers leases representing 17,280 gross (1,620 net) acres, and the Shenandoah prospect covers leases representing 12,960 gross (2,650 net) acres. If development projects related to our North Platte, Heidelberg and Shenandoah discoveries are sanctioned, we will evaluate which acreage associated with these prospects could then be classified as developed acreage.

        Most of our U.S. Gulf of Mexico blocks have a 10-year primary term, expiring between 2016 and 2022. Assuming we are able to commence exploration and production activities or successfully exploit our properties during the primary lease term, our leases would extend beyond the primary term, generally for the life of production. The royalties on our lease blocks range from 12.5% to 18.75% with an average of 15.6%.

        The table below summarizes our undeveloped acreage scheduled to expire in the next five years in the U.S. Gulf of Mexico.

	Undeveloped Acres Expiring
	2013(1)				2014(2)				2015(1)				2016(3)				2017 and thereafter(2)(3)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
U.S. Gulf of Mexico		57,600		13,680		168,480		85,996		69,120		26,287		345,600		198,538		768,710		370,568

(1)

The gross and net acreage numbers reflected in these columns include portions of the 17,280 gross (1,620 net) acres covering our Heidelberg prospect, upon which exploratory and appraisal wells have discovered hydrocarbons, but a development project has not yet been sanctioned. One of the leases covering our Heidelberg prospect, Green Canyon Block 860, which covers 5,760 gross (540 net) acres, had a primary term that was due to expire on May 31, 2012, but is held by a Suspension of Production. We expect that the operator of the Heidelberg prospect will file an additional Suspension of Production in order to retain the remaining acreage associated with the Heidelberg prospect and avoid leasehold expiration.

(2)

The gross and net acreage numbers reflected in these columns include portions of the 12,960 gross (2,650 net) acres covering our Shenandoah prospect, upon which an exploratory and appraisal well have both discovered hydrocarbons, but a development project has not yet been sanctioned. We expect that the operator of the Shenandoah prospect will file a Suspension of Production in order to retain the acreage associated with the Shenandoah prospect and avoid leasehold expiration.

(3)

The gross and net acreage numbers reflected in these columns include portions of the 34,560 gross (20,736 net) acres covering our North Platte prospect, upon which an exploratory well has discovered hydrocarbons, but a development project has not yet been sanctioned.

        Although we have been primarily focused during the last several years on maturing and conducting exploratory and appraisal operations on our existing prospects on leases we had already acquired, we intend to continue our prospect identification and lease acquisitions efforts in the deepwater U.S. Gulf of Mexico and, in the future, potentially elsewhere in the world so that we can continue to identify additional value creation opportunities.

Prospects and Plans for Exploration

        As a result of our prospect identification process and lease acquisition efforts, we currently have an extensive below salt prospect inventory in the deepwater U.S. Gulf of Mexico. This inventory includes dozens of prospects in various states of maturation in both our Miocene and Inboard Lower Tertiary trends. The initial well drilled to test a prospect is referred to as an exploratory well. We estimate that the average gross cost to drill and evaluate an exploratory well would be approximately $160 to $180 million for Miocene prospects and approximately $190 to $220 million for Inboard Lower Tertiary prospects. See "Risk Factors—Risks Relating to Our Business—Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business."

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        Our near term exploration plans call for the following exploratory wells to be drilled:

        Ardennes #1.    We spud the Ardennes #1 exploratory well on February 6, 2013. The Ardennes #1 exploratory well will target a 3-way structure located in both Miocene and Inboard Lower Tertiary horizons located in Green Canyon blocks 895, 896 and 939, where we are the named operator and own a 42% working interest. Ardennes was mapped using our processed, pre-stack, depth-migrated, narrow-azimuth 3-D seismic data and, most recently, proprietary, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. Our partners in the Ardennes prospect include ConocoPhillips Company (30%) and TOTAL E&P USA, INC. ("Total") (28%).

        Aegean #1.    We expect to spud the Aegean #1 exploratory well after our Ardennes #1 exploratory well. The Aegean #1 exploratory well will target a 3-way structure in Inboard Lower Tertiary horizons located in Keathley Canyon blocks 162, 163 and 207, where we are the named operator and currently own a 37.5% working interest. Aegean was mapped using proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. Our partners in the Aegean prospect include Shell Offshore, Inc. (37.5%) and Total (25%). Prior to spudding the Aegean #1 exploratory well, the composition and working interests of the Aegean partnership may change.

        Rum Ramsey #1.    We expect to participate as a non-operator in the Rum Ramsey #1 exploratory well, which will target Miocene horizons. Currently, we have a 24% working interest in the Rum Ramsey prospect and our partners include BHP Billiton Petroleum (Americas) Inc. (60%) and Total (16%). Prior to spudding the Rum Ramsey #1 exploratory well, the composition and working interests of the Rum Ramsey partnership may change as part of a proposed unitization plan.

        Racer #1.    We expect to participate as a non-operator in the Racer #1 exploratory well, which will target Miocene and Inboard Lower Tertiary horizons. Currently, we have a 24% working interest in the Racer prospect and our partners include BHP Billiton Petroleum (Americas) Inc. (60%) and Total (16%). Prior to spudding the Racer #1 exploratory well, the composition and working interests of the Racer partnership may change as part of a proposed unitization plan.

        South Platte #1.    We expect to spud the South Platte #1 exploratory well during 2014. South Platte is a 3-way prospect targeting Inboard Lower Tertiary horizons located in Garden Banks blocks 1003 and 1004 and Keathley Canyon blocks 35 and 36, where we are the named operator and own a 60% working interest. South Platte was mapped using our proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. Our partner in the South Platte prospect is Total (40%).

        Baffin Bay #1.    We expect to spud the Baffin Bay #1 exploratory well during 2014. Baffin Bay is a 4-way prospect targeting Inboard Lower Tertiary horizons located in Garden Banks blocks 956 and 957, where we are the named operator and own a 60% working interest. Baffin Bay was mapped using our proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. Our partner in the Baffin Bay prospect is Total (40%).

        In addition, we plan to continue maturing our prospects at Latvian, Williams Fork, Goodfellow, El Ciervo, Fraser, Mulashidi, Kashmir, Percheron, Rocky Mountain, Saddelbred and Sulu. See "Risk Factors—Risks Relating to Our Business—Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling."

Plans for Appraisal

        Following a successful exploratory well on a prospect, the operator may choose to drill one or more appraisal wells to delineate the size and other characteristics of the discovered field, including the areal extent of the field. The drilling of an appraisal well is an important step in the process of being able to determine whether a development of a discovered field would be economic. We estimate that

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the average gross cost to drill and evaluate an appraisal well will be approximately $140 to $170 million for Miocene prospects and approximately $180 to $210 million for Inboard Lower Tertiary prospects. Our near term appraisal plans call for the drilling of the North Platte #2 appraisal well in 2014. In addition to the drilling of appraisal wells, other elements of our appraisal work may include the evaluation and analysis of well logs, reservoir core samples, fluid samples and the results of production tests from both exploratory and appraisal wells. See "Risk Factors—Risks Relating to Our Business—Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business."

Discoveries and Plans for Development

        The information obtained from the drilling of exploratory and appraisal wells is used to create a development plan, which may include the construction of offshore facilities and drilling of development wells designed to efficiently produce and optimize recovery of hydrocarbons from the field. Any oil resources, if developed, would be produced using either newly constructed processing facilities owned by the working-interest partnership, which would be a capital expense, or processing facilities leased from third-party providers, which would be an operating expense. In general, we expect our development wells will be produced through subsea templates tied back to the processing facilities. We estimate that the average gross cost to drill and complete a development well would be approximately $140 to $170 million for Miocene fields and approximately $180 to $210 million for Inboard Lower Tertiary fields. In addition to the drilling and completion costs associated with development wells, we also expect to incur substantial costs associated with the design, construction and installation of subsea, umbilical, riser and flowline systems.

        A discovery made by the initial exploratory well on a prospect does not ensure that we will ultimately develop or produce oil or gas from such prospect or that a development will be economically viable or successful. Following a discovery by an initial exploratory well, substantial additional evaluation and analysis will need to be performed prior to official project sanction and development, which may include (i) the drilling of appraisal wells, (ii) the evaluation and analysis of well logs, reservoir core samples, fluid samples and the results of production tests from both exploratory and appraisal wells, and (iii) the preparation of a development plan which includes economic assumptions on the costs of drilling development wells, and the construction or leasing of offshore production facilities and transportation infrastructure. Regulatory approvals are also required to proceed with certain development plans. Any of the foregoing steps of evaluation and analysis may render a particular discovery uneconomic and we may ultimately decide to abandon the prospect, despite the fact that the initial exploratory well, or subsequent appraisal wells, discovered hydrocarbons. See "Risk Factors—Risks Relating to Our Business—Our discoveries remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and development."

        North Platte Discovery.    On December 5, 2012, we announced a significant oil discovery at our North Platte prospect on Garden Banks block 959 in the deepwater U.S. Gulf of Mexico. The North Platte #1 exploratory well represents the first discovery in our deepwater U.S. Gulf of Mexico alliance with Total. Based on extensive wireline evaluation, the discovery well encountered several hundred feet of net oil pay in multiple Inboard Lower Tertiary sands. This discovery is particularly important because it provides evidence to support our geologic model of the Inboard Lower Tertiary trend where we hold a substantial acreage position with several follow-on prospects, such as Ardennes, South Platte, Baffin Bay, Latvian and Aegean. We have conducted bypass coring on our North Platte #1 exploratory well, which has provided us with additional information we will use as we continue our evaluation of the North Platte discovery and plans for appraisal. We are currently in the early stages of the appraisal and development process on North Platte and will continue to review the data obtained from the North

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Platte #1 exploratory well as we formulate appraisal drilling plans and begin to evaluate potential development options. The North Platte discovery will require substantial additional evaluation and analysis, including appraisal drilling, prior to preparing a development plan and seeking formal project sanction. We currently anticipate spudding an appraisal well on our North Platte discovery in 2014. The North Platte #1 exploratory well is located in approximately 4,400 feet of water and was drilled to a total depth of approximately 34,500 feet. We are the operator of North Platte and own a 60% working interest. Total is our partner in this discovery and owns a 40% working interest.

        Shenandoah Discovery.    On February 4, 2009, we announced that the Shenandoah #1 exploratory well had been drilled into Inboard Lower Tertiary horizons and encountered approximately 300 feet of net pay. This well, located in approximately 5,750 feet of water in Walker Ridge block 52, was drilled to approximately 30,000 feet. The Shenandoah #2R appraisal well, located in Walker Ridge block 51, was spud in the third quarter of 2012 and was drilled to a total depth of 31,400 feet in approximately 5,800 feet of water and 1.3 miles southwest of the Shenandoah #1 exploratory well. While evaluation operations are still ongoing, wireline evaluation results from Shenandoah #2R are very encouraging. We own a 20% working interest in this discovery and Anadarko Petroleum Corporation ("Anadarko") is the operator. Anadarko has publicly indicated that it expects first production from the Shenandoah field in 2017.

        Heidelberg Discovery.    On February 2, 2009, we announced that the Heidelberg #1 exploratory well had encountered more than 200 feet of net pay thickness in Miocene horizons. Located in approximately 5,200 feet of water in Green Canyon block 859 within the Tahiti Basin Miocene trend, this well was drilled to approximately 30,000 feet. We participated as a non-operator in the Heidelberg #3 appraisal well which was spud in late 2011 in Green Canyon block 903. On February 16, 2012, Anadarko, as operator, announced the successful results of the well, which encountered approximately 250 feet of net pay thickness in high-quality Miocene sands. The appraisal well was drilled to a total depth of 31,030 feet in approximately 5,000 feet of water, about 1.5 miles south and 550 feet structurally up-dip from the Heidelberg #1 exploratory well. Log and pressure data from the Heidelberg #1 exploratory well and Heidelberg #3 appraisal well indicate excellent quality, continuous and pressure-connected reservoirs with high-quality oil. On April 19, 2012, Anadarko announced that a sidetrack well performed on the Heidelberg #3 appraisal well successfully confirmed an extension of the Heidelberg field of up to 1,500 acres by encountering an oil/water contact that was approximately 700 feet down structure. We own a 9.375% working interest in the Heidelberg discovery.

        We, in cooperation with Anadarko, as operator, and our other partners on the Heidelberg discovery, are continuing to advance plans to develop the Heidelberg field following the successful appraisal well. Key contractors to build the production platform and facilities necessary to enable production from the Heidelberg discovery have been identified and the final design has been completed. Negotiations with respect to gas gathering, transportation, and processing agreements have concluded and these agreements have been signed. Negotiations with respect to oil transportation are being finalized and we expect agreements to be signed in the near future. Anadarko has received a Suspension of Production with the Bureau of Safety and Environmental Enforcement (BSEE) in order to hold the applicable leases while the Heidelberg field is being developed. A list of activities which demonstrates that we and our partners are actively pursuing field development at Heidelberg was filed with the suspension application. As part of this suspension application, Anadarko has forecast the ordering of critical long lead equipment to support the timely progress of this discovery to first production. We are supporting Anadarko in this effort and, to date, we and our partners have authorized in excess of $400 million (gross) in expenditures at Heidelberg for the purchase of forecasted long lead equipment and the initial design of development facilities. In addition, Anadarko submitted its Heidelberg field development plan to us and the other Heidelberg partners in the fourth quarter of 2012 and began fabrication of the spar hull. The Heidelberg production facility is being designed to produce 80,000 barrels of oil per day ("BOPD"). Anadarko has publicly indicated that it

9

expects to seek formal project sanction in mid-2013 and anticipates first production from the Heidelberg field in 2016.

EXPLORATION TO PRODUCTION BUSINESS MODEL

MATURING PROSPECTS	EXPLORATION WELLS	APPRAISAL	PRE-PRODUCTION(1)
Latvian(2)	Ardennes #1(2)	North Platte(2)	Heidelberg
Williams Fork(2)	Aegean #1(2)	Shenandoah(2)
Goodfellow(2)	Rum Ramsey #1
El Ciervo(2)	Racer #1(2)
Fraser(2)	South Platte #1(2)
Mulashidi(2)	Baffin Bay #1(2)
Kashmir(2)
Percheron(2)
Rocky Mountain
Saddelbred
Sulu

(1)

Discoveries that we classify as being in a "pre-production" phase are those in which successful exploration and appraisal wells have been drilled and we, in cooperation with any partners on the applicable discovery, are continuing to advance plans to develop the field. Substantial additional evaluation and analysis may need to be performed prior to official project sanction and development, which includes the preparation of a development plan containing economic assumptions on the costs of drilling development wells, and the construction or leasing of offshore production facilities and transportation infrastructure. Such evaluation and analysis may render a particular discovery uneconomic and we may ultimately decide to abandon the prospect, despite the fact that we currently classify the discovery as being in "pre-production." See "Risk Factors—Risks Relating to Our Business—Our discoveries remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and development."

(2)

Inboard Lower Tertiary fields or prospects.

        The map below shows our deepwater U.S. Gulf of Mexico prospects, near-term exploratory wells, and discoveries in appraisal and pre-production.

10

Drilling Rigs

        We have one drilling rig, the Ensco 8503, that is currently performing drilling operations on our operated prospect portfolio in the deepwater U.S. Gulf of Mexico. Our contract for the Ensco 8503 drilling rig has a two year term that commenced on January 1, 2012 and provides for a base operating rate of $510,000 per day, subject to adjustment. We expect to utilize the Ensco 8503 drilling rig continuously throughout 2013 to support our operated deepwater U.S. Gulf of Mexico drilling campaign, including the completion of drilling operations on our Ardennes #1 exploratory well and at least one additional well in 2013. In order to secure additional rig capacity beyond year end 2013, we plan to begin negotiations to either extend the drilling contract for the Ensco 8503 beyond 2013 or source another drilling rig. We may choose to both extend the Ensco 8503 and source an additional drilling rig to support our operated drilling campaign beyond 2013.

Prior Drilling Results and Drilling Statistics

        The results of each of the wells we have drilled as operator or participated in as a non-operator in the deepwater U.S. Gulf of Mexico since our formation are listed below.

        North Platte #1.    On December 5, 2012, we announced a significant oil discovery at our North Platte prospect on Garden Banks block 959 in the deepwater U.S. Gulf of Mexico. Based on extensive wireline evaluation, the discovery well encountered several hundred feet of net oil pay in multiple Inboard Lower Tertiary sands. The North Platte #1 exploratory well is located in approximately 4,400 feet of water and was drilled to a total depth of approximately 34,500 feet. We are the operator of North Platte and own a 60% working interest. Total is our partner in this discovery and owns a 40% working interest. See "—Discoveries and Plans for Development—North Platte Discovery."

        Heidelberg #1, #2 and #3.    On February 2, 2009, we announced that the Heidelberg #1 exploratory well had encountered more than 200 feet of net pay thickness in Miocene horizons. Located in approximately 5,200 feet of water in Green Canyon block 859 within the Tahiti Basin Miocene trend, this well was drilled to approximately 30,000 feet. Anadarko operates the block and we own a 9.375% working interest. On February 17, 2010, the Heidelberg #2 appraisal well was spud by Anadarko in approximately 5,300 feet of water in Green Canyon block 903. On April 29, 2010, we announced that Anadarko had notified us that Heidelberg #2 would be permanently plugged and abandoned due to mechanical problems. Heidelberg #2 did not reach the depth necessary to test any targeted objectives because of these mechanical problems. The Heidelberg #3 appraisal well was spud in late 2011, thereby resuming the Heidelberg appraisal drilling program. On February 16, 2012, Anadarko announced the successful results of the well, which encountered approximately 250 feet of net pay thickness in high-quality Miocene sands. The appraisal well was drilled to a total depth of 31,030 feet in approximately 5,000 feet of water, about 1.5 miles south and 550 feet structurally up-dip from the Heidelberg #1 exploratory well. Log and pressure data from the Heidelberg #1 exploratory well and Heidelberg #3 appraisal well indicate excellent quality, continuous and pressure-connected reservoirs with high-quality oil. On April 19, 2012, Anadarko announced that a sidetrack well performed on the Heidelberg #3 appraisal well successfully confirmed an extension of the Heidelberg field of up to 1,500 acres by encountering an oil/water contact that was approximately 700 feet down structure. See "—Discoveries and Plans for Development—Heidelberg Discovery."

        Shenandoah #1 and #2R.    On February 4, 2009, we announced that the Shenandoah #1 exploratory well had been drilled into Inboard Lower Tertiary horizons. Anadarko has stated that this well encountered approximately 300 feet of net pay. This well, located in approximately 5,750 feet of water in Walker Ridge block 52, was drilled to approximately 30,000 feet and exhibited rock properties that were more similar to those found in Miocene horizons rather than Lower Tertiary horizons. We own a 20% working interest in this prospect. During the third quarter, the Shenandoah #2 appraisal well encountered mechanical problems early in the drilling process prior to reaching any of the targeted horizons and was re-drilled, which we refer to as the Shenandoah #2R appraisal well. On February 26, 2013, we announced that the Shenandoah #2R appraisal well had been drilled to a total depth of

11

31,400 feet in approximately 5,800 feet of water and 1.3 miles southwest of the Shenandoah #1 exploratory well. While evaluation operations are still ongoing, wireline evaluation results from Shenandoah #2R are very encouraging. See "—Discoveries and Plans for Development—Shenandoah Discovery."

        Ligurian #1 and #2.    On July 16, 2009, we spud Ligurian #1 on Green Canyon block 858 to target upper- and middle-Miocene horizons. On October 28, 2009, we and our partners decided to cease drilling operations on Ligurian #1 having encountered operational difficulties when drilling below salt through an unforeseen geologic formation before reaching total depth or drilling to the targeted horizons. On January 1, 2012, we spud the Ligurian #2 exploratory well on Green Canyon block 814 in the deepwater U.S. Gulf of Mexico. The Ligurian #2 exploratory well was designed to test the northwest flank of the field discovered by the Heidelberg #1 exploratory well and to evaluate deeper Miocene formations. On June 12, 2012, we announced that our Ligurian #2 exploratory well had reached total objective depth after having drilled through all the targeted Miocene formations. The well did not encounter commercial hydrocarbons and it was subsequently plugged and abandoned. We are the named operator and own a 45% working interest in the Ligurian prospect.

        Criollo #1.    On January 29, 2010, we announced that we had reached a planned total depth of approximately 31,000 feet in the Criollo exploratory sidetrack well located in approximately 4,200 feet of water in Green Canyon block 685 within the Tahiti Basin Miocene trend. The original well encountered 55 feet of net pay thickness in Miocene horizons and the sidetrack encountered 73 feet of net pay thickness in correlative reservoirs. Both the original well and the sidetrack encountered structural complexities associated with salt, which prevented the drilling of the entire target interval. We refer to the sidetrack well and the original well as the Criollo #1 exploratory well. We own a 60% working interest in this prospect.

        Firefox #1.    On February 10, 2010, the Firefox #1 exploratory well was spud by its operator in approximately 4,400 feet of water in Green Canyon block 817 within the Tahiti Basin Miocene trend and approximately six miles northeast of the Heidelberg discovery. On May 6, 2010, we announced that the Firefox #1 exploratory well would be plugged and abandoned, having been drilled to approximately 34,000 feet. Based on the well results, we believe that undrilled potential lies below the total depth reached on the Firefox #1 exploratory well. We have named this prospect Firefox Deep. We own a 30% working interest in this prospect.

        The following table sets forth information with respect to the gross and net oil and gas wells we drilled in the deepwater U.S. Gulf of Mexico during the periods indicated. The information presented is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of any reserves found. Productive wells include wells that have been drilled to the targeted depth and prove, in our opinion, to be capable of producing either oil or gas in sufficient quantities that will justify completion as an oil or gas well. A dry well is an exploratory, appraisal or development well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

	U.S. Gulf of Mexico
	2012(2)				2011				2010(3)
Wells Drilled	Gross		Net		Gross		Net		Gross		Net
Exploratory(1)
Productive		1		0.6		—		—		—		—
Dry		1		0.45		—		—		2		0.9
Total		2		1.05		—		—		2		0.9

(1)

We did not drill any development wells in the U.S. Gulf of Mexico during the fiscal years ended December 31, 2012, 2011 and 2010, respectively. The numbers in this table do not reflect the results of our Heidelberg #2 and Heidelberg #3 wells, as these wells were

12

appraisal wells rather than exploratory or development wells. See "—Heidelberg #1, #2 and #3" for more information.

(2)

The wells noted include our North Platte #1 (productive) and Ligurian #2 (dry) exploratory wells.

(3)

The wells noted include our Criollo #1 and Firefox #1 exploratory wells.

        The following table sets forth information with respect to the gross and net oil and gas wells that are currently drilling in the U.S. Gulf of Mexico (including wells that are temporarily suspended) as of the date of this Annual Report on Form 10-K, but does not include oil and gas wells that have been drilled to their targeted depth and have subsequently been either temporarily or permanently plugged and abandoned.

U.S. Gulf of Mexico
Gross(1)		Net(1)
	1		0.42

(1)

The well noted is the Ardennes #1 exploratory well.

Strategic Relationships

        On April 6, 2009, we announced a long-term alliance with Total in which, through a series of transactions, we combined our respective U.S. Gulf of Mexico exploratory lease inventory (which excludes the Heidelberg portion of our Ligurian/Heidelberg prospect, our Shenandoah prospect, and all developed or producing properties held by Total in the U.S. Gulf of Mexico) through the exchange of a 40% interest in our leases for a 60% interest in Total's leases, resulting in a current combined alliance portfolio covering 239 blocks. We act as operator on behalf of the alliance through the exploration and appraisal phases of development. As part of the alliance, Total committed, among other things, to (i) provide a 5th generation deepwater rig to drill a mandatory five-well program on our existing operated blocks, (ii) pay up to $300 million to carry a substantial share of our costs with respect to this five-well program (above the amounts Total has agreed to pay as owner of a 40% interest), (iii) pay an initial amount of approximately $280 million primarily as reimbursement of our share of historical costs in our contributed properties and consideration under purchase and sale agreements, (iv) pay 40% of the general and administrative costs relating to our operations in the deepwater U.S. Gulf of Mexico during the 10-year alliance term, and (v) award us up to $180 million based on the success of the alliance's initial five-well program, in all cases subject to certain conditions and limitations. Additionally, as part of the alliance, we formed a U.S. Gulf of Mexico-wide area of mutual interest with Total, whereby each party has the right to participate in any oil and natural gas lease interest acquired by the other party within this area. Total has paid us the initial amount of approximately $280 million as reimbursement of our share of historical costs in our contributed properties and consideration under purchase and sale agreements. As of December 31, 2012, approximately $95 million of the $300 million that Total is obligated to carry us remains available to us, as does the potential award of up to $120 million based on the success of the alliance. Our North Platte #1 well has qualified as a "successful well" pursuant to the terms of our alliance with Total and in February 2013 Total increased the amount of drilling costs that it is obligated to carry us by $60 million.

        On April 22, 2009, we announced a partnership in the deepwater U.S. Gulf of Mexico with the national oil company of Angola, Sociedade Nacional de Combustíveis de Angola—Empresa Pública ("Sonangol") pursuant to an agreement we had entered into with Sonangol immediately following the 2008 Central Gulf of Mexico Lease Sale, whereby Sonangol acquired a 25% non-operated interest of our pre-Total alliance interests in 11 of our deepwater U.S. Gulf of Mexico leases. The price Sonangol paid us for this interest was calculated using the price we paid for these leases plus $10 million to cover our historical seismic and exploration costs. Sonangol has since acquired its proportionate non-operated interest in four additional deepwater U.S. Gulf of Mexico leases pursuant to this partnership bringing the total partnership portfolio to 15 deepwater U.S. Gulf of Mexico leases. This transaction is notable as it represents Sonangol's initial entry into the North American exploration and production sector.

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West Africa Segment

        Our oil-focused exploration efforts target pre-salt horizons on Blocks 9, 20 and 21 offshore Angola and the Diaba Block offshore Gabon. To date, we have drilled as operator one exploratory well on Block 21 offshore Angola (Cameia #1) and one appraisal well on Block 21 offshore Angola (Cameia #2). These drilling efforts have resulted in the Cameia pre-salt discovery.

        The following sections detail our West Africa business:

Geologic Overview	Page 14
Prospect Identification and Lease Acquisition	Page 14
Prospects and Plans for Exploration	Page 16
Plans for Appraisal	Page 18
Discoveries and Plans for Development	Page 18
Drilling Rigs	Page 21
Prior Drilling Results and Drilling Statistics	Page 22

Geologic Overview

        Offshore Angola and Gabon are characterized by the presence of salt formations and oil-bearing sediments located in pre-salt and above salt (Albian) horizons. Given the rifting that occurred when plate tectonics separated the South American and African continents, we believe the geology offshore Angola (Kwanza Basin) and Gabon (South Gabon Coastal Basin) is a direct analog to the geology offshore Brazil (Campos and Santos Basins) where recent pre-salt discoveries, such as Lula and Jubarte, are located. The basis for this hypothesis is that 150 million years ago, current day South America and Africa were part of a larger continent that broke apart. As these land masses slowly drifted away from each other, rift basins formed. These basins were filled with organic rich material and sediments, which in time became hydrocarbon source rocks and reservoirs. A thick salt layer was subsequently deposited, forming a seal over the reservoirs. Finally the continents continued to drift apart, forming two symmetric geologic areas separated by the Atlantic Ocean. This symmetry in geology is particularly notable in the deepwater areas offshore Gabon, Angola and the Campos Basin offshore Brazil. From an exploration perspective, we believe this similarity is very meaningful, particularly in the context of recent pre-salt Brazilian discoveries, our recent pre-salt Cameia discovery and the recent Azul pre-salt discovery by Maersk.

Prospect Identification and Lease Acquisition

        Similar to our approach in the deepwater U.S. Gulf of Mexico, our business model offshore West Africa begins with prospect identification and lease or license acquisition. Internationally, oil and gas companies typically acquire their rights to explore for and produce hydrocarbons by entering into a "license" arrangement with the applicable host government. We use the terms "lease" and "license" interchangeably in this Annual Report on Form 10-K. Consistent with our "rift" hypothesis that the geology offshore Angola and Gabon was a direct analog to the geology offshore Brazil where recent large pre-salt discoveries are located, we acquired approximately 125,000 line miles (200,000 line kilometers) of 2-D seismic data offshore West Africa. After analyzing and evaluating 2-D seismic data and certain well data, we sought to obtain leases to explore for and develop hydrocarbons offshore West Africa in those areas that offered what we believed were the highest potential for large hydrocarbon deposits. Specifically, we targeted Blocks 9, 20 and 21 offshore Angola and the Diaba Block offshore Gabon.

        We executed Risk Services Agreements ("RSAs") for Blocks 9 and 21 offshore Angola with Sonangol, Sonangol Pesquisa e Produção, S.A. ("Sonangol P&P"), Nazaki Oil and Gáz, S.A. ("Nazaki"), and Alper Oil, Limitada ("Alper"). The RSAs govern our 40% working interest in and

14

operatorship of Blocks 9 and 21 offshore Angola and form the basis of our exploration, development and production operations on these blocks. On December 20, 2011, we executed a Production Sharing Contract (the "PSC") with Sonangol, Sonangol P&P, BP Exploration Angola (Kwanza Benguela) Limited ("BP"), and China Sonangol International Holding Limited ("China Sonangol") for Block 20 offshore Angola. The PSC governs our 40% working interest in and operatorship of Block 20 offshore Angola and forms the basis of our exploration, development and production operations on Block 20 offshore Angola. Subsequent to its execution of the PSC, China Sonangol assigned its working interest in Block 20 to BP. We do not have contractual rights to sell natural gas on our Angola blocks, but we have the right to use the natural gas during lease operations.

        Block 9 is approximately 1 million acres (4,000 square kilometers) in size or approximately 167 U.S. Gulf of Mexico blocks and is located immediately offshore in the southeastern-most portion of the Kwanza Basin. Water depth ranges from zero to more than 3,200 feet (1,000 meters). Block 21 is approximately 1.2 million acres (4,900 square kilometers) in size or approximately 200 U.S. Gulf of Mexico blocks. The block is 30 to 90 miles (50 to 140 kilometers) offshore in water depths of 1,300 to 5,900 feet (400 to 1,800 meters) in the central portion of the Kwanza Basin. Block 20 is approximately 1.2 million acres (4,900 square kilometers) in size or approximately 200 U.S. Gulf of Mexico blocks and is centered approximately 75 miles west of Luanda in the deepwater Kwanza Basin. It is immediately to the north of Block 21.

        Offshore Gabon, we entered into an assignment agreement in February 2008 with Total Gabon, S.A. ("Total Gabon") and acquired a 21.25% working interest in the Diaba Block. Through the assignment we became a party to the Production Sharing Agreement ("PSA") between the operator Total Gabon and the Republic of Gabon. The PSA gives us the right to recover costs incurred and receive a share of the remaining profit from any commercial discoveries made on the block. The Diaba Block is approximately 2.2 million acres (9,100 square kilometers) in size or approximately 370 U.S. Gulf of Mexico blocks. The block is 40 to 120 miles (60 to 200 kilometers) offshore in water depths of 300 to 10,500 feet (100 to 3,200 meters) in the central portion of the offshore South Gabon Coastal basin. We have contractual rights to any natural gas discovered on our Gabon license area.

        In connection with and following the acquisition of our licenses on Blocks 9, 20 and 21 offshore Angola and the Diaba Block offshore Gabon, we acquired 3-D seismic data covering approximately 6,950 square miles (18,000 square kilometers) offshore Angola and Gabon, and began analyzing and reprocessing this data. This includes advanced imaging information, such as wide-azimuth studies, to further our understanding of a particular prospect's characteristics, including both trapping mechanics and fluid migration patterns. Reprocessing is accomplished through a series of model building steps that incorporate the geometry of the salt and below-salt geology to optimize the final image. We also commenced a 3-D seismic acquisition in late 2012 covering approximately 1,120 square miles (2,900 square kilometers) on Block 21 offshore Angola that will be used in connection with the development of our Cameia discovery as well as ongoing exploration activity.

        As of December 31, 2012, our working interests in Blocks 9, 20 and 21 offshore Angola and the Diaba Block offshore Gabon comprised an aggregate 5,652,687 gross (1,840,581 net) undeveloped acres. We do not currently own any working interests in developed acreage offshore West Africa, although exploratory and appraisal wells have discovered hydrocarbons at our Cameia prospect on Block 21 offshore Angola and we have filed a declaration of commercial well with respect to our Cameia #1 exploratory well. We have not yet made a formal declaration of commercial discovery under our RSA governing Block 21 and our Cameia prospect, so we are unable to determine the size of any potential development area covering our Cameia prospect at this time. Upon the filing of a declaration of commercial discovery and the approval of a development area by the applicable Angolan government authorities, we will be in a position to specify the acreage assigned to the Cameia development area and seek approval of a formal development plan. After the approval of a development plan, the delineation of a development area and the completion of certain other steps, we

15

will evaluate which acreage associated with the Cameia prospect could then be classified as developed acreage. See "Risk Factors—Risks Relating to Our Business—Our discoveries remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and development."

        The table below summarizes our undeveloped acreage scheduled to expire in the next five years offshore West Africa.

	Undeveloped Acres Expiring
	2013				2014				2015				2016				2017 and thereafter
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Offshore West Africa
Angola:
Block 9(1)		—		—		988,668		395,467		—		—		—		—		—		—
Block 20(2)		—		—		—		—		—		—		—		—		1,210,569		484,228
Block 21(3)		—		—		—		—		1,210,816		484,326		—		—		—		—
Gabon:
Diaba Block(4)		—		—		—		—		—		—		2,242,634		476,560		—		—

(1)

Pursuant to our RSA governing Block 9, our license to acreage not defined by an approved development area will expire as of March 1, 2014, subject to certain extensions. This expiration date may be extended by three years if we notify Sonangol in writing of such extension at least thirty days before March 1, 2014 provided we have otherwise fulfilled our obligations under the agreement and agree to drill additional wells pursuant to the RSA.

(2)

Pursuant to the PSC governing Block 20, our license to acreage not defined by an approved development area will expire as of January 1, 2017, subject to certain extensions. This expiration date may be extended by three years if we notify Sonangol in writing of such extension at least thirty days before January 1, 2017, provided we have otherwise fulfilled our obligations under the agreement and agree to drill additional wells pursuant to the PSC.

(3)

Pursuant to our RSA governing Block 21, our license to acreage not defined by an approved development area will expire as of March 1, 2015, subject to certain extensions. This expiration date may be extended by three years if we notify Sonangol in writing of such extension at least thirty days before March 1, 2015 provided we have otherwise fulfilled our obligations under the agreement and agree to drill additional wells pursuant to the RSA. The undeveloped acreage numbers listed in this row include acreage associated with our Cameia prospect, upon which exploratory and appraisal wells have discovered hydrocarbons, but a formal declaration of commercial discovery has not yet been filed with the applicable Angolan government authorities and therefore an associated development area has not yet been approved.

(4)

Pursuant to the PSA governing the Diaba Block, our license to acreage not defined by an approved development area will expire as of December 31, 2016, subject to certain extensions.

Prospects and Plans for Exploration

        As a result of our prospect identification process and license acquisition efforts, we currently have an extensive pre-salt prospect inventory offshore West Africa. This inventory includes dozens of prospects in various states of maturation on Blocks 9, 20 and 21 offshore Angola and the Diaba Block offshore Gabon. The initial well drilled to test a prospect is referred to as an exploratory well. Offshore Angola and Gabon, we estimate that the gross cost to drill, evaluate and perform a production test, if necessary, on an exploratory well is approximately $100 to $160 million per well for pre-salt prospects.

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See "Risk Factors—Risks Relating to Our Business—Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business."

        Our near term exploration plans call for the following exploratory wells to be drilled:

        Mavinga #1.    We expect to spud the Mavinga #1 exploratory well (formerly referred to as our North Cameia prospect) in the first quarter of 2013. The Mavinga #1 exploratory well will target pre-salt horizons in Block 21 offshore Angola, where we are the named operator with a 40% working interest. Mavinga was mapped using our pre-stack, depth-migrated 3-D seismic data. This prospect is located approximately 10 kilometers northwest of the Cameia #1 exploratory well location. Nazaki (30%), Alper (10%) and Sonangol P&P (20%) are our partners in the Mavinga prospect.

        Lontra #1.    We expect to spud the Lontra #1 exploratory well in the second quarter of 2013. The Lontra #1 exploratory well will target pre-salt horizons in Block 20, where we are the named operator with a 40% working interest. Lontra was mapped using our 3-D seismic data. BP (30%) and Sonangol P&P (30%) are our partners in the Lontra prospect.

        Bicuar #1.    We expect to spud the Bicuar #1 exploratory well in the third quarter of 2013. The Bicuar #1 exploratory well will target pre-salt horizons in Block 21 offshore Angola, where we are the named operator with a 40% working interest. Bicuar was mapped using our pre-stack, depth-migrated 3-D seismic data. Nazaki (30%), Alper (10%) and Sonangol P&P (20%) are our partners in the Bicuar prospect.

        Idared #1.    We expect to spud the Idared #1 exploratory well in the fourth quarter of 2013. The Idared #1 exploratory well will target pre-salt horizons in Block 20 offshore Angola, where we are the named operator with a 40% working interest. Idared was mapped using our 3-D seismic data. BP (30%) and Sonangol P&P (30%) are our partners in the Idared prospect.

        Baleia #1.    We expect to spud the Baleia #1 exploratory well in 2014. The Baleia #1 exploratory well will target pre-salt horizons in Block 20 offshore Angola, where we are the named operator with a 40% working interest. Baleia was mapped using our 3-D seismic data. BP (30%) and Sonangol P&P (30%) are our partners in the Baleia prospect.

        Loengo #1.    We expect to spud the Loengo #1 exploratory well in 2014. The Loengo #1 exploratory well will target pre-salt horizons in Block 9 offshore Angola, where we are the named operator with a 40% working interest. Loengo was mapped using our 3-D seismic data. Nazaki (30%), Alper (10%) and Sonangol P&P (20%) are our partners in the Loengo prospect.

        Diaman #1.    We will participate as a non-operator in the Diaman #1 exploratory well (formerly referred to as our Mango prospect), which will test pre-salt horizons on the Diaba block offshore Gabon, where Total Gabon is the named operator and we own a 21.25% working interest. We expect Total Gabon, as operator, to spud the Diaman #1 exploratory well in the second quarter of 2013. Diaman was mapped using 3-D seismic data.

        Diaman South #1.    We will participate as a non-operator in the Diamon South #1 exploratory well (formerly referred to as our Mango South prospect), which will test pre-salt horizons on the Diaba block offshore Gabon, where Total Gabon is the named operator and we own a 21.25% working interest. Total Gabon, as operator, may choose to spud the Diaman South #1 exploratory well following the completion of operations on the Diaman #1 exploratory well. Diaman South was mapped using 3-D seismic data.

        In addition, we plan to continue maturing several follow-on prospects on Blocks 9, 20, and 21 offshore Angola and the Diaba Block offshore Gabon. See "Risk Factors—Risks Relating to Our

17

Business—Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling."

Plans for Appraisal

        Following a successful exploratory well on a prospect, the operator may choose to drill one or more appraisal wells to delineate the size and other characteristics of the discovered field, including the areal extent of the field. The drilling of an appraisal well is an important step in the process of being able to determine whether a development of a discovered field would be economic. Offshore Angola and Gabon, we estimate that the gross cost to drill, evaluate and perform a production test, if necessary, on an appraisal well is approximately $100 to $160 million per well for pre-salt prospects. We do not currently have any near term plans to drill appraisal wells offshore Angola or Gabon. However, if any of our near-term exploratory wells are successful, we may decide to drill an appraisal well to further delineate the size and other characteristics of the discovery. In addition to the drilling of appraisal wells, other elements of our appraisal work may include the evaluation and analysis of well logs, reservoir core samples, fluid samples and the results of production tests from both exploratory and appraisal wells. See "Risk Factors—Risks Relating to Our Business—Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business."

Discoveries and Plans for Development

        The information obtained from the drilling of exploratory and appraisal wells is used to create a development plan, which may include the construction of offshore facilities and drilling of development wells designed to efficiently produce and optimize recovery of hydrocarbons from the field. Any oil resources, if developed, would use either newly constructed processing facilities owned by the working-interest partnership, which would be a capital expense, or processing facilities leased from third-party providers, which would be an operating expense. In general, we expect our development wells will be produced through subsea templates tied back to the processing facilities. We estimate that the average gross cost to drill and complete a development well would be approximately $100 to $160 million for pre-salt fields offshore Angola and Gabon. In addition to the drilling and completion costs associated with development wells, we also expect to incur substantial costs associated with the design, construction and installation of subsea, umbilical, riser and flowline systems.

        As an operator in Angola, we expect that our primary development concept for any discovery, including our Cameia pre-salt discovery, will be standardized phased developments to enhance understanding of reservoir performance and optimize development planning. For each discovery, we expect that an early production system incorporating a floating production, storage and offloading ("FPSO") system will be implemented, to then be followed by a further standardized FPSO system depending on the size of the discovery and associated development. All FPSOs offshore Angola are expected to be leased.

        A discovery made by the initial exploratory well on a prospect does not ensure that we will ultimately develop or produce oil or gas from such prospect or that a development will be economically viable or successful. Following a discovery by an initial exploratory well, substantial additional evaluation and analysis will need to be performed prior to official project sanction and development, which may include (i) the drilling of appraisal wells, (ii) the evaluation and analysis of well logs, reservoir core samples, fluid samples and the results of production tests from both exploratory and appraisal wells, and (iii) the preparation of a development plan which includes economic assumptions on the costs of drilling development wells, and the construction or leasing of offshore production facilities and transportation infrastructure. Regulatory approvals are also required to proceed with certain development plans. Any of the foregoing steps of evaluation and analysis may render a

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particular discovery uneconomic and we may ultimately decide to abandon the prospect, despite the fact that the initial exploratory well, or subsequent appraisal wells, discovered hydrocarbons. See "Risk Factors—Risks Relating to Our Business—Our discoveries remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and development."

        Cameia Discovery.    On February 9, 2012, we announced that the Cameia #1 exploratory well was drilled in 5,518 feet (1,682 meters) of water to a total depth of 16,030 feet (4,886 meters), at which point an extensive wire-line evaluation program was conducted. The results of this wire-line evaluation program confirmed the presence of a 1,180 foot (360 meter) gross continuous hydrocarbon column with over a 75% net to gross pay estimate. No gas/oil or oil/water contact was evident on the wire line logs. An extended Drill Stem Test ("DST") was performed on the Cameia #1 exploratory well to provide additional information. The DST flowed at an un-stimulated sustained rate of 5,010 barrels per day of 44-degree API gravity oil and 14.3 million cubic feet per day of associated gas (approximately 7,400 BOEPD) with minimal bottom-hole pressure drawdown. Upon shut-in, the bottom-hole pressure reverted to its initial state in less than one minute. The well bore used in the DST had a perforated interval of less than one-third of the reservoir section. The flow rate, which was restricted by surface equipment, facility and safety precautions, confirmed the presence of a very thick, continuous, high quality reservoir. We believe the well, without such restrictions, would have the potential to produce in excess of 20,000 barrels of oil per day. We are the operator of and own a 40% working interest in the Cameia discovery.

        Our Cameia discovery confirms our West Africa pre-salt geologic model, including a working pre-salt petroleum system, significantly de-risked the geologic uncertainty associated with the deepwater Angolan pre-salt play, and increased the likelihood of geologic success on our adjacent undrilled prospects offshore Angola. In addition, the results of the Cameia #1 exploratory well confirmed or exceeded our pre-drill estimates of reservoir quality and thickness. Such results also lead us to believe that the areal extent of the Cameia #1 pre-salt discovery is between 7,500 and 25,000 acres (30 to 100 square kilometers).

        On July 31, 2012, we provided an update on the status of our Cameia #2 appraisal well located in Block 21 offshore Angola. The Cameia #2 appraisal well (i) confirmed the presence of a large hydrocarbon accumulation in what is a high quality reservoir, (ii) discovered a new hydrocarbon-bearing zone at least 440 feet (134 meters) deeper than that which was observed in the Cameia #1 exploratory well, and (iii) demonstrated lateral continuity within the reservoir originally encountered by the Cameia #1 exploratory well. The Cameia #2 appraisal well was drilled approximately 1.7 miles (2.7 kilometers) south from the Cameia #1 exploratory well to the total depth of 17,963 feet (5,475 meters).

        We are currently in the process of performing a DST on the new deeper hydrocarbon-bearing zones encountered by the Cameia #2 appraisal well. We expect to announce the results of this DST in the first quarter of 2013.

        We continue to advance plans to develop our Cameia discovery in Block 21 offshore Angola following the drilling of the successful Cameia #2 appraisal well. Our confidence in advancing plans to develop our Cameia discovery is based on the fact that the drilling results from our Cameia #2 appraisal well penetrated hydrocarbons and demonstrated lateral continuity within the reservoir originally encountered by our Cameia #1 exploratory well. This provided additional assurance of sufficient areal extent to support our plans to proceed with the evaluation of development options. Our subsurface development work is in process, with static and dynamic reservoir simulators under development to help refine our resource estimates and optimize well spacing for the first phase of development. We are also progressing our development well design, including the development of drilling and completion options. We are preparing tender documents for a drilling rig to be used in development operations and long-lead equipment for drilling and completion operations. In addition,

19

we are also continuing our production chemistry analysis, which will help us better understand the flow assurance requirements that will be considered in our subsea design. We are currently working to define the scope of our subsea, umbilical, riser and flowline requirements, and we expect to select the subsea architecture in 2013 to be used in the first phase of the Cameia development. We have received and are currently evaluating proposals from five suppliers of FPSO vessels for production operations at Cameia and anticipate initiating front-end engineering design and detailed engineering scopes in 2013. We currently estimate first production from the Cameia field during 2016, assuming continued alignment with our partners and Sonangol, among other things. See "Risk Factors—Risks Relating to Our Business—Our discoveries remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and development."

EXPLORATION TO PRODUCTION BUSINESS MODEL

MATURING PROSPECTS	EXPLORATION WELLS	APPRAISAL	PRE-PRODUCTION(1)
Angola
Block 21 #4, #5, #6	Block 21—Mavinga #1 Block 21—Bicuar #1	Block 21—Cameia Lower Reservoir	Block 21—Cameia Upper Reservoir
Block 20 #4, #5	Block 20—Lontra #1
	Block 20—Idared #1
	Block 20—Baleia #1
Block 9 #2	Block 9—Loengo #1
Gabon
Diaba #3, #4	Diaba—Diaman #1
	Diaba—Diaman South #1

(1)

Discoveries that we classify as being in a "pre-production" phase are those in which successful exploration and appraisal wells have been drilled and we, in cooperation with any partners on the applicable discovery, are continuing to advance plans to develop the field. Substantial additional evaluation and analysis may need to be performed prior to official project sanction and development, which includes the preparation of a development plan containing economic assumptions on the costs of drilling development wells, and the construction or leasing of offshore production facilities and transportation infrastructure. Such evaluation and analysis could render a particular discovery uneconomic and it is possible that we could ultimately decide to abandon the prospect, despite the fact that we currently classify the discovery as being in "pre-production." See "Risk Factors—Risks Relating to Our Business—Our discoveries remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and development."

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        The maps below show our offshore West Africa prospects, near-term exploratory wells, and discoveries in appraisal and pre-production.

Angola



Gabon



Drilling Rigs

        We currently have two drilling rigs under contract to support our pre-salt exploratory drilling campaign offshore Angola during 2013: the Diamond Ocean Confidence and the Petroserv SSV Catarina. We have the right to use the Ocean Confidence to complete the DST on the lower reservoir penetrated by the Cameia #2 appraisal well and drill two additional wells, which will include our Mavinga #1 exploratory well and one additional well. The first well will be at a dayrate of $375,000 and the second well at a dayrate of $430,000. On July 30, 2012, we executed a drilling contract with an affiliate of Petroserv S.A. for the SSV Catarina, a new-build, sixth-generation semi-submersible drilling

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rig. The SSV Catarina drilling rig was mobilized from South Korea in January 2013 and we expect it to arrive in Angola late in the first quarter or early in the second quarter of 2013. The SSV Catarina drilling contract provides for a firm three-year commitment, beginning upon arrival of the rig to our Lontra #1 exploratory well location on Block 20 offshore Angola, at a day rate of approximately $600,000 and two one-year extension options at day rates to be mutually agreed. Such rates are subject to standard reimbursement and escalation contractual provisions.

Prior Drilling Results and Drilling Statistics

        The results of each of the wells we have drilled as operator offshore West Africa since our formation are listed below.

        Cameia #1.    On February 9, 2012, we announced that the Cameia #1 exploratory well was drilled in 5,518 feet (1,682 meters) of water to a total depth of 16,030 feet (4,886 meters), at which point an extensive wire-line evaluation program was conducted. The results of this wire-line evaluation program confirmed the presence of a 1,180 foot (360 meter) gross continuous hydrocarbon column with over a 75% net to gross pay estimate. No gas/oil or oil/water contact was evident on the wire line logs. An extended DST was performed on the Cameia #1 exploratory well to provide additional information. The DST flowed at an un-stimulated sustained rate of 5,010 barrels per day of 44-degree API gravity oil and 14.3 million cubic feet per day of associated gas (approximately 7,400 BOEPD) with limited drawdown. The flow rate, which was restricted by surface equipment, facility and safety precautions, confirmed the presence of a very thick, continuous, high quality reservoir. See "—Discoveries and Plans for Development—Cameia Discovery."

        Cameia #2.    On July 31, 2012, we provided an update on the status of our Cameia #2 appraisal well located in Block 21 offshore Angola. The Cameia #2 appraisal well (i) confirmed the presence of a large hydrocarbon accumulation in what is a high quality reservoir, (ii) discovered a new hydrocarbon-bearing zone at least 440 feet (134 meters) deeper than that which was observed in the Cameia #1 exploratory well, and (iii) demonstrated lateral continuity within the reservoir originally encountered by the Cameia #1 exploratory well. The Cameia #2 appraisal well was drilled approximately 1.7 miles (2.7 kilometers) south from the Cameia #1 exploratory well to the total depth of 17,963 feet (5,475 meters). See "—Discoveries and Plans for Development—Cameia Discovery."

        Bicuar #1.    On July 27, 2011, we announced that we had commenced our initial two well pre-salt exploratory drilling program on Block 21 offshore Angola by spudding the surface hole of the Bicuar #1 exploratory well. On July 20, 2011, after setting the 36" conductor casing and drilling approximately 689 feet (210 meters) of surface hole, we encountered an over pressured water sand resulting in a water flow with limited quantities of natural gas. No safety or environmental issues resulted from the incident, and we subsequently plugged and abandoned the Bicuar #1 exploratory well. We expect to spud the Bicuar #1 exploratory well from a different surface hole location in the third quarter of 2013.

        The following table sets forth information with respect to the gross and net oil and gas wells we drilled offshore West Africa during the periods indicated. The information presented is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of any reserves found. Productive wells include wells that have been drilled to the targeted depth and prove, in our opinion, to be capable of producing either oil or gas in sufficient quantities that will justify completion as an oil or gas

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well. A dry well is an exploratory, appraisal or development well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

	Offshore West Africa
	2012(2)				2011				2010
Wells Drilled	Gross		Net		Gross		Net		Gross		Net
Exploratory(1)
Productive		2		0.8		—		—		—		—
Dry		—		—		—		—		—		—
Total		2		0.8		—		—		—		—

(1)

We did not drill any development wells offshore West Africa during the fiscal years ended December 31, 2012, 2011 and 2010, respectively. The numbers in this table do not reflect our drilling of the surface hole of the Bicuar #1 exploratory well, as we plugged and abandoned the well after drilling only 689 feet (210 meters). See "—Bicuar #1" for more information.

(2)

The wells noted include our Cameia #1 exploratory well and Cameia #2 appraisal well.

        The following table sets forth information with respect to the gross and net oil and gas wells that are currently drilling offshore West Africa (including wells that are temporarily suspended) as of the date of this Annual Report on Form 10-K, but does not include oil and gas wells that have been drilled to their targeted depth and have subsequently been either temporarily or permanently plugged and abandoned.

West Africa
Gross(1)		Net(1)
	1		0.40

(1)

The well noted is the DST on our Cameia #2 appraisal well.

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MATERIAL AGREEMENTS

TOTAL Alliance

        On April 6, 2009, we announced that we had entered into a long-term alliance with Total. This alliance transaction principally consisted of:

•

A simultaneous exchange agreement, between Total and ourselves, dated April 6, 2009 (the "Exchange Agreement"), whereby both Total and ourselves agreed to combine each company's respective U.S. Gulf of Mexico exploratory lease inventories except as to certain leases which were purchased by us and Total under separate purchase and sale agreements. This was achieved through the transfer of a 40% interest in our leases to Total in return for a 60% interest in Total's leases, and resulted in a current combined alliance portfolio covering 239 U.S. Gulf of Mexico blocks. As the Exchange Agreement contemplates the combination of Total and our U.S. Gulf of Mexico exploratory lease inventories, it excludes the Heidelberg portion of our Ligurian/Heidelberg prospect, our Shenandoah prospect, and all developed or producing properties held by Total in the U.S. Gulf of Mexico. The terms of the exchange agreement mandate the alliance, with Cobalt as operator, to drill an initial five-well program on existing Cobalt-operated blocks. This well program is expected to be drilled on the prospects of Ligurian, Criollo, North Platte, Aegean and Ardennes. In order to drill this initial program, Total committed to provide us with the use of a drilling rig to drill the well program. Furthermore, pursuant to the terms of the Exchange Agreement, Total has also committed, among other things, to (i) pay up to $300 million to carry a substantial share of costs first allocable to us based on our 60% ownership interest in the combined alliance properties with respect to this five-well program and certain other exploration, appraisal and development activities (above the amounts Total has agreed to pay as owner of a 40% interest in such properties), (ii) pay an initial amount of approximately $280 million primarily as reimbursement of our share of historical costs in our contributed properties and consideration under purchase and sale agreements covering leases not included in the Exchange Agreement, and (iii) based on the success of the alliance's five-well program (primarily defined as discoveries of petroleum accumulations of at least 100 feet of net pay thickness for Miocene objectives and 250 feet of net pay thickness for Lower Tertiary objectives), pay up to $180 million to carry a substantial share of costs first allocable to Cobalt based on its 60% ownership interest in combined alliance properties with respect to additional wells and certain other exploration, appraisal and development activities outside of the five-well program, in all cases subject to certain conditions and limitations. Any additional carry owed to us based on the success of the alliance's five-well program will increase the commitment by Total to pay a disproportionate share of the costs of additional wells drilled and certain other exploration and development activities incurred outside of the five-well program. To date, Total has paid us the initial amount of approximately $280 million as reimbursement of our share of historical costs in our contributed properties and consideration under purchase and sale agreements. As of December 31, 2012, approximately $95 million of the $300 million that Total is obligated to carry us remains available to us, as does the potential award of up to $120 million based on the success of the alliance. Our North Platte #1 well has qualified as a "successful well" pursuant to the terms of our alliance with Total and in February 2013 Total increased the amount of drilling costs that it is obligated to carry us by $60 million.

•

A management and area of mutual interest agreement, between Total and ourselves, dated April 6, 2009 (the "Total AMI Agreement"), whereby both Total and ourselves agreed to participate in an area of mutual interest covering the whole U.S. Gulf of Mexico. The Total AMI Agreement is for a term of ten years, and grants each party the right and option, but not the obligation, to acquire a share of any oil and natural gas leasehold interest acquired by the other party within the designated area. The Total AMI Agreement excludes the Heidelberg portion of our Ligurian/Heidelberg prospect, our Shenandoah prospect, and all developed or producing

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properties held by Total in the U.S. Gulf of Mexico. For the duration of the term of the Total AMI Agreement, Total will pay 40% of the general and administrative costs relating to our operations in the U.S. Gulf of Mexico. Furthermore, this agreement designates us as the operator for all exploratory and appraisal operations. Upon completion of appraisal operations, operatorship will be determined by Total and ourselves, with the greatest importance being placed on majority (or largest) working interest ownership and the respective experience of each party in developments which have required the design, construction and ownership of a permanently anchored host facility to collect and transport oil or natural gas from such development.

Sonangol Partnership

        On May 15, 2008, we entered into a participation agreement with Sonangol, which established the terms of our deepwater U.S. Gulf of Mexico partnership with Sonangol. This partnership currently consists of an agreement for Sonangol to participate in the development of certain prospects on 15 of our deepwater U.S. Gulf of Mexico leases. In this regard, Sonangol purchased a 25% non-operated interest in the blocks containing our Sulu, Ligurian and Rocky Mountain prospects, among others. Furthermore, in connection with the partnership, Sonangol purchased their interests in our leases for the price we paid for such leases in the 2007 and 2008 Central Gulf of Mexico Lease Sales, reimbursed us $10 million for our share of historical seismic and exploration costs in the subject properties and allow us to act as the operator on all of the subject properties.

Production Sharing Contract for Block 20 Offshore Angola

        On December 15, 2011, the Council of Ministers of Angola published Decree Law No. 303/11 which granted the mining rights for the prospecting, research, development and production of hydrocarbons on Block 20 offshore Angola to Sonangol, as the national concessionaire, and appointed us as the operator of Block 20. On December 20, 2011, CIE Angola Block 20 Ltd., our wholly-owned subsidiary, executed the PSC with Sonangol, Sonangol P&P, BP and China Sonangol. Subsequent to its execution of the PSC, China Sonangol assigned its working interest in Block 20 to BP. The PSC forms the basis of our exploration, development and production operations on Block 20 offshore Angola. We are the operator of and own a 40% working interest in Block 20 offshore Angola. Under the PSC, in order to preserve our rights in Block 20, we will be required to drill four exploratory wells (with at least one of these wells having a pre-salt objective), acquire approximately 1,500 square kilometers of 3-D seismic data, and make at least one commercial discovery, all within five years of the signing of the PSC, subject to certain extensions. We have the right to a 30-year production period. In order to guarantee these exploration work obligations under the PSC, we and BP are required to post a financial guarantee of $360 million. Our share of this financial guarantee is 57.14%, or approximately $206 million. We have delivered a letter of credit to Sonangol for such amount. As we complete our work obligations under the PSC, the amount of this letter of credit will be reduced accordingly. We acquired approximately 1,500 square kilometers of 3-D seismic data in 2012, and, accordingly, our letter of credit was reduced by approximately $17.1 million on August 16, 2012. In addition, pursuant to the PSC, we and BP are required to make certain contributions for bonus, scholarships and for social projects such as the Sonangol Research and Technology Center aggregating $607.5 million, comprised of $242.5 million in the first year after the signing of the PSC, $85 million on each of the first, second and third anniversaries of the signing of the PSC, and $110 million on the fourth anniversary of the signing of the PSC. We are obligated to pay 57.14% of the foregoing costs, less $10 million previously paid, or approximately $337 million. On January 6, 2012, we funded our share of the social contributions due upon the signing of the PSC. We shall recover all exploration, development, production, administration and services expenditures incurred under the PSC by taking up to a maximum amount of 50% of all oil produced from Block 20. In addition, proportionate with our working interest in Block 20, we will receive 40% of a variable revenue stream that the Contractor

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Group (as defined in the PSC) will be allocated from Sonangol based on the Contractor Group's rate of return, reduced by applicable Angolan taxes, calculated on a quarterly basis. The variable revenue stream paid by Sonangol to the Contractor Group ranges from 10% to 70%, and is inversely related to the applicable rate of return. We do not have contractual rights to sell natural gas from Block 20, but we have the right to use the natural gas during lease operations.

Risk Services Agreements for Blocks 9 and 21 Offshore Angola

        On June 11, 2009, the Council of Ministers of Angola published Decree Law No. 15/09 and Decree Law No. 14/09 which granted the mining rights for the prospecting, exploration, development and production of hydrocarbons on Blocks 9 and 21 offshore Angola, respectively, to Sonangol, as the national concessionaire, and appointed us as the operator of Blocks 9 and 21, respectively. Pursuant to these Decree Laws, in October 2009, we completed negotiations with Sonangol and initialed the finalized RSAs for Blocks 9 and 21 offshore Angola. On December 16, 2009, the Council of Ministers of Angola approved the terms of the finalized RSAs. On February 24, 2010, we executed RSAs for Blocks 9 and 21 offshore Angola with Sonangol, Sonangol P&P, Nazaki and Alper. Cobalt, Sonangol P&P, Nazaki and Alper comprise the "Contractor Group" under the RSAs. The RSAs govern our 40% working interest in and operatorship of Blocks 9 and 21 offshore Angola and form the basis of our exploration, development and production operations on these blocks.

•

Under the RSA for Block 9, in order to preserve our rights in the block, we will be required to drill three wells, as well as acquire approximately 10,764 million square feet (1,000 square kilometers) of seismic data, and find at least one commercial discovery, within four years of its signing. This four year period may be extended by one extension of three years if we notify Sonangol in writing of such extension at least thirty days before the end of the four year period and if we have otherwise fulfilled our obligations under the agreement. After this initial four or seven year period ends, our rights in the block are only preserved with respect to the development areas on the block on which discoveries have been made and all other portions of the block will be forfeited. After this initial four or seven year period ends, we will also be required to commence production within four years of the date of the commercial discovery, subject to certain extensions. We have the right to a 20 year production period. In order to guarantee our exploration work obligations under the RSA for Block 9, we and Nazaki are required to post a financial guarantee in the amount of approximately $87.5 million. Our share of this financial guarantee is approximately $54.7 million. In March 2010, we delivered a letter of credit to Sonangol for such amount. As we complete our work obligations under the RSA, the amount of this letter of credit will be reduced accordingly. We acquired approximately 2,500 square kilometers of 3-D seismic data on Block 9 in 2011, and, accordingly, our letter of credit was reduced by approximately $9.375 million on April 25, 2011. As is customary in Angola, we are required to make contributions for Angolan social projects and academic scholarships for Angolan citizens. We made such an initial contribution in March 2010 after the signing of the RSA and will make additional contributions upon each commercial discovery, upon project development sanction and each year after the commencement of production. We have a 40% working interest in Block 9, with Nazaki, Alper and Sonangol P&P holding lesser working interests in the block and sharing in the exploration, development and production costs associated with such block. Proportionate with our working interest in Block 9, we will receive 40% of a variable revenue stream that the Contractor Group will be allocated from Sonangol based on the Contractor Group's rate of return, calculated on a quarterly basis, and then reduced by applicable Angolan taxes and royalties. The Contractor Group's rate of return for each quarter will be determined by the Contractor Group's variable revenue stream from oil production less expenditures and Angolan taxes and royalties from the block. The variable revenue stream paid by Sonangol to the Contractor Group ranges from 72% to 95%, and is inversely related to the applicable rate of return. The Angolan taxes and royalties applicable to

26

the variable revenue stream include the petroleum production tax (at a current tax rate of 20% applied to the Contractor Group's variable revenue stream), the petroleum transaction tax (at a current tax rate of 70% applied to the Contractor Group's variable revenue stream less expenditures less the Contractor Group's specified production allowance, which ranges from 55% to 95% of the Contractor Group's variable revenue stream depending inversely on the Contractor Group's rate of return) and the petroleum income tax (at a current tax rate of 65.75% applied to the Contractor Group's variable revenue stream less expenditures and less petroleum production and petroleum transaction taxes paid). We do not have contractual rights to sell natural gas from Block 9, but we have the right to use the natural gas during lease operations.

•

Under the RSA for Block 21, in order to preserve our rights in the block, we will be required to drill four wells and find at least one commercial discovery, within five years of its signing. This five year period may be extended by one extension of three years if we notify Sonangol in writing of such extension at least thirty days before the end of the five year period and if we have otherwise fulfilled our obligations under the agreement. After this initial five or eight year period ends, our rights in the block are only preserved with respect to the development areas on the block on which discoveries have been made and all other portions of the block will be forfeited. After this initial five or eight year period ends, we will also be required to commence production within four years of the date of the commercial discovery, subject to certain extensions. We have the right to a 25 year production period. In order to guarantee these exploration work obligations under the Risk Services Agreement for Block 21, we and Nazaki are required to post a financial guarantee in the amount of approximately $147.5 million. Our share of this financial guarantee is approximately $92.2 million. In March 2010, we delivered a letter of credit to Sonangol for such amount. As we complete our work obligations under the RSA, the amount of this letter of credit will be reduced accordingly. As a result of completing drilling operations on our Cameia #1 exploratory well in 2012, our letter of credit was reduced by approximately $31.25 million on May 25, 2012. As is customary in Angola, we are required to make contributions for Angolan social projects and academic scholarships for Angolan citizens. We made such an initial contribution in March 2010 after the signing of the RSA and will make additional contributions upon each commercial discovery, upon project development sanction and each year after the commencement of production. We have a 40% working interest in Block 21, with Nazaki, Alper and Sonangol P&P holding lesser working interests in the block and sharing in the exploration, development and production costs associated with such block. Proportionate with our working interest in Block 21, we will receive 40% of a variable revenue stream that the Contractor Group will be allocated from Sonangol based on the Contractor Group's rate of return, calculated on a quarterly basis, and then reduced by applicable Angolan taxes and royalties. The Contractor Group's rate of return for each quarter will be determined by the Contractor Group's variable revenue stream from oil production less expenditures and Angolan taxes and royalties from the block. The variable revenue stream paid by Sonangol to the Contractor Group ranges from 60% to 96%, and is inversely related to the applicable rate of return. The Angolan taxes and royalties applicable to the variable revenue stream include the petroleum production tax (at a current tax rate of 20% applied to the Contractor Group's variable revenue stream), the petroleum transaction tax (at a current tax rate of 70% applied to the Contractor Group's variable revenue stream less expenditures less the Contractor Group's specified production allowance, which ranges from 35% to 90% of the Contractor Group's variable revenue stream depending inversely on the Contractor Group's rate of return) and the petroleum income tax (at a current tax rate of 65.75% applied to the Contractor Group's variable revenue stream less expenditures and less petroleum production and petroleum transaction taxes paid). We do not have contractual rights to sell natural gas from Block 21, but we have the right to use the natural gas during lease operations.

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COMPETITION

        The oil and gas industry is highly competitive. We encounter strong competition from other independent and major oil and gas companies in acquiring properties and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and gas properties, or to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drill attempts, delays, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position.

        We are also affected by competition for drilling rigs and the availability of related equipment and personnel. Our recent Cameia pre-salt discovery, which significantly de-risked the geologic uncertainty associated with the offshore Angola pre-salt play, could increase the demand for drilling rigs and related equipment and personnel offshore West Africa which, in turn, could increase the competition for drilling rigs or related oilfield equipment and personnel and adversely affect our ability to secure such equipment or hire such personnel on favorable terms. Furthermore, higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, oil and gas companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill wells and conduct our operations.

        Competition is also strong for attractive oil and gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

TITLE TO PROPERTY

        We believe that we have satisfactory title to our prospect interests in accordance with standards generally accepted in the oil and gas industry. We currently have federal oil and gas leases in 246 blocks within the deepwater U.S. Gulf of Mexico covering approximately 1.4 million gross acres (0.7 million net acres). In West Africa, we currently have a license on the Diaba Block offshore Gabon, and licenses for Blocks 9, 20 and 21 offshore Angola. We do not have contractual rights to sell natural gas on our Angola blocks, but we have the right to use the natural gas during lease operations. We do, however, have contractual rights to any natural gas from our Gabon license area. Our prospect interests are subject to applicable customary royalty and other interests, liens under operating agreements, liens for current taxes, and other burdens, easements, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect our carrying value of the prospect interests.

CONTAINMENT RESOURCES

        We are a member of several industry groups that provide general and specific oil spill and well containment resources in the U.S. Gulf of Mexico, including the Helix Well Containment Group ("HWCG"), Clean Gulf Associates ("CGA"), the Marine Preservation Association ("MPA"), and National Response Corporation ("NRC").

        We are a member of HWCG Holdings, LLC, which in turn wholly owns HWCG, LLC. HWCG, LLC serves as the operating entity for the members of HWCG by carrying out day-to-day business activities and serving as a contracting party for various oil spill and well containment equipment and services on behalf of the HWCG members. Our relationship with HWCG provides us access to the

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Helix Producer 1, a production handling vessel, and the Helix Q4000, a multi-purpose field intervention and construction vessel. Together with various elements of relevant hardware such as hoses, connectors, risers, and similar equipment, the Helix Producer and the Helix Q4000 form the "Helix Fast Response System". The Helix Fast Response System is currently capable of facilitating control and containment of spills in water depths up to 10,000 feet and has capturing and processing capabilities of 55,000 barrels of oil per day and 95 million cubic feet of gas per day. HWCG has two capping stacks, a 15,000 psig capping stack and a 10,000 psig capping stack. The capping stacks are designed to handle deep, higher-pressure wells and would be used in the event a blowout preventer is ineffective. In addition to us, members of HWCG include operators such as Marathon Oil Company and Statoil Gulf of Mexico LLC, among others.

        As a member of MPA, we have access to the resources of the Marine Spill Response Corporation ("MSRC"). MSRC provides a wide variety of surface spill equipment, including approximately 75% of the existing dispersant material in the U.S. Gulf of Mexico region. NRC is an umbrella response corporation that provides us access to a wide variety of surface spill response equipment as well as a wide group of surface response contractors that can address a surface response as well as play a support role in addressing a subsea well containment event. In addition, we have existing contracts with a number of contractors which have equipment that could assist in well containment efforts as well as with the surface effects of a subsea blowout or in addressing a concurrent surface spill. Examples of such equipment include, but are not limited to, anchor and supply vessels, subsea transponders and communication equipment, subsea cutting equipment, debris removal equipment, air and water monitoring and scientific support vessels, remote-operated vehicles, storage and shuttle vessels, and subsea dispersant equipment.

        For our operations offshore West Africa, we have contracts in place for the provision of oil spill management, equipment and response services. Specifically, we have contracted with (i) Braemer-Howells, a U.K.-based company with staff in Angola, which provides us access to oil spill response management, equipment and services, (ii) the West and Central African Aerial Surveillance and Dispersant Service, a non-profit organization which provides aerial surveillance and chemical dispersant services offshore Angola utilizing aircraft based in Ghana, and (iii) Oil Spill Response Limited, a U.K.-based company which is wholly owned by exploration and production companies and provides us access to personnel and equipment for oil spill events. In addition, we have developed an Oil Spill Response Plan to address any potential spill, and we have access to equipment which is pre-staged in Angola, including containment boom, skimming systems, chemical dispersant systems, and temporary oil storage systems.

        Furthermore, we also have contracts in place with O'Brien's Response Management and J. Connor Consulting for the provision of additional emergency response management services to help us address an incident in either the U.S. Gulf of Mexico or West Africa.

        In considering the information above, specific reference should be made to the subsection of this Annual Report on Form 10-K titled "Risk Factors—Risks Relating to Our Business—We are subject to drilling and other operational hazards."

INSURANCE COVERAGE

        We have insurance coverage in place for our U.S. Gulf of Mexico operations, consisting of a $500 million policy for operator's extra expense, which covers well control, re-drill and pollution clean-up expenses, a $450 million policy for third-party liability, and a $50 million policy for liabilities incurred under the Oil Pollution Act of 1990. In addition, we have identified certain unencumbered assets in the U.S. Gulf of Mexico to the Bureau of Ocean Energy Management ("BOEM") in order to demonstrate $100 million of Oil Spill Financial Responsibility through self-insurance under the Oil Pollution Act of 1990. For our West Africa operations, we have insurance policies in Angola that provide coverages of three times the amount of our nominal authorization-for-expenditure for each well, or approximately

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$450 to $500 million, and policies in Gabon for approximately $350 million. In addition, we also have insurance policies in West Africa for up to $200 million for third party liability. Our stated policy limits scale down to our working interest based on the working interest in the prospect being drilled. We believe that these coverage amounts are sufficient and are consistent with what is held by our competitors operating in the deepwater U.S. Gulf of Mexico and West Africa.

        In considering the information above, specific reference should be made to the subsection of this Annual Report on Form 10-K titled "Risk Factors—Risks Relating to Our Business—We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage" and "Risk Factors—Risks Relating to Our Business—We are subject to drilling and other operational hazards."

ENVIRONMENTAL MATTERS AND REGULATION

General

        We are, and our future operations will be, subject to various stringent and complex international, foreign, federal, state and local environmental, health and safety laws and regulations governing matters including the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use, transportation and disposal of regulated materials; and the health and safety of our employees. These laws and regulations may, among other things:

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require the acquisition of various permits before drilling commences;

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enjoin some or all of the operations of facilities deemed not in compliance with such laws and regulations or permits issued thereunder;

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas exploration, drilling, production and transportation activities;

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limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and

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require remedial measures to mitigate pollution from our operations.

        These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Compliance with these laws can be costly; the regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

        Moreover, particularly in light of the Deepwater Horizon incident in the U.S. Gulf of Mexico, public interest in the protection of the environment has increased. Offshore drilling in some areas has been opposed by environmental groups and, in other areas, has been restricted. Our operations could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental requirements that result in increased costs to the oil and gas industry in general, such as more stringent or costly waste handling, disposal, cleanup requirements or financial responsibility and assurance requirements.

        Accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result, including costs relating to claims for damage to natural resources, property and persons. Moreover, environmental laws and regulations are complex, change frequently and have tended to become more stringent over time. Accordingly, we cannot assure you that we have been or will be at all times in compliance with such laws, or that environmental laws and regulations will not change or become more stringent in the future in a manner that could have a material adverse effect on our financial condition and results of operations.

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        The following is a summary of some of the existing laws or regulatory issues to which we and our business operations are or may be subject to in the future.

Impact of the U.S. Gulf of Mexico Oil Spill

        On April 20, 2010, the Transocean Deepwater Horizon, a semi-submersible offshore drilling rig operating in the deepwater U.S. Gulf of Mexico under contract to BP plc exploded, burned for two days and sank, resulting in loss of life, injuries and a large oil spill. The U.S. government and its regulatory agencies with jurisdiction over oil and gas exploration, including the U.S. Department of the Interior ("DOI") and two of its agencies, the BOEM and the Bureau of Safety and Environmental Enforcement ("BSEE"), which together formerly comprised the Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE"), responded to this incident by imposing moratoria on drilling operations. These agencies also required operators to reapply for exploration plans and drilling permits which had previously been approved and adopted numerous new regulations and new interpretations of existing regulations regarding operations in the U.S. Gulf of Mexico that are applicable to us and with which our new applications for exploration plans and drilling permits must prove compliant. These regulations include (i) the Increased Safety Measures for Energy Development on the Outer Continental Shelf—Final Rule, which sets forth increased safety measures for offshore energy development and requires, among other things, that all offshore operators submit written certifications as to compliance with the rules and regulations for operations occurring in the Outer Continental Shelf including the submission of independent third party written certifications as to the capabilities of certain safety devices, such as blowout preventers and their components, (ii) the workplace safety rule, which requires operators to develop and implement a comprehensive Safety and Environmental Management System, or SEMS, for oil and gas operations and codifies and makes mandatory the American Petroleum Institute's Recommended Practice 75, (iii) NTL No 2010-N06, which sets forth requirements for exploration plans, development and production plans and development operations coordination documents to include a blowout scenario, the assumptions and calculations that are used to determine the volume of the worst case discharge scenario, and proposed measures to prevent and mitigate a blowout and (iv) NTL No. 2010-N10, which requires that each operator submit adequate information demonstrating that it has access to and can deploy containment resources that would be adequate to promptly respond to a blowout or other loss of well control, adds additional requirements to oil spill response plans and requires that operators submit written certifications stating that the operator will conduct all authorized activities in compliance with all applicable regulations. In September 2011, the BOEMRE issued proposed amendments to the workplace safety rule which would, among other things, expand required safety procedures and revise third party auditing procedures of a company's SEMS. We have conducted our own internal SEMS assessment and plan to conduct a third party SEMS audit in 2013 to ensure we are in compliance with all applicable regulations related to our SEMS. We believe that the extensive new regulations and changes proposed thereto, increased regulatory scrutiny including the requirement for the BOEM to conduct a site specific environmental assessment for every proposed well location has and may continue to result in substantial delays to the historical timing of the permitting process.

        Compliance with the new regulations and new interpretations of existing regulations may materially increase the cost of and time required to obtain drilling permits or conduct our drilling operations in the U.S. Gulf of Mexico, which may adversely affect our business, financial position or future results of operations.

Oil Pollution Act of 1990

        The U.S. Oil Pollution Act of 1990 ("OPA") and regulations thereunder impose liability on responsible parties for damages resulting from oil spills into or upon navigable waters or in the exclusive economic zone of the U.S. Liability under the OPA is strict, joint and several and potentially unlimited. A "responsible party" under the OPA includes the lessee or permittee of the area in which

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an offshore facility is located. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility to cover potential liabilities related to an oil spill for which such person would be statutorily responsible in an amount that depends on the risk represented by the quantity or quality of oil handled by such facility. The BSEE has promulgated regulations that implement the financial responsibility requirements of the OPA. A failure to comply with the OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil, administrative and/or criminal enforcement actions. There has also been a call from public interest groups, certain governmental officials and the National Commission on the BP Deepwater Horizon Spill and Offshore Drilling for, among other things, increased government oversight of the offshore oil and gas industry, to require more comprehensive financial assurance requirements, to raise or eliminate the economic damages liability cap under OPA, significantly raise daily penalties for OPA infractions and make the environmental review process more stringent. If adopted, certain of these proposals have the potential to adversely affect our operations by restricting areas in which we may carry out exploration or development activities and/or causing us to incur increased operating expenses. We have identified certain unencumbered assets in the U.S. Gulf of Mexico to the BOEM in order to demonstrate $100 million of Oil Spill Financial Responsibility through self-insurance under the Oil Pollution Act of 1990.

Clean Water Act

        The U.S. Federal Water Pollution Control Act of 1972, or Clean Water Act, as amended ("CWA"), imposes restrictions and controls on the discharge of pollutants, produced waters and other oil and natural gas wastes into waters of the U.S. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Under the CWA, permits must be obtained to discharge pollutants into regulated waters. In addition, certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into certain coastal and offshore waters. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges of oil and other hazardous substances and imposes liability on parties responsible for those discharges for the costs of cleaning up related damage and for natural resource damages resulting from the release. Comparable state statutes impose liabilities and authorize penalties in the case of an unauthorized discharge of petroleum or its derivatives, or other hazardous substances, into state waters.

Marine Protected Areas

        Executive Order 13158, issued in 2000, directs federal agencies to safeguard existing Marine Protected Areas ("MPAs") in the U.S. and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the U.S. Environmental Protection Agency ("EPA") to propose regulations under the CWA to ensure appropriate levels of protection for the marine environment. This order and related CWA regulations have the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.

Consideration of Environmental Issues in Connection with Governmental Approvals

        Our operations frequently require licenses, permits and other governmental approvals. Several federal statutes, including the Outer Continental Shelf Lands Act ("OCSLA"), the National Environmental Policy Act ("NEPA"), and the Coastal Zone Management Act ("CZMA") require federal agencies to evaluate environmental issues in connection with granting such approvals or taking other major agency actions. OCSLA, for instance, requires the DOI to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment,

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and gives the DOI authority to refuse to issue, suspend or revoke permits and licenses allowing such activities in certain circumstances, including when there is a threat of serious harm or damage to the marine, coastal or human environment. Similarly, NEPA requires DOI and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency must prepare an environmental assessment and, potentially, an environmental impact statement. If such NEPA documents are required, the preparation of such could significantly delay the permitting process and involve increased costs. CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development. In obtaining various approvals from the DOI, we will have to certify that we will conduct our activities in a manner consistent with any applicable CZMA program. Violation of these foregoing requirements may result in civil, administrative or criminal penalties.

Naturally Occurring Radioactive Materials

        Wastes containing naturally occurring radioactive materials ("NORM") may also be generated in connection with our operations. Certain oil and natural gas exploration and production activities may enhance the radioactivity, or the concentration, of NORM. In the U.S., NORM is subject to regulation primarily under individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration. These regulations impose certain requirements concerning worker protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; and restrictions on the uses of land with NORM contamination.

Resource Conservation and Recovery Act

        The U.S. Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently exempt from RCRA's requirements pertaining to hazardous waste and are regulated under RCRA's non-hazardous waste and other regulatory provisions. A similar exemption is contained in many of the state counterparts to RCRA. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Accordingly, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we expect to generate some amounts of ordinary industrial wastes, such as waste solvents and waste oils, that may be regulated as hazardous wastes.

Air Pollution Control

        The U.S. Clean Air Act ("CAA") and state air pollution laws adopted to fulfill its mandates provide a framework for national, state, regional and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants subject to the CAA and other pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. Regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA or other air pollution laws and regulations, including the suspension or termination of permits and monetary fines. Recently, the EPA also proposed new air regulations for oil and gas exploration, production, transmission and storage. These include new source performance standards for volatile organic compounds and sulfur dioxide and air toxics standards issued in April 2012. These regulations could require us to incur additional expenses to control air emissions by installing emissions control technologies and adhering to a variety of work practice and other requirements.

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Superfund

        The U.S. Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), also known as "Superfund," imposes joint and several liability for response costs at certain contaminated properties and damages to natural resources, without regard to fault or the legality of the original act, on some classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or past owner or operator of the site where the release occurred and anyone who transported, disposed or arranged for the disposal of a hazardous substance at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur and seek natural resource damages.

Protected Species and Habitats

        The federal U.S. Endangered Species Act, the federal Marine Mammal Protection Act, and similar federal and state wildlife protection laws prohibit or restrict activities that could adversely impact protected plant and animal species or habitats. Oil and natural gas exploration and production activities could be prohibited or delayed in areas where protected species or habitats may be located, or expensive mitigation may be required to accommodate such activities.

Climate Change

        Our operations and the combustion of petroleum and natural gas-based products results in the emission of greenhouse gases ("GHG") that could contribute to global climate change. Climate change regulation has gained momentum in recent years internationally and domestically at the federal, regional, state and local levels. Various U.S. regions and states have already adopted binding climate change legislation. In addition, the U.S. Congress has at times considered the passage of laws to limit the emission of GHGs. In 2009, the U.S. House of Representatives passed, and the U.S. Senate considered but did not pass, legislation that proposed, among other things, a nationwide cap on carbon dioxide and other GHG emissions and a requirement that certain emitters of GHGs, including certain electricity generators and producers and importers of specified fuels, obtain "emission allowances" to meet that cap. It is possible that federal legislation related to GHG emissions will be considered by Congress in the future.

        The EPA has issued final and proposed regulations pursuant to the CAA to limit carbon dioxide and other GHG emissions. Under EPA regulations finalized in May 2010 (referred to as the "Tailoring Rule"), the EPA began regulating GHG emissions from certain stationary sources in January 2011. Additionally, on April 1, 2010 and August 28, 2012, the EPA and the National Highway Traffic Safety Administration finalized GHG emissions standards for light-duty vehicles for model years 2012 through 2016 and 2017 through 2025, respectively. On August 9, 2011, these two agencies also announced national efficiency and emissions standards for medium- and heavy-duty engines and vehicles.

        On September 22, 2009, the EPA issued a "Mandatory Reporting of Greenhouse Gases" final rule ("Reporting Rule"). The Reporting Rule establishes a comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually on a facility-by-facility basis. On November 9, 2010, the EPA expanded the Reporting Rule to certain oil and natural gas facilities, including producers and offshore exploration and production operations. Each of these laws could adversely affect us directly as well as indirectly, as they could decrease the demand for oil and natural gas.

        On the international level, various nations, including Angola and Gabon, have committed to reducing their GHG emissions pursuant to the Kyoto Protocol. The Kyoto Protocol was set to expire in 2012. In late 2011, an international climate change conference in Durban, South Africa resulted in,

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among other things, an agreement to negotiate a new climate change regime by 2015 that would aim to cover all major greenhouse gas emitters worldwide, including the U.S., and take effect by 2020. In November and December 2012, at an international meeting held in Doha, Qatar, the Kyoto Protocol was extended by amendment until 2020. In addition, the Durban agreement to develop the protocol's successor by 2015 and implement it by 2020 was reinforced. U.S. federal climate change legislation or regulation or climate change legislation or regulation in other regions in which we conduct business could have an adverse effect on our results of operations, financial condition and demand for oil and natural gas.

Health and Safety

        Our operations are and will be subject to the requirements of the federal U.S. Occupational Safety and Health Act ("OSH Act") and comparable foreign and state statutes. These laws and their implementing regulations strictly govern the protection of the health and safety of employees. In particular, the OSH Act hazard communication standard, EPA community right-to-know regulations under Title III of the Superfund Amendments and Reauthorization Act of 1986 and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Such laws and regulations also require us to ensure our workplaces meet minimum safety standards and provide for compensation to employees injured as a result of our failure to meet these standards as well as civil and/or criminal penalties in certain circumstances.

Other Regulation of the Oil and Gas Industry

        The oil and gas industry is regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry may increase our cost of doing business by increasing the future cost of transporting our production to market, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Homeland Security Regulations

        The Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security ("DHS") to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and natural gas facilities that are deemed to present "high levels of security risk." The DHS is currently in the process of adopting regulations that will determine whether our operations may in the future be subject to DHS-mandated security requirements. Presently, it is not possible to accurately estimate the costs we could incur, directly or indirectly, to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Development and Production

        Development and production operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds in connection with various types of activities and filing reports concerning operations. U.S. laws under which we operate may also regulate one or more of the following:

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the location of wells;

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the method of drilling and casing wells;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells; and

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notice to surface owners and other third parties.

Regulation of Transportation and Sale of Natural Gas

        The availability, terms and cost of transportation significantly affect sales of natural gas. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. The FERC's regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. Upon us reaching the production stage of our business model, such regulations will be applicable to us.

        Although gas prices are currently unregulated, Congress historically has been active in the area of gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

U.S. Coast Guard and the U.S. Customs Service

        The transportation of drilling rigs to the sites of our prospects in the U.S. Gulf of Mexico and our operation of such drilling rigs is subject to the rules and regulations of the U.S. Coast Guard and the U.S. Customs Service. Such regulation sets safety standards, authorizes investigations into vessel operations and accidents and governs the passage of vessels into U.S. territory. We are required by these agencies to obtain various permits, licenses and certificates with respect to our operations.

Laws and Regulations of Angola and Gabon

        Our exploration and production activities offshore Angola and Gabon are subject to Angolan and Gabonese regulations, respectively. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase our costs or affect our operations. We have engaged third party consultants to assist us with our compliance efforts in Angola. The following are summaries of certain applicable regulatory frameworks in Angola and Gabon.

Angola

        In Angola, petroleum exploration and development activities are governed by the Petroleum Activities Law (the "Angola PAL"). Pursuant to the Angola PAL, all hydrocarbons located underground are property of the State of Angola, and exploitation rights can only be granted by the President of the Republic to Sonangol, as the national concessionaire. Foreign companies may only engage in petroleum activities in Angola in association with Sonangol through a commercial company or consortium, and generally upon entering a production sharing contract or a risk services agreement.

        The Angolan PAL and the regulations thereunder extensively regulate the activities of oil and gas companies operating in Angola, including financial and insurance requirements, local content and involvement requirements, exploration and development processes, and operational matters. Local content regulations stipulate which goods or services relating to the oil and gas industry must be provided by Angolan companies (being companies which are beneficially owned in their majority by

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Angolan citizens), whether on a sole basis or in association with foreign contractors, and which goods or services may be provided by foreign companies. Goods or services which may be provided by foreign companies are generally subject to a local preference rule, whereby Angolan companies are granted preference in tendering for such activities or services, provided that the price difference in such tender does not exceed 10% of the total tendered amount. The power to make many of the day-to-day decisions concerning petroleum activities, including the granting of certain consents and authorizations, is vested with Sonangol.

        The petroleum agreements entered with Sonangol set forth the main provisions for exploration and production activities, including fiscal terms, mandatory State participation, obligations to meet domestic supply requirements, local training and spending obligations, and ownership of assets used in petroleum operations. Angolan law and these agreements also contain important limitations on assignment of interests in such licenses, including in most cases the need to obtain the consent of Angolan authorities.

        Certain industry-specific and general application statutes and regulations govern health, safety and environmental matters under Angolan law. Prior to commencing petroleum operations in Angola, contractors must, among other things, prepare an environmental impact assessment and establish and implement a health and safety plan. Such environmental laws govern the disposal of by-products from petroleum operations and required oil spill preparedness capabilities. Failure to comply with these laws may result in civil and criminal liability, including, without limitation, fines or penalties.

        Angola enacted a new Foreign Exchange Law for the Petroleum Sector in 2012, Law N? 2/12, of January 13, 2012, which requires, among other things, that all foreign exchange operations be carried out through Angolan banks, that oil and gas companies open local bank accounts in foreign currencies in order to pay local taxes and pay for goods and services supplied by non-resident suppliers and service providers, and also that oil and gas companies open local bank accounts in local currency in order to pay for goods and services supplied by resident suppliers and service providers. As a consequence, foreign currency proceeds obtained by oil and gas companies from the sale of their share of production cannot be retained in full outside Angola, as a portion of the proceeds required to settle tax liabilities and pay for local petroleum operations-related expenses must be deposited in and paid through Angolan banks. Furthermore, oil and gas companies without production in Angola (such as ourselves) will be required to convert funds into local currency and deposit such funds in local banks in order pay for local petroleum operations-related expenses. The Foreign Exchange Law for the Petroleum Sector was further supplemented by Banco Nacional de Angola's Order 20/2012, of April 25, 2012, which details the procedures and mechanisms that must be adopted by oil and gas companies and sets forth a schedule for their phased implementation. Under the new statute, since October 1, 2012, oil companies (including operators) are required to make all payments for goods and services supplied by foreign exchange residents (as defined in the Foreign Exchange Law) out of bank accounts domiciled in Angola, whether in national or foreign currency. As of July 1, 2013, oil and gas exploration and production companies (including operators) will be required to make all payments for goods and services provided by foreign exchange residents in local currency. From October 1, 2013 onwards, operators will have to make all payments for goods and services related to Angolan operations provided by non-residents out of bank accounts domiciled in Angola. See "Risk Factors—Risk Related to Our Business—Participants in the oil and gas industry are subject to complex laws that can affect the cost, manner or feasibility of doing business."

Gabon

        In Gabon, exploration and development activities are governed by the Law on Petroleum Exploration and Production Activities. Petroleum resources in Gabon are the property of the State of Gabon and petroleum companies undertake operations on behalf of the Government of Gabon. In order to conduct petroleum operations, oil and gas companies must enter into a petroleum agreement,

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typically a production sharing contract ("PSC"), with the Ministries of Petroleum, Finance and Domains. Such agreement must approved by the Gabon legislature.

        A number of other regulations deal with other matters regarding petroleum activities such as taxes, charges, customs, State participation, petroleum exports, local content, training, foreign exchange, safety and environment. Recent changes to local content regulations generally require a ⁹⁰/10 ratio of Gabon national to foreign expatriate workers involved in petroleum activities. The powers to make many of the day-to-day decisions concerning petroleum activities, including the granting of certain consents and authorizations, are vested with the Hydrocarbons General Directorate, a government authority. In addition, a national oil company—Société Nationale des Hydrocarbures du Gabon—has recently been created to hold, manage and take participations in petroleum activities on behalf of the State.

        Petroleum agreements, including PSCs, set forth the main provisions for exploration and production activities, including obligations to meet domestic supply requirements, mandatory State participation; fiscal terms such as production sharing, royalty, bonuses and other charges, limitations on the number of foreign nationals to be employed, local training and spending obligations, and ownership of assets used in petroleum operations. There are important limitations on assignment of interests in a petroleum agreement, including the need to obtain the consent of Gabonese authorities.

        Gabon's legislature is considering the enactment of the Hydrocarbons Code, a more comprehensive law governing exploration and development activities in Gabon. Such law is expected to become effective in the near future. However, as a draft of this law has not yet been disclosed publicly, we are unable to determine its contents or likely impact. There can be no assurance that this new law will not materially adversely impact our licenses in Gabon or rights under Gabonese law.

EMPLOYEES

        As of December 31, 2012, we had 126 employees. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory. In addition, as of December 31, 2012, we had 105 contractors, consultants and secondees working in our offices and field locations.

CORPORATE INFORMATION

        We were incorporated pursuant to the laws of the State of Delaware as Cobalt International Energy, Inc. in August 2009 to become a holding company for Cobalt International Energy, L.P. Cobalt International Energy, L.P. was formed as a limited partnership on November 10, 2005 pursuant to the laws of the State of Delaware. Pursuant to the terms of a corporate reorganization that we completed in connection with our initial public offering, all of the interests in Cobalt International Energy, L.P. were exchanged for common stock of Cobalt International Energy, Inc. and, as a result, Cobalt International Energy, L.P. is wholly-owned by Cobalt International Energy, Inc.

AVAILABLE INFORMATION

        We make certain filings with the Securities and Exchange Commission ("SEC"), including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, http://www.cobaltintl.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. Our press releases and recent analyst presentations are also available on our website. The information on our website does not constitute a part of this Annual Report on Form 10-K.

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EXECUTIVE OFFICERS

        The following table sets forth certain information concerning our executive officers as of the date of this Annual Report.

Name	Age		Position
Joseph H. Bryant		57	Chairman of the Board of Directors and Chief Executive Officer
Van P. Whitfield		61	Chief Operating Officer
John P. Wilkirson		55	Chief Financial Officer and Executive Vice President
James H. Painter		55	Executive Vice President, Gulf of Mexico
Michael D. Drennon		57	Executive Vice President, West Africa
James W. Farnsworth		58	Chief Exploration Officer
Jeffrey A. Starzec		36	Senior Vice President and General Counsel
Lynne L. Hackedorn		54	Vice President, Government and Public Affairs
Richard A. Smith		53	Vice President, Investor Relations, Compliance and Risk Management

Biographical Information

Joseph H. Bryant has served as Chief Executive Officer and Chairman of our Board of Directors since our inception in November 2005. Mr. Bryant has 35 years of experience in the oil and gas industry. Prior to joining Cobalt, from September 2004 to September 2005, he was President and Chief Operating Officer of Unocal Corporation, an oil and gas exploration and production company. From May 2000 to August 2004, Mr. Bryant was President of BP Exploration (Angola) Limited, from January 1997 to May 2000, Mr. Bryant was President of BP Canada Energy Company (including serving as President of Amoco Canada Petroleum Co. between January 1997 and May 2000, prior to its merger with BP Canada), and from 1993 to 1996, Mr. Bryant served as President of a joint venture between Amoco Orient Petroleum Company and the China National Offshore Oil Corporation focused on developing the offshore Liuhua fields. Prior to 1993, Mr. Bryant held executive leadership positions in Amoco Production Company's business units in The Netherlands and the Gulf of Mexico, serving in many executive capacities and in numerous engineering, financial and operational roles throughout the continental United States. Mr. Bryant served on the board of directors of Berry Petroleum Company from October 2005 until May 2011. Mr. Bryant currently also serves on the board of directors of the American Petroleum Institute. Mr. Bryant holds a Bachelor of Science in Mechanical Engineering from the University of Nebraska.

Van P. Whitfield has served as Chief Operating Officer since September 2011. Mr. Whitfield served as our Executive Vice President, Operations and Development from May 2006 until September 2011. Mr. Whitfield has over 38 years of experience leading oil and gas production operations and marketing activities in North America, the United Kingdom and Europe, the Middle East and Asia. Prior to joining Cobalt, from May 2003 to May 2005, Mr. Whitfield served as Senior Vice President, Western Operations of CDX Gas LLC, an independent oil and gas company. From October 2002 to April 2003 he served as Production Unit Leader for the Angola Liquid Natural Gas Project, BP Exploration (Angola) Limited and from June 2001 to October 2002, he held the position of Vice President, Power and Water of ExxonMobil Saudi Arabia (Southern Ghawar) Ltd, an exploration and production company. Mr. Whitfield has also held the positions of Senior Vice President of BP Global Power, President and General Manager of Amoco Netherlands BV and Production Manager of Amoco (U.K.) Exploration Company, both exploration and production companies. In addition, he has held numerous operational and technical leadership positions in various Amoco Production Company locations, including: the position of Production Manager, West Texas and Engineering Manager, Worldwide. Mr. Whitfield has a Bachelor of Science Degree—Petroleum Engineering from Louisiana State University and is a graduate of the Executive Program at Stanford University.

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John P. Wilkirson has served as Executive Vice President and Chief Financial Officer since June 2010. From 2007 until June 2010, Mr. Wilkirson served as our Vice President, Strategic Planning and Investor Relations. Mr. Wilkirson has 32 years of experience in the energy industry. Prior to joining Cobalt, from 1998 to 2005, Mr. Wilkirson was Vice President, Strategic Planning and Economics of Unocal Corporation, where his primary responsibilities included identifying and addressing major strategic issues, managing the global asset and investment portfolio, leading the economic analysis and evaluations function and overseeing performance management. He played an instrumental role as the integration executive for Unocal Corporation's merger into Chevron Corporation. Prior to Unocal Corporation, from 1992 to 1997, Mr. Wilkirson was an Engagement Manager at McKinsey & Company, Inc., a management consulting firm, serving energy clients on strategy and performance improvement engagements. Additional industry experience includes positions at Exxon Company USA from 1980 to 1984 and Sohio Petroleum Company and BP from 1984 to 1991, in petroleum engineering and commercial assignments. Mr. Wilkirson has a Bachelor of Science with Highest Honors in Petroleum Engineering and a Master of Business Administration from the University of Texas at Austin.

James H. Painter has served as Executive Vice President, Gulf of Mexico since our inception in November 2005. Mr. Painter has more than 33 years of experience in the oil and gas industry. Prior to joining Cobalt, from February 2004 to September 2005, Mr. Painter was the Senior Vice President of Exploration and Technology at Unocal Corporation. Prior to his position at Unocal Corporation (following the merger between Ocean Energy Inc. and Devon Energy Corporation), from April 2003 to October 2003, Mr. Painter served as the Vice President of Exploration at Devon Energy Corporation, an oil and gas exploration and production company. From January 1995 to April 2003, Mr. Painter served in various manager and executive positions at Ocean Energy Inc. (and its predecessor Flores and Rucks, Inc.) with his final position as Senior Vice President of Gulf of Mexico and International Exploration. Additional industry experience includes positions at Forest Oil Corporation, an independent oil and gas exploration and production company, Mobil Oil Corporation and Superior Oil Company, Inc. Mr. Painter holds a Bachelor of Science in Geology from Louisiana State University.

Michael D. Drennon has served as Executive Vice President, West Africa since April 2010 and has 36 years of industry experience. Prior to joining Cobalt, Mr. Drennon served as Vice President, Operations for Parker Drilling Company from 2005 until April 2010. Mr. Drennon's additional industry experience includes various executive positions at BP and Amoco in the United States, United Kingdom, China, Trinidad, Norway and Angola. Mr. Drennon received a Bachelor of Science Degree in Petroleum Engineering from Texas Tech University in 1977.

James W. Farnsworth has served as Chief Exploration Officer since our inception in November 2005. Mr. Farnsworth has had more than 28 years of experience in the oil and gas industry. From 2003 to 2005, Mr. Farnsworth held the position of Vice President of World-Wide Exploration and Technology, at BP p.l.c., a global energy company, responsible for BP p.l.c.'s global exploration business inclusive of North America, West Africa, North Africa, South America, Russia and the Far East. His prior positions at BP p.l.c., from 1983 to 2003, include: Vice President of North America Exploration; Vice President of Gulf of Mexico Exploration; Exploration Manager for Alaska; Deepwater Gulf of Mexico Production Manager for Non-operated Fields. Mr. Farnsworth has a Bachelor of Science Degree in Geology from Indiana University and a Masters of Science Degree in Geophysics from Western Michigan University.

Jeffrey A. Starzec has served as Senior Vice President and General Counsel since January 2012. Mr. Starzec also serves as our Corporate Secretary. From June 2009 until December 2011, Mr. Starzec served as our Associate General Counsel and Corporate Secretary. Prior to joining Cobalt, Mr. Starzec practiced corporate and securities law at Vinson & Elkins LLP from July 2006 until June 2009, where he represented a variety of energy companies, including Cobalt in connection with its strategic alliance with Total in the U.S. Gulf of Mexico. Mr. Starzec began his legal career at Baker Botts LLP in 2002

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and holds a Bachelor of Science in Economics from Duke University and a J.D. from Harvard Law School.

Lynne L. Hackedorn has served as Vice President, Government and Public Affairs since October 2011. Ms. Hackedorn served as our Vice President, Government, Public Affairs and Land from September 2010 until October 2011. From April 2006 until September 2010, Ms. Hackedorn served as our Vice President, Land. Ms. Hackedorn has over 28 years of experience in the oil and gas industry. Prior to joining Cobalt, from 2001 to 2006, Ms. Hackedorn served as Senior Landman at Hydro Gulf of Mexico, L.L.C., formerly Spinnaker Exploration Company, L.L.C., an oil and gas exploration and production company, handling a variety of land functions within both the shelf and deepwater areas of the Gulf of Mexico. From 1998 to 2001, Ms. Hackedorn held management positions within the offshore Gulf of Mexico regions of Sonat Exploration GOM, Inc. and El Paso Production GOM, Inc., both oil and gas exploration and production companies. From 1994 to 1998, Ms. Hackedorn was a Landman with Zilkha Energy Company, also an oil and gas exploration and production company. Ms. Hackedorn began her career as a Landman in 1984 at ARCO Oil and Gas Company, where she worked in the onshore South Texas region from 1984 until 1990, and then in the offshore Gulf of Mexico region from 1990 until 1994. Ms. Hackedorn currently also serves on the board of directors of National Ocean Industries Association. Ms. Hackedorn earned her Bachelor of Science in Petroleum Land Management from the University of Houston, graduating Magna Cum Laude.

Richard A. Smith has served as Vice President, Investor Relations, Compliance and Risk Management since December 2012. Mr. Smith previously served as Vice President, Investor Relations and Planning from October 2011 until December 2012. Mr. Smith served as Vice President, International Business Development, Commercial and Finance from September 2010 until October 2011. From October 2007 until September 2010, Mr. Smith served as our Vice President. Mr. Smith has over 30 years of oil and gas industry experience in North American and international markets. Prior to joining Cobalt, from September 2005 to September 2007, Mr. Smith was Vice President, Joint Venture Development Corporate Affairs for the BP Russia Offshore Strategic Performance Unit, an oil and gas exploration and production unit of BP. From February 2002 to August 2005, he held the position of Vice President and then Executive Director for BP Exploration (Angola) Limited, an oil and gas exploration and production company operating in Angola. Mr. Smith's additional industry experience includes leadership positions at various companies in the oil and gas industry operating in Azerbaijan, Georgia, Turkey, the United Kingdom, the United States and Canada. Mr. Smith holds a Bachelor of Commerce from the University of Calgary.

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Item 1A.    Risk Factors

You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this Annual Report on Form 10-K, including the consolidated financial statements and the related notes appearing at the end of this Annual Report on Form 10-K. If any of the following risks actually occurs, our business, business prospects, stock price, financial condition, results of operations or cash flows could be materially adversely affected. The risks below are not the only ones facing our company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. This Annual Report on Form 10-K also contains forward-looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of specific factors, including the risks described below.

Risks Relating to Our Business

We have no proved reserves and areas that we decide to drill may not yield oil in commercial quantities or quality, or at all.

        We have no proved reserves. Our asset portfolio consists of identified yet unproven prospects based on available seismic and geological information that indicates the potential presence of oil and discoveries with limited appraisal drilling or other well penetrations. The areas we decide to drill may not yield oil in commercial quantities or quality, or at all. Our current discoveries and many of our prospects are in various stages of evaluation that will require substantial additional analysis and interpretation. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. Exploratory wells have been drilled on a limited number of our prospects. Undue reliance should not be placed on our limited drilling results or any estimates of the characteristics of our prospects, including any derived calculations of our potential resources or reserves based on these limited results and estimates. Additional appraisal wells, other testing and production data from completed and producing wells will be required to fully appraise our discoveries, to better estimate their characteristics and potential resources and reserves and to ultimately understand the commerciality of our prospects. Accordingly, we do not know how many of our prospects will contain oil in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil is found on our prospects in commercial quantities, construction costs of oil pipelines or FPSO systems, as applicable, and transportation costs may prevent such prospects from being economically viable. We will require various regulatory approvals in order to develop and produce from any of our discoveries, which may not be forthcoming.

        Additionally, the analogies drawn by us from available data from other wells, more fully explored prospects or producing fields may not prove valid in respect of our drilling prospects. We may terminate our drilling program for a prospect if data, information, studies and previous reports indicate that the possible development of our prospect is not commercially viable and, therefore, does not merit further investment. If a significant number of our prospects do not prove to be successful, our business, financial condition and results of operations will be materially adversely affected.

        To date, there has been limited drilling which has targeted the pre-salt horizon in the deepwater offshore West Africa and the Inboard Lower Tertiary trend in the deepwater U.S. Gulf of Mexico, areas in which we intend to focus a substantial amount of our exploration efforts.

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Our discoveries remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and development.

        Our use of the term "discoveries" in this Annual Report on Form 10-K in relation to our exploration and appraisal efforts refers only to our existing four discoveries: North Platte, Heidelberg, Shenandoah, and Cameia, and is not intended to refer to (i) our exploration portfolio as a whole, (ii) prospects where drilling activities have not discovered hydrocarbons or (iii) our undrilled exploratory prospects. A discovery made by the initial exploratory well on a prospect does not ensure that we will ultimately develop or produce oil or gas from such prospect or that a development will be economically viable or successful. Following a discovery by an initial exploratory well, substantial additional evaluation, analysis and partner and regulatory approvals will need to be performed and obtained prior to official project sanction and development, which may include (i) the drilling of appraisal wells, (ii) the evaluation and analysis of well logs, reservoir core samples, fluid samples and the results of production tests from both exploratory and appraisal wells, and (iii) the preparation of a development plan which includes economic assumptions on the costs of drilling development wells, and the construction or leasing of offshore production facilities and transportation infrastructure. Regulatory approvals are also required to proceed with certain development plans. Any of the foregoing steps of evaluation and analysis may render a particular discovery uneconomic and we may ultimately decide to abandon the prospect, despite the fact that the initial exploratory well, or subsequent appraisal wells, discovered hydrocarbons. We may not be successful in obtaining partner or regulatory approvals to develop a particular discovery, which could prevent us from proceeding with development and ultimately producing oil or gas from such discovery, even if we believe a development would be economically successful.

Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

        Exploring for and developing oil reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploratory wells bear a much greater risk of financial loss than development wells. In the past we have experienced unsuccessful drilling efforts. Moreover, the successful drilling of an oil well does not necessarily result in a profit on investment. Most of the wells we plan to operate or participate in in the near term are exploratory wells. A variety of factors, both geological and market-related, can cause a well to become uneconomic or only marginally economic. Our initial drilling sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. Due to a general lack of infrastructure and, in the case of offshore Angola and Gabon, underdeveloped oil and gas industries and increased transportation expenses due to geographic remoteness, which either require a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development of a commercially viable field we face additional risks in the Lower Tertiary Trend in the U.S. Gulf of Mexico and offshore Angola and Gabon. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

        We contract with third parties to conduct drilling and related services on our prospects for us. Such third parties may not perform the services they provide us on schedule or within budget. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third

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parties we contract with is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business, financial position and results of operations.

The high cost or unavailability of drilling rigs, equipment, personnel, oil field services and infrastructure could adversely affect our ability to execute our exploration and development plans on a timely basis and within budget.

        Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel, often during periods of higher oil prices or in emerging areas of exploration. During these periods and within these areas, the costs of drilling rigs, equipment, supplies and personnel are substantially greater and their availability may be limited. Additionally, these services may not be available on commercially reasonable terms. The high cost or unavailability of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within budget, which could have a material adverse effect on our business, financial condition or results of operations.

        Our ability to produce hydrocarbons will depend substantially on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Additionally, such infrastructure may not be available on commercially reasonable terms. We may be required to shut in oil wells because of the absence of a market or because access to pipelines, gathering systems or processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market, which could have a material adverse effect on our business, financial condition or results of operations.

Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to develop our exploration and production plans.

        We expect our capital outlays and operating expenditures to increase substantially over at least the next several years as we expand our operations. Exploration and production plans and obtaining additional leases or concessional licenses and seismic data are very expensive, and we expect that we will need to raise substantial additional capital, through future private or public equity offerings, strategic alliances or debt financing, before we achieve commercialization of any of our properties.

        Our future capital requirements will depend on many factors, including:

•

the scope, rate of progress and cost of our exploration and production activities;

•

the extent to which we invest in additional oil leases or concessional licenses;

•

oil and natural gas prices;

•

our ability to locate and acquire hydrocarbon reserves;

•

our ability to produce oil or natural gas from those reserves;

•

the terms and timing of any drilling and other production-related arrangements that we may enter into;

•

the cost and timing of governmental approvals and/or concessions; and

•

the effects of competition by other companies operating in the oil and gas industry.

        While we believe our operations will be adequately funded at least through 2014, we do not currently have any commitments for future external funding and we do not expect to generate any

44

revenue from production for several years. Additional financing may not be available on favorable terms, or at all. Even if we succeed in selling additional securities to raise funds, at such time the ownership percentage of our existing stockholders could be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm-out interests in our leases or licenses, we would dilute our ownership interest subject to the farm-out and any potential value resulting therefrom, and we may lose operating control over such prospects.

        In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. Assuming we are able to commence exploration and production activities or successfully exploit our properties during the primary license term, our licenses over the developed areas of a prospect could extend beyond the primary term, generally for the life of production. However, unless we make and declare discoveries within certain time periods specified in the documents governing our licenses, our interests in either the undeveloped parts of our license areas (as is the case in Angola and Gabon) or the whole block (as is the case in the deepwater U.S. Gulf of Mexico) may be forfeited, we may be subject to significant penalties or be required to make additional payments in order to maintain such licenses. The costs to maintain licenses may fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such licenses on commercially reasonable terms or at all. If we are not successful in raising additional capital, we may be unable to continue our exploration and production activities or successfully exploit our properties, and we may lose the rights to develop these properties upon the expiration of our licenses.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

        Our management team has identified and scheduled drilling locations on our acreage over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital and equipment, qualified personnel, seasonal conditions, regulatory approvals, oil prices, costs and drilling results. The final determination on whether to drill any of these drilling locations will be dependent upon the factors described elsewhere in this Annual Report on Form 10-K as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce oil from these or any other potential drilling locations. As such, our actual drilling activities may be materially different from our current expectations, which could adversely affect our results of operations and financial condition.

We are not, and may not be in the future, the operator on all of our prospects, and do not, and may not in the future, hold all of the working interests in our prospects. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and to an extent, any non-wholly owned, assets.

        Currently, we are not the operator on approximately 25% of our deepwater U.S. Gulf of Mexico blocks, and we are not the operator on the Diaba Block offshore Gabon. As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future prospects that result in a greater proportion of our prospects being operated by others. In addition, the terms of our current or future licenses or leases may require at least the majority of working interests to approve certain actions. As a result, we may have limited ability to exercise influence over the operations of the prospects operated by our partners or which are not wholly-owned by us, as the case may be. Dependence on the operator or our partners could prevent us from realizing our target returns for those prospects. Further, it may be difficult for us to pursue one of our key

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business strategies of minimizing the cycle time between discovery and initial production with respect to prospects for which we do not operate or wholly-own. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

•

the timing and amount of capital expenditures;

•

the operator's expertise and financial resources;

•

approval of other participants in drilling wells;

•

selection of technology; and

•

the rate of production of reserves, if any.

        Furthermore, even though we are the operator of Blocks 9, 20 and 21 offshore Angola, we are required to obtain the prior approval of Sonangol for most of our operational activities. This limited ability to exercise control over the operations of some of our prospects may cause a material adverse effect on our results of operations and financial condition.

The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results.

        We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or lease partners. If any of our partners in the blocks or leases in which we hold interests are unable to fund their share of the exploration and development expenses, we may be liable for such costs. In addition, if any of the service providers we contract with to mature our prospects or develop our discoveries file for bankruptcy or are otherwise unable to fulfill their obligations to us, we may face increased costs and delays in locating replacement vendors. The inability or failure of third parties we contract with to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

We are a development stage enterprise and our future performance is uncertain.

        We are a development stage enterprise and will continue to be so until commencement of substantial production from our properties, which will depend upon our ability to conduct drilling operations, successful drilling results, additional and timely capital funding, and access to suitable infrastructure and adequate personnel. We do not expect to commence production for at least several years, and therefore we do not expect to generate any revenue from production for a long time. Companies in their initial stages of development face substantial business risks and may suffer significant losses. We have generated substantial net losses and negative cash flows from operating activities since our inception and expect to continue to incur substantial net losses as we continue our drilling program and develop our discoveries. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. In the event that our drilling schedules are not completed, or are delayed or terminated, our operating results will be adversely affected and our operations will differ materially from the activities described in this Annual Report on Form 10-K. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition.

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We are dependent on certain members of our management and technical team and our inability to retain or recruit qualified personnel may impair our ability to grow our business.

        Our investors must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, discovering and developing oil reserves. Our performance and success are dependent, in part, upon key members of our management and technical team, and their loss or departure could be detrimental to our future success. You must be willing to rely to a significant extent on our management's discretion and judgment. The vast majority of our senior management and technical team's equity in us will vest and their employment agreements will expire prior to January 1, 2015. In addition, a significant portion of our employee base is at or near retirement age. Furthermore, we utilize the services of a number of individual consultants for contractually fixed periods of time. Our inability to retain or recruit qualified personnel may impair our ability to grow our business and develop our discoveries, which could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects.

        In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified in our various license agreements and leases, our interests in the undeveloped parts of our license (as is the case in Angola and Gabon) or the whole block (as is the case in the deepwater U.S. Gulf of Mexico) areas may lapse and we may be subject to significant penalties or be required to make additional payments in order to maintain such licenses. For example, under the Risk Services Agreements for Blocks 9 and 21 offshore Angola, in order to preserve our rights in these blocks, we will be required to drill three and four wells, respectively, within four years of the signing of the Risk Services Agreements, or early 2014, subject to certain extensions. Under the PSC for Block 20 offshore Angola, in order to preserve our rights in the block, we will be required to drill four exploratory wells within five years of the signing of the PSC, or late 2016, subject to certain extensions. In addition, most of our deepwater U.S. Gulf of Mexico blocks have a 10-year primary term, expiring between 2016 and 2020. Generally, we are required to commence exploration activities or successfully exploit our properties during the primary lease term in order for these leases to extend beyond the primary lease term. Accordingly, we may not be able to drill all of the prospects we have identified on our leases or licenses prior to the expiration of their respective terms. Should the prospects we have identified under the licenses or leases currently in place yield discoveries, we cannot assure you that we will not face delays in drilling these prospects or otherwise have to relinquish these prospects. The costs to maintain licenses over such areas may fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such licenses on commercially reasonable terms or at all. Our actual drilling activities may therefore materially differ from our current expectations, which could adversely affect our business. For each of our blocks and license areas, we cannot assure you that any renewals or extensions will be granted or whether any new agreements or leases will be available on commercially reasonable terms, or, in some cases, at all.

A substantial or extended decline in oil prices may adversely affect our business, financial condition and results of operations.

        The price that we will receive for our oil production will significantly affect our revenue, profitability, access to capital and future growth rate. The market price of oil affects the valuation of our business and price of our common stock despite the fact that we currently do not produce or sell

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oil. Historically, the oil markets have been volatile and will likely continue to be volatile in the future. Oil prices depend on numerous factors. These factors include, but are not limited to, the following:

•

changes in supply and demand for oil and natural gas;

•

the actions of the Organization of the Petroleum Exporting Countries;

•

the price and quantity of imports of foreign oil and natural gas;

•

speculation as to the future price of oil and the speculative trading of oil futures contracts;

•

global economic conditions;

•

political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activities, particularly in the Middle East, Africa, Russia and South America;

•

the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

•

the level of global oil exploration and production activity;

•

the level of global oil inventories and oil refining capacities;

•

weather conditions and other natural disasters;

•

technological advances affecting energy consumption;

•

domestic and foreign governmental regulations;

•

proximity and capacity of oil pipelines and other transportation facilities;

•

the price and availability of competitors' supplies of oil; and

•

the price and availability of alternative fuels.

        Oil prices have fluctuated dramatically in recent times and will likely continue to be volatile in the future. Lower oil prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil that we can produce economically. A substantial or extended decline in oil prices may materially and adversely affect our future business, financial condition, the market price of our common stock, results of operations, liquidity or ability to finance planned capital expenditures.

We are subject to numerous risks inherent to the exploration and production of oil.

        Oil exploration and production activities involve many risks that a combination of experience, knowledge and careful evaluation may not be able to overcome. Our future success will depend on the success of our exploration and production activities and on the future existence of the infrastructure that will allow us to take advantage of our findings. Additionally, our properties are located in deepwater, which generally increases the capital and operating costs, technical challenges and risks associated with exploration and production activities. As a result, our exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

        Furthermore, the marketability of expected production from our prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices, proximity, capacity and availability of pipelines, the availability of processing facilities, equipment availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, importing and exporting of hydrocarbons, environmental protection and climate

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change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.

        In the event that our drilling programs are developed and become operational, they may not produce hydrocarbons in commercial quantities or at the costs anticipated, and our projects may cease production, in part or entirely, in certain circumstances. Drilling programs may become uneconomic as a result of an increase in operating costs to produce hydrocarbons. Our actual operating costs may differ materially from our current estimates. Moreover, it is possible that other developments, such as increasingly strict environmental, health and safety laws and regulations and enforcement policies thereunder and claims for damages to natural resources, property or persons resulting from our operations, could result in substantial costs and liabilities, delays, an inability to complete our drilling programs or the abandonment of such drilling programs, which could cause a material adverse effect on our results of operations and financial condition.

We are subject to drilling and other operational hazards.

        The exploration and production business involves a variety of operating risks, including, but not limited to:

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blowouts, cratering and explosions;

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mechanical and equipment problems;

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uncontrolled flows or leaks of oil or well fluids, natural gas or other pollution;

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fires and gas flaring operations;

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marine hazards with respect to offshore operations;

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formations with abnormal pressures;

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pollution, other environmental risks and geological problems; and

•

weather conditions and natural disasters.

        These risks are particularly acute in deepwater drilling and exploration for natural resources. Any of these events could result in loss of human life, significant damage to property, environmental damage, impairment of our operations, delays in our drilling operations, increased costs and substantial losses. In accordance with customary industry practice, we expect to maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. The occurrence of any of these events, whether or not covered by insurance, could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

        We are members of several industry groups that provide general and specific oil spill and well containment resources in the U.S. Gulf of Mexico and offshore West Africa, including, but not limited to, the Helix Well Containment Group, Clean Gulf Associates, the Marine Preservation Association, and the National Response Corporation. Through these industry groups, as described under "Business—Containment Resources", we have contractual rights to access certain oil spill and well containment resources. We can make no assurance that these resources will perform as designed or be able to fully contain or cap any oil spill, blow-out or uncontrolled flow of hydrocarbons. Furthermore, our contracts for the use of oil spill and well containment resources contain strict indemnity provisions that generally require us to indemnify the contractor for all losses incurred as a result of assisting us in our oil spill and well containment efforts, subject to certain exceptions and limitations. In the event we experience a subsea blowout, explosion, fire, uncontrolled flow of hydrocarbons or any of the other operational risks identified above, the oil spill and well containment resources which we have contractual rights to will not prevent us from incurring losses or shield us from liability, which could be

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substantial and have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

Our operations will involve special risks that could adversely affect operations.

        Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt our operations. As a result, we could incur substantial expenses that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we do not carry, and have no plans to carry, business interruption insurance due to the fact that this is not economically viable, and therefore we may not be able to rely on insurance coverage in the event of such natural phenomena.

        Deepwater exploration generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Such risks are particularly applicable to our deepwater exploration efforts in the Lower Tertiary trend and pre-salt offshore Angola and Gabon, as there has been limited drilling activity in these areas. In addition, there may be production risks of which we are currently unaware. Whether we use existing pipeline infrastructure, participate in the development of new subsea infrastructure or use floating production systems to transport oil from producing wells, if any, these operations may require substantial time for installation, or encounter mechanical difficulties and equipment failures that could result in significant cost overruns and delays. Furthermore, deepwater operations generally, and operations in the Lower Tertiary and offshore West Africa trends in particular, lack the physical and oilfield service infrastructure present on the shelf. As a result, a significant amount of time may elapse between a deepwater discovery and the marketing of the associated hydrocarbons, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of this infrastructure, reserve discoveries we make in the deepwater, if any, may never be economically producible.

Our operations in the U.S. Gulf of Mexico may be adversely impacted by tropical storms and hurricanes.

        Tropical storms, hurricanes and the threat of tropical storms and hurricanes often result in the shutdown of operations in the U.S. Gulf of Mexico as well as operations within the path and the projected path of the tropical storms or hurricanes. In the future, during a shutdown period, we may be unable to access wellsites and our services may be shut down. Additionally, tropical storms or hurricanes may cause evacuation of personnel and damage to offshore drilling rigs and other equipment, which may result in suspension of our operations. The shutdowns, related evacuations and damage can create unpredictability in activity and utilization rates, as well as delays and cost overruns, which may have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

The geographic concentration of our properties in the U.S. Gulf of Mexico and offshore Angola and Gabon subjects us to an increased risk of loss of revenue or curtailment of production from factors specifically affecting the U.S. Gulf of Mexico and offshore Angola and Gabon.

        Our properties are concentrated in three countries: the U.S. Gulf of Mexico and offshore Angola and Gabon. Some or all of these properties could be affected should such regions experience:

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severe weather or natural disasters;

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moratoria on drilling or permitting delays;

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•

delays or decreases in production;

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delays or decreases in the availability of drilling rigs and related equipment, facilities, personnel or services;

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delays or decreases in the availability of capacity to transport, gather or process production; and/or

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changes in the regulatory, political and fiscal environment.

        For example, in response to the Deepwater Horizon incident, the U.S. government and its regulatory agencies with jurisdiction over oil and gas exploration, including the DOI and the BOEM and BSEE, imposed moratoria on drilling operations, required operators to reapply for exploration plans and drilling permits and adopted extensive new regulations, which effectively halted drilling operations in the deepwater U.S. Gulf of Mexico for a period of time. Additionally, oil and gas properties and facilities located in the U.S. Gulf of Mexico were significantly damaged by Hurricanes Katrina and Rita, which required our competitors to spend a significant amount of time and capital on inspections, repairs, debris removal, and the drilling of replacement wells. We maintain insurance coverage for only a portion of these risks. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. We do not carry business interruption insurance.

        Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

Regulations enacted as a result of the Deepwater Horizon drilling rig accident and resulting oil spill may have significantly increased certain of the risks we face and increased the cost of operations in the U.S. Gulf of Mexico.

        On April 20, 2010, the Transocean Deepwater Horizon, a semi-submersible offshore drilling rig operating in the deepwater U.S. Gulf of Mexico under contract to BP plc exploded, burned for two days and sank, resulting in loss of life, injuries and a large oil spill. The U.S. government and its regulatory agencies with jurisdiction over oil and gas exploration, including the DOI, BOEM and BSEE, responded to this incident by imposing moratoria on drilling operations and adopting numerous new regulations and new interpretations of existing regulations regarding operations in the U.S. Gulf of Mexico. Compliance with these new regulations has increased the cost of our drilling operations in the U.S. Gulf of Mexico.

        We believe that extensive new regulations, increased regulatory and legal scrutiny, the restructuring of the BOEM and BSEE as successors to each of the BOEMRE and the Minerals Management Service, and ongoing and potential third party legal challenges to industry drilling operations in the U.S. Gulf of Mexico could result in substantial delays to and adversely affect our exploration and appraisal drilling operations in the U.S. Gulf of Mexico, including the timing of the permitting process.

        The successful execution of our U.S. Gulf of Mexico business plan depends on our ability to continue our exploration and appraisal efforts. A prolonged suspension of or delay in our drilling operations would adversely affect our business, financial position or future results of operations.

        Furthermore, the Deepwater Horizon incident may have increased certain of the risks we face, including, without limitation, the following:

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increased governmental regulation and enforcement of our and our industry's operations in a number of areas, including health and safety, financial responsibility, environmental, licensing, taxation, equipment specifications and inspections and training requirements;

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increased difficulty in obtaining leases and permits to drill offshore wells, including as a result of any bans or moratoria placed on offshore drilling;

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potential legal challenges to the issuance of permits and the conducting of our operations;

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•

higher drilling and operating costs;

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higher royalty rates and fees on leases acquired in the future;

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higher insurance costs and increased potential liability thresholds under proposed legislation and regulations;

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decreased partner participation in wells we operate;

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higher capital costs as a result of any increase to the risks we or our industry face; and

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less favorable investor perception of the risk-adjusted benefits of deepwater offshore drilling.

        The occurrence of any of these factors, or their continuation, could have a material adverse effect on our business, financial position or future results of operations.

We face various risks associated with increased activism against oil and gas exploration and development activities.

        Opposition toward oil and gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as offshore drilling and development. For example, environmental activists have recently challenged lease sales and decisions to grant air-quality permits in the U.S. Gulf of Mexico for offshore drilling.

        Future activist efforts could result in the following:

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delay or denial of drilling permits;

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shortening of lease terms or reduction in lease size;

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restrictions or delays on our ability to obtain additional seismic data;

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restrictions on installation or operation of gathering or processing facilities;

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restrictions on the use of certain operating practices;

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legal challenges or lawsuits;

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damaging publicity about us;

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increased costs of doing business;

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reduction in demand for our products; and

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other adverse effects on our ability to develop our properties.

        Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations.

Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.

        Our oil exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract

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rights, foreign exchange restrictions, currency fluctuations, royalty and tax increases and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to civil strife, acts of war, guerrilla activities and insurrection. Some of these risks may be higher in the developing countries in which we conduct our activities, namely, Angola and Gabon.

        Our operations are exposed to risks of war, local economic conditions, political disruption, civil disturbance and governmental policies that may:

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disrupt our operations;

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restrict the movement of funds or limit repatriation of profits;

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in the case of our non-U.S. operations, lead to U.S. government or international sanctions; and

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limit access to markets for periods of time.

        Disruptions may occur in the future, and losses caused by these disruptions may occur that will not be covered by insurance. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material adverse effect on our financial condition and results of operations. Furthermore, in the event of a dispute arising from non-U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the U.S. or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the U.S., which could adversely affect the outcome of such dispute.

        Our operations may also be adversely affected by laws and policies of the jurisdictions, including Angola, Gabon, the United States, the Cayman Islands and other jurisdictions, in which we do business, that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof, could have a material adverse effect on our results of operations and financial position, as well as on the market price of our common stock.

The oil and gas industry, including the acquisition of exploratory acreage in the U.S. Gulf of Mexico and offshore West Africa, is intensely competitive.

        The international oil and gas industry, including in the U.S. Gulf of Mexico and West Africa, is highly competitive in all aspects, including the exploration for, and the development of, new sources of oil and gas. We operate in a highly competitive environment for acquiring exploratory acreage and hiring and retaining trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than us, which can be particularly important in the areas in which we operate. These companies may be able to pay more for productive or prospective oil properties and prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drill attempts, delays, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for available capital for investment in the oil and gas industry. As a result of these and other factors, we may not be able to compete successfully in an intensely competitive industry, which could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

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Participants in the oil and gas industry are subject to complex laws that can affect the cost, manner or feasibility of doing business.

        Exploration and production activities in the oil and gas industry are subject to extensive local, state, federal and international regulations. We may be required to make large expenditures to comply with governmental regulations, particularly in respect of the following matters:

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licenses and leases for drilling operations;

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foreign exchange and banking;

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royalty increases, including retroactive claims;

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drilling and development bonds and social payment obligations;

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reports concerning operations;

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the spacing of wells;

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unitization of oil accumulations;

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remediation or investigation activities for environmental purposes; and

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taxation.

        Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock.

        The SEC recently promulgated final rules under the Dodd-Frank Act requiring SEC reporting companies that engage in the commercial development of oil, natural gas or minerals, to disclose payments (including taxes, royalties, fees and other amounts) made by such companies or an entity controlled by such companies to the United States or to any non-U.S. government for the purpose of commercial development of oil, natural gas or minerals. Such disclosure will be made in a new public filing with the SEC starting in 2014 (and will cover the 2013 calendar year). The final rules do not contain an exception that would allow companies to exclude payments which may not be disclosed pursuant to foreign laws or confidentiality agreements. Accordingly, while we are working with our foreign partners and the governments of the foreign jurisdictions in which we conduct our oil and gas operations in preparation for these new reporting obligations, there can be no assurance that we will be able to comply with these regulations without creating disagreements with these partners or governments. Further, such regulations may place us at a disadvantage to our non-U.S. competitors in doing business in the international oil and gas industry. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

        Angola recently enacted a new Foreign Exchange Law for the Petroleum Sector, which requires, among other things, that all foreign exchange operations be carried out through Angolan banks, that oil and gas exploration and production companies open local bank accounts in foreign currencies in order to pay local taxes and pay for goods and services supplied by non-resident suppliers and service providers, and also that oil and gas exploration and production companies open local bank accounts in local currency in order to pay for goods and services supplied by resident suppliers and service providers. See "Business—Laws and Regulations of Angola and Gabon—Angola" for more information. As a consequence, any foreign currency proceeds we obtain from the sale of our share of oil and gas production in Angola cannot be retained in full outside Angola, as a portion of the

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proceeds required to settle tax liabilities and pay for local petroleum operations-related expenses must be deposited in and paid through Angolan banks. Furthermore, until we achieve oil and gas production in Angola, we will be required to convert funds into local Angolan currency and deposit such funds in local banks in order pay for our local petroleum operations-related expenses. There can be no assurance that a liquid foreign exchange market will develop in Angola or that we won't be adversely affected by foreign exchange rate fluctuations (which we may not be able to hedge against). In addition, in order to comply with this law and related regulations, we will be required to assess the residency status of our contractors in Angola to determine which rules apply to each specific contractor (whether they be resident contractors or non-resident contractors). We envision that these new rules will require additional compliance efforts and costs on our and other industry participants' part, and may in some cases cause delay or other issues in connection with the acquisition or payments for goods and services. Any of these consequences could have a material adverse effect on our results of operations.

We and our operations are subject to numerous environmental, health and safety regulations which may result in material liabilities and costs.

        We are, and our future operations will be, subject to various international, foreign, federal, state and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water, the generation, storage, handling, use and transportation of regulated materials and the health and safety of our employees. We are required to obtain various environmental permits from governmental authorities for our operations, including drilling permits for our wells. There is a risk that we have not been or will not be at all times in complete compliance with these permits and the environmental laws and regulations to which we are subject. If we violate or fail to comply with these laws, regulations or permits, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations. If we fail to obtain permits in a timely manner or at all (due to opposition from community or environmental interest groups, governmental delays, changes in laws or the interpretation thereof or any other reasons), such failure could impede our operations, which could have a material adverse effect on our results of operations and our financial condition.

        We, as the named lessee or as the designated operator under our current and future oil leases and licenses, could be held liable for all environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our third-party contractors. To the extent we do not address these costs and liabilities or if we are otherwise in breach of our lease or license requirements, our leases or licenses could be suspended or terminated. We have contracted with and intend to continue to hire third parties to perform the majority of the drilling and other services related to our operations. There is a risk that we may contract with third parties with unsatisfactory environmental, health and safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. Accordingly, we could be held liable for all costs and liabilities arising out of the acts or omissions of our contractors, which could have a material adverse effect on our results of operations and financial condition.

        As the designated operator of certain of our leases and licenses, we are required to maintain bonding or insurance coverage for certain risks relating to our operations, including environmental risks. We maintain insurance at levels that we believe are consistent with current industry practices, but we are not fully insured against all risks. Our insurance may not cover any or all environmental claims that might arise from our operations or those of our third-party contractors. If a significant accident or other event occurs and is not fully covered by our insurance, or our third-party contractors have not agreed to bear responsibility, such accident or event could have a material adverse effect on our results of operations and our financial condition. In addition, we may not be able to obtain required bonding or insurance coverage at all or in time to meet our anticipated startup schedule for each well, and if we

55

fail to obtain this bonding or coverage, such failure could have a material adverse effect on our results of operations and financial condition.

        Releases to deepwater of regulated substances are common, and under certain environmental laws, we could be held responsible for all of the costs relating to any contamination caused by us or our contractors, at our facilities and at any third party waste disposal sites used by us or on our behalf. These costs could be material. In addition, offshore oil exploration and production involves various hazards, including human exposure to regulated substances, including naturally occurring radioactive materials. As such, we could be held liable for any and all consequences arising out of human exposure to such substances or other damage resulting from the release of regulated substances to the environment, endangered species, property or to natural resources.

        Particularly since the Deepwater Horizon event in the U.S. Gulf of Mexico, there has been an increased interest in making regulation of deepwater oil and gas exploration and production more stringent in the U.S. If adopted, certain proposals such as a significant increase or elimination of financial liability caps for economic damages, could significantly raise daily penalties for infractions and require significantly more comprehensive financial assurance requirements under OPA could affect our results of operations and our financial condition.

        In addition, we expect continued attention to climate change issues. Various countries and U.S. states and regions have agreed to regulate emissions of greenhouse gases ("GHG"), including methane (a primary component of natural gas) and carbon dioxide, a byproduct of oil and natural gas combustion. Additionally, the U.S. Congress has in the past and may in the future consider legislation requiring reductions in GHG emissions. The EPA began regulating GHG emissions from certain stationary sources on January 2, 2011 and has enacted GHG emissions standards for certain classes of vehicles. The EPA has also adopted rules requiring the reporting of GHG emissions, including from certain offshore oil and natural gas production facilities on an annual basis. The regulation of GHGs and the physical impacts of climate change in the areas in which we, our customers and the end-users of our products operate could adversely impact our operations and the demand for our products.

        Environmental, health and safety laws are complex, change frequently and have tended to become increasingly stringent over time. Our costs of complying with current and future environmental, health and safety laws, and our liabilities arising from releases of, or exposure to, regulated substances may adversely affect our results of operations and our financial condition. See "Business—Environmental Matters and Regulation."

Non-U.S. holders of our common stock, in certain situations, could be subject to U.S. federal income tax upon the sale, exchange or other disposition of our common stock.

        Our assets consist primarily of interests in U.S. oil and gas properties (which constitute U.S. real property interests for purposes of determining whether we are a U.S. real property holding corporation) and interests in non-U.S. oil and gas properties, the relative values of which at any time may be uncertain and may fluctuate significantly over time. Therefore, we may be, now or at any time while a non-U.S. investor owns our common stock, a U.S. real property holding corporation. As a result, under the Foreign Investment in Real Property Tax Act ("FIRPTA"), certain non-U.S. investors may be subject to U.S. federal income tax on gain from the disposition of shares of our common stock, in which case they would also be required to file U.S. tax returns with respect to such gain. Whether these FIRPTA provisions apply depends on the amount of our common stock that such non-U.S. investors hold and whether, at the time they dispose of their shares, our common stock is regularly traded on an established securities market (such as the NYSE) within the meaning of the applicable Treasury Regulations. So long as our common stock is listed on the NYSE, only a non-U.S. investor who has held, actually or constructively, more than 5% of our common stock may be subject to U.S. federal income tax on the disposition of our common stock under FIRPTA.

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We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act, and any determination that we violated the U.S. Foreign Corrupt Practices Act could have a material adverse effect on our business.

        We are subject to the U.S. Foreign Corrupt Practices Act ("FCPA") and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business. We do business and may do additional business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, or private entities. Thus, we face the risk of unauthorized payments or offers of payments by one of our employees or consultants, given that these parties may not always be subject to our control. Our existing safeguards and any future improvements may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible.

        In connection with entering into our RSAs for Blocks 9 and 21 offshore Angola, two Angolan-based E&P companies were assigned as part of the contractor group by the Angolan government. We had not worked with either of these companies in the past, and, therefore, our familiarity with these companies was limited. In the fall of 2010, we were made aware of allegations of a connection between senior Angolan government officials and one of these companies, Nazaki Oil and Gáz, S.A. ("Nazaki"), which is a full paying member of the contractor group. In March 2011, the SEC commenced an informal inquiry into these allegations. To avoid non-overlapping information requests, we voluntarily contacted the U.S. Department of Justice ("DOJ") with respect to the SEC's informal request and offered to respond to any requests the DOJ may have. Since such time, we have been complying with all requests from the SEC and DOJ with respect to their inquiry. In November 2011, a formal order of investigation was issued by the SEC related to our operations in Angola. We are fully cooperating with the SEC and DOJ investigations, have conducted an extensive investigation into these allegations and believe that our activities in Angola have complied with all laws, including the FCPA. We cannot provide any assurance regarding the duration, scope, developments in, results of or consequences of these investigations.

        In the future, we may be partnered with other companies with whom we are unfamiliar. Violations of the FCPA may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the government may seek to hold us liable for successor liability FCPA violations committed by companies in which we invest or that we acquire.

We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage.

        We maintain insurance to protect us and our subsidiaries against losses arising out of our oil and gas operations. Our insurance includes coverage for operator's extra expense, physical damage to our offshore property, general (third party) liability, workers' compensation and employer's liability, seepage and pollution and other risks. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. Additionally, our insurance is subject to the terms, conditions and exclusions of such policies. We have various insurance coverages with individual policy limits ranging from $1.0 million to $500 million each, with most of our policy limits scaling to the working interest we have in our prospects. While we maintain insurance levels, deductibles and retentions that we believe are prudent and responsible, there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

        In general, our current insurance policies cover physical damage to our oil and gas assets. The coverage is designed to repair or replace assets damaged by insurable events.

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        Our excess liability policies generally provide coverage for bodily injury and property damage, including coverage for seepage and pollution. This liability coverage covers claims for bodily injury or death brought against us by or on behalf of individuals who are not our employees.

        Our energy insurance package includes coverage for operator's extra expense, which provides coverage for control of well, re-drill and pollution arising from a covered event. We have identified certain unencumbered assets in the U.S. Gulf of Mexico to the BOEM in order to demonstrate $100 million of Oil Spill Financial Responsibility through self-insurance under OPA. Additionally, as noted above, our excess liability policies provide coverage (dependent on the asset) for bodily injury and property damage, including coverage for negative environmental effects such as seepage and pollution. Legislation has been proposed to increase the limit of the Oil Spill Financial Responsibility policy required for the certificate and there is no assurance that we will be able to obtain this insurance should that happen.

        The occurrence of a significant accident or other event not fully covered by our insurance could have a material adverse effect on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third-party contractors and other service providers are used in our offshore operations, we may not realize the full benefit of worker's compensation laws in dealing with their employees. In addition, pollution and environmental risks generally are not fully insurable.

        Generally, under our contracts with drilling and other oilfield service contractors, we are obligated, subject to certain exceptions and limitations, to indemnify such contractors for all claims arising out of damage to our property, injury or death to our employees and pollution emanating from the well-bore, including pollution resulting from blow-outs and uncontrolled flows of hydrocarbons.

Our level of indebtedness may increase and thereby reduce our financial flexibility.

        In December 2012 we issued $1.38 billion aggregate principal amount of 2.625% convertible senior notes due 2019 (the "notes"). The notes do not contain restrictive covenants, and we may incur significant additional indebtedness in the future in order to make investments or acquisitions or to explore, appraise or develop our oil and natural gas assets. Our level of indebtedness could affect our operations in several ways, including the following:

•

a significant portion or all of our cash flows, if and when generated, could be used to service our indebtedness;

•

a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions;

•

a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing; and

•

a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

        A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, risks associated with exploring for and producing oil and natural gas, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our indebtedness and future working capital, borrowings or equity financing may not be available to pay or refinance such indebtedness. Factors that

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will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our performance at the time we need capital.

Conversions of the notes may adversely affect our financial condition and operating results.

        Holders of notes will be entitled to convert the notes at their option at any time up until the maturity date, being December 1, 2019. If one or more holders elect to convert their notes, unless we elect to satisfy our conversion obligation by delivering solely shares of our common stock (other than cash in lieu of any fractional share), we would be required to settle a portion or all of our conversion obligation through the payment of cash, which could adversely affect our liquidity. In addition, even if holders do not elect to convert their notes, we could be required under applicable accounting rules to reclassify all or a portion of the outstanding principal of the notes as a current rather than long-term liability, which would result in a material reduction of our net working capital.

The accounting method for convertible debt securities that may be settled in cash, such as the notes, is the subject of recent changes that could have a material effect on our reported financial results.

        In May 2008, the Financial Accounting Standards Board, which we refer to as FASB, issued FASB Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement), which has subsequently been codified as Accounting Standards Codification 470-20, Debt with Conversion and Other Options, which we refer to as ASC 470-20. Under ASC 470-20, an entity must separately account for the liability and equity components of the convertible debt instruments (such as the notes) that may be settled entirely or partially in cash upon conversion in a manner that reflects the issuer's economic interest cost. The effect of ASC 470-20 on the accounting for the notes is that the equity component is required to be included in the additional paid-in capital section of stockholders' equity on our consolidated balance sheet, and the value of the equity component would be treated as original issue discount for purposes of accounting for the debt component of the notes. As a result, we will be required to record a greater amount of non-cash interest expense in current periods presented as a result of the amortization of the discounted carrying value of the notes to their face amount over the term of the notes. We will report lower net income in our financial results because ASC 470-20 will require interest to include both the current period's amortization of the debt discount and the instrument's coupon interest, which could adversely affect our reported or future financial results, the trading price of our common stock and the trading price of the notes.

        In addition, convertible debt instruments like the notes that may be settled in cash, stock or a combination of cash and stock are currently accounted for utilizing the if converted method, the effect of which is that conversion will not be assumed for purposes of computing diluted earnings per share if the effect would be antidilutive. Under the if-converted method, for diluted earnings per share purposes, convertible debt is antidilutive whenever its interest, net of tax and nondiscretionary adjustments, per common share obtainable on conversion exceeds basic earnings per share. Dilutive securities that are issued during a period and dilutive convertible securities for which conversion options lapse, or for which related debt is extinguished during a period, will be included in the denominator of diluted earnings per share for the period that they were outstanding. Likewise, dilutive convertible securities converted during a period will be included in the denominator for the period prior to actual conversion. Moreover, interest charges applicable to the convertible debt will be added back to the numerator. We cannot be sure that the accounting standards in the future will continue to permit the use of the if converted method. If we are unable to use the if-converted method in accounting for the shares issuable upon conversion of the notes, then our diluted earnings per share would be reduced.

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Risks Relating to our Common Stock

Our stock price may be volatile, and investors in our common stock could incur substantial losses.

        Our stock price may be volatile. The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. The market price for our common stock may be influenced by many factors, including, but not limited to:

•

the price of oil and natural gas;

•

the success of our exploration and development operations, and the marketing of any oil we produce;

•

regulatory developments in the United States and foreign countries where we operate;

•

the recruitment or departure of key personnel;

•

quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us;

•

market conditions in the industries in which we compete and issuance of new or changed securities;

•

analysts' reports or recommendations;

•

the failure of securities analysts to cover our common stock or changes in financial estimates by analysts;

•

the inability to meet the financial estimates of analysts who follow our common stock;

•

the issuance or sale of any additional securities of ours;

•

investor perception of our company and of the industry in which we compete; and

•

general economic, political and market conditions.

A substantial portion of our total outstanding shares may be sold into the market at any time. This could cause the market price of our common stock to drop significantly, even if our business is doing well.

        All of the shares sold in our public offerings are freely tradable without restrictions or further registration under the federal securities laws, unless purchased by our "affiliates" as that term is defined in Rule 144 under the Securities Act of 1933, as amended (the "Securities Act"). Substantially all the remaining shares of common stock are restricted securities as defined in Rule 144 under the Securities Act. Restricted securities may be sold in the U.S. public market only if registered or if they qualify for an exemption from registration, including by reason of Rules 144 or 701 under the Securities Act. All of our restricted shares are eligible for sale in the public market, subject in certain circumstances to the volume, manner of sale limitations with respect to shares held by our affiliates, and other limitations under Rule 144. Additionally, we have registered all shares of our common stock that we may issue under our employee and director benefit plans. These shares can be freely sold in the public market upon issuance, unless pursuant to their terms these stock awards have transfer restrictions attached to them. Sales of a substantial number of shares of our common stock, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our common stock.

Conversion of the notes may dilute the ownership interest of existing stockholders, including holders who have previously converted their notes.

        The conversion of some or all of the notes may dilute the ownership interests of existing stockholders. Any sales in the public market of any shares of our common stock issuable upon such

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conversion could adversely affect prevailing market prices of our common stock. In addition, the anticipated conversion of the notes into shares of our common stock or a combination of cash and shares of our common stock could depress the price of our common stock.

Holders of our common shares will be diluted if additional shares are issued.

        We may issue additional shares of common stock, preferred stock, warrants, rights, units and debt securities for general corporate purposes, including, but not limited to, repayment or refinancing of borrowings, working capital, capital expenditures, investments and acquisitions. We may issue additional shares of common stock in connection with complementary or strategic acquisitions of assets or businesses. We also issue restricted stock to our executive officers, employees and independent directors as part of their compensation. If we issue additional shares of common stock in the future, it may have a dilutive effect on our current outstanding stockholders.

Ownership of our capital stock is concentrated among our largest stockholders and their affiliates.

        Our former financial sponsors collectively own approximately 42% of our outstanding common stock. These stockholders have significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial. Furthermore, these stockholders may sell their shares of common stock at any time. Such sales could be substantial and adversely affect the market price of our common stock.

Provisions of our certificate of incorporation and by-laws could discourage potential acquisition proposals and could deter or prevent a change in control.

        Some provisions in our certificate of incorporation and by-laws, as well as Delaware statutes, may have the effect of delaying, deferring or preventing a change in control. These provisions, including those providing for the possible issuance of shares of our preferred stock and the right of the board of directors to amend the by-laws, may make it more difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire a substantial number of shares of our common stock or to launch other takeover attempts that a stockholder might consider to be in his or her best interest. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock.

Provisions of the notes could discourage an acquisition of us by a third party.

        Certain provisions of the notes could make it more difficult or more expensive for a third party to acquire us, or may even prevent a third party from acquiring us. For example, upon the occurrence of a fundamental change, holders of the notes will have the right, at their option, to require us to repurchase all of their notes or any portion of the principal amount of such notes in integral multiples of $1,000. In addition, the acquisition of us by a third party could require us, under certain circumstances, to increase the conversion rate for a holder who elects to convert its notes in connection with such acquisition. By discouraging an acquisition of us by a third party, these provisions could have the effect of depriving the holders of our common stock of an opportunity to sell their common stock at a premium over prevailing market prices.

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We do not intend to pay dividends on our common shares and, consequently, your only opportunity to achieve a return on your investment is if the price of our shares appreciates.

        We do not plan to declare dividends on shares of our common stock in the foreseeable future. Consequently, investors must rely on sales of their shares of common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.

Item 1B.    Unresolved Staff Comments

        Not applicable.

Item 2.    Properties

        Please refer to the information under the captions "Business—Overview—U.S. Gulf of Mexico Segment" and "Business—Overview—West Africa Segment" elsewhere in this Annual Report on Form 10-K.

Item 3.    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 4.    Mine Safety Disclosures

        Not applicable.

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

        Our common stock is traded on the New York Stock Exchange under the symbol "CIE." On February 15, 2013, the last reported sale price for our common stock on New York Stock Exchange was $25.09 per share. The following table sets forth, for the periods indicated, the reported high and low sale prices for our common stock on the New York Stock Exchange.

	High		Low
Year ending December 31, 2013
First Quarter (through February 15, 2013)	$	27.00	$	24.00
Year ended December 31, 2012
Fourth Quarter	$	29.45	$	19.90
Third Quarter		28.69		20.59
Second Quarter		31.36		19.69
First Quarter		36.51		15.63
Year ended December 31, 2011
Fourth Quarter	$	16.24	$	6.30
Third Quarter		14.87		7.51
Second Quarter		17.22		12.03
First Quarter		17.14		12.39

Performance Graph

The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

        The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of our common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on our common stock with the cumulative total return of the Standard & Poor's Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 16, 2009, the date we commenced trading on the New York Stock Exchange, through December 31, 2012.

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        An investment of $100 (with reinvestment of any dividends) is assumed to have been made in our common stock, in the S&P's Composite 500 Stock Index and in the Dow Jones U.S. Exploration & Production Index on December 16, 2009, and its relative performance is tracked through December 31, 2012:

			Year Ended December 31,
	As of December 16, 2009
			2009		2010		2011		2012
Cobalt International Energy, Inc.	$	100.00	$	102.52	$	90.44	$	114.96	$	181.93
S&P's Composite 500 Stock Index		100.00		100.53		113.38		113.38		128.58
Dow Jones U.S. Exploration & Production Index		100.00		102.55		121.27		116.66		120.68

Holders

        As of December 31, 2012, there were approximately 144 holders of record of our common stock. The number of record holders does not include holders of shares in "street names" or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

Dividend Policy

        At the present time, we intend to retain all of our future earnings, if any, generated by our operations for the development and growth of our business. The decision to pay dividends on our common stock is at the discretion of our board of directors and depends on our financial condition, results of operations, capital requirements and other factors that our board of directors deems relevant.

Item 6.    Selected Financial Data

        The selected historical financial information set forth below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and with our financial statements and the notes to those financial statements included elsewhere in this Annual Report on Form 10-K. The consolidated statements of operations and cash flows information for the years ended December 31, 2012, 2011, 2010, 2009, and 2008 were derived from Cobalt International Energy, Inc.'s audited financial statements.

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Consolidated Statement of Operations Information:

	Year Ended December 31,
	2012			2011			2010			2009			2008
	($ in thousands except per share data)
Oil and gas revenue	$	—		$	—		$	—		$	—		$	—
Operating costs and expenses
Seismic and exploration		61,583			32,239			45,030			30,666			41,274
Dry hole expense and impairment		134,085			45,732			44,178			14,486			—
General and administrative		87,963			59,130			48,063			35,996			31,271
Depreciation and amortization		1,197			735			787			622			683
Total operating costs and expenses		284,828			137,836			138,058			81,770			73,228
Operating income (loss)		(284,828	)		(137,836	)		(138,058	)		(81,770	)		(73,228	)
Other income (expense):
Interest income		5,041			4,199			1,582			513			1,632
Interest expense		(3,212	)		—			—			—			—
Total other income (expense)		1,829			4,199			1,582			513			1,632
Net income (loss) before income tax		(282,999	)		(133,637	)		(136,476	)		(81,257	)		(71,596	)
Income tax expense (benefit)(1)(2)		—			—			—			—			—
Net income (loss)	$	(282,999	)	$	(133,637	)	$	(136,476	)	$	(81,257	)	$	(71,596	)
Basic and diluted income (loss) per common share	$	(0.70	)	$	(0.35	)	$	(0.39	)
Weighted average number of common shares—basic and diluted		403,356,174			376,603,520			349,342,050
Pro forma net income (loss) (unaudited)(1):
Net income (loss) as reported										$	(81,257	)
Pro forma income tax expense(2)											—
Pro forma management fees(3)											2,872
Pro forma net income (loss) allocable to common shareholders										$	(78,385	)
Pro forma basic and diluted income (loss) per share(4)										$	(0.33	)
Pro forma weighted average number of common shares—basic and diluted(5)											236,751,219

(1)

Upon completion of our initial public offering in 2009, Cobalt International Energy, L.P. became wholly-owned by Cobalt International Energy, Inc. Upon the completion of our corporate reorganization, all of Cobalt International Energy, L.P.'s outstanding limited partnership interests were exchanged for shares of Cobalt International Energy, Inc.'s common stock based on these interests' relative rights as set forth in Cobalt International Energy, L.P.'s limited partnership agreement. Additionally, we became subject to federal and state income taxes.

(2)

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.

(3)

Upon completion of the corporate reorganization the right of our former private equity owners to receive a management fee terminated.

(4)

Nonvested restricted stock awards of 8,015,041 as of December 31, 2009 were excluded from the pro forma calculation of diluted income (loss) per common share because they were anti-dilutive for the applicable period.

(5)

The pro forma weighted average common shares outstanding have been calculated as if the conversion of all partnership units into shares of common shares occurred as of the beginning of the year.

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Consolidated Balance Sheet Information:

	As of December 31,
	2012		2011		2010		2009		2008
	($ in thousands)
Cash and cash equivalents(1)	$	1,425,815	$	292,546	$	302,720	$	1,093,100	$	5,103
Short-term restricted cash		90,440		69,009		—		—		—
Short-term investments(2)		789,668		858,293		534,933		—		—
Total current assets		2,456,742		1,335,094		889,632		1,153,946		23,876
Total property, plant and equipment(3)		1,099,756		863,326		463,769		471,612		760,728
Long-term restricted cash		395,652		270,235		338,515		186,547		—
Long-term investments		36,267		47,232		40,003		—		—
Total assets		4,011,459		2,527,944		1,746,443		1,812,105		784,604
Total current liabilities(4)		160,956		238,069		24,559		70,523		44,133
Total long term liabilities(5)		1,161,285		210,961		2,850		—		—
Total partners' capital/stockholders' equity		2,689,218		2,078,914		1,719,034		1,741,582		740,471
Total liabilities and partners' capital/stockholders' equity		4,011,459		2,527,944		1,746,443		1,812,105		784,604

(1)

The significant increase in cash and cash equivalents from December 31, 2011 to December 31, 2012 was due to the proceeds that we received on December 17, 2012 from the issuance of our 2.625% convertible senior notes due 2019. These proceeds we received were temporarily held in money market funds as of December 31, 2012. The decrease from December 31, 2009 to December 31, 2010 was due to increases in investment in short-term and long-term investments. Cash and cash equivalents at December 31, 2009 includes the proceeds from our initial public offering.

(2)

The increase in investments from December 31, 2010 to 2011 was attributed to the investments of the proceeds from the equity offering of common stock during 2011.

(3)

The increase from December 31, 2011 to 2012 reflects acquisition of uproved leases in the Gulf of Mexico and the capitalized costs for the Heidelberg #3 and Cameia #2 appraisal wells and the North Platte #1 exploratory well. The increase from December 31, 2010 to 2011 reflects the acquisition costs of Block 20 offshore Angola. The decreases in 2010 and 2009 reflect the farm-out of the U.S. Gulf of Mexico lease interests to Total and Sonangol.

(4)

The decrease in current liabilities at December 31, 2012 was primarily attributed to the payment of certain bonus obligations for Block 20 during 2012. The increase in current liabilities at December 31, 2011 consists of year-end accruals for exploration costs in the U.S. Gulf of Mexico and West Africa and the short-term portion of the social and bonus payment obligations for Blocks 9, 20 and 21.

(5)

The significant increase in long-term liabilities from December 31, 2011 to 2012 reflects the issuance of the 2.625% convertible senior notes due 2019 on December 17, 2012. The increase in long-term liabilities at December 31, 2011 reflects the long-term portion of the social and bonus payment obligations for Blocks 9, 20 and 21.

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Consolidated Statement of Cash Flows Information:

	Year Ended December 31,
	2012			2011			2010			2009			2008
	($ in thousands)
Net cash provided by (used in):
Operating activities	$	(140,397	)	$	(57,795	)	$	(133,264	)	$	(75,486	)	$	(48,420	)
Investing activities		(564,761	)		(430,391	)		(758,372	)		87,123			(608,876	)
Financing activities		1,838,427			478,012			101,256			1,076,360			566,453

Item 7.    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," "Cautionary Note Regarding Forward-Looking Statements," and the other matters set forth in this Annual Report on Form 10-K. 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 Annual Report on Form 10-K, as well as the information presented under "Selected Financial Data." Due to the fact that we have not generated any revenues, we believe that the financial information contained in this Annual Report on Form 10-K is not indicative of, or comparable to, the financial profile that we expect to have once we begin to generate revenues. Except to the extent required by law, we undertake no obligation to update publicly any forward-looking statements for any reason, even if new information becomes available or other events occur in the future.

        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 both the U.S. Gulf of Mexico at North Platte, Heidelberg and Shenandoah and offshore Angola at Cameia. Our plan is to continue to mature and drill what we believe are our most promising 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.

Factors Affecting Comparability of Future Results

        You should read this management's discussion and analysis of our financial condition and results of operations in conjunction with our historical financial statements included elsewhere in this Annual Report on Form 10-K. Below are the period-to-period comparisons of our historical results and the analysis of our financial condition. In addition to the impact of the matters discussed in "Risk Factors," our future results could differ materially from our historical results due to a variety of factors, including the following:

        Success in the Discovery and Development of Oil Reserves.    Because we have no operating history in the production of oil, our future results of operations and financial condition will be directly affected by our ability to discover and develop reserves through our drilling activities. Currently, our estimated oil asset base does not qualify as proved reserves. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future exploration will not result in additional discoveries, and, even if we are able to successfully make such discoveries, there is no certainty that the discoveries will be commercially viable to produce. Our results of operations will be adversely affected in the event that our estimated oil asset base does not result in reserves that may eventually be commercially developed.

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        Oil and Gas Revenue.    We have not yet commenced oil production. If and when we do commence production, we expect to generate revenue from such production. No oil and gas revenue is reflected in our historical financial statements.

        Production Costs.    We have not yet commenced oil production. If and when we do commence production, we will incur production costs. Production costs are the costs incurred in the operation of producing and processing our production and are primarily comprised of lease operating expense, workover costs and production and ad valorem taxes. No production costs are reflected in our historical financial statements.

        General and Administrative Expenses.    These costs include expenses associated with our staff costs, information technology, rent, travel, annual and quarterly reporting, investor relations, registrar and transfer agent fees, incremental insurance costs, and accounting and legal services.

        Depreciation, Depletion and Amortization.    We have not yet commenced oil or natural gas production. If and when we do commence production, we will amortize the costs of successful exploration, appraisal, drilling and field development using the unit-of-production method based on total estimated proved developed oil and gas reserves. Costs of acquiring proved and unproved leasehold properties and associated asset retirement costs will be amortized using the unit-of-production method based on total estimated proved developed and undeveloped reserves. No depletion of oil and gas properties is reflected in our historical financial statements.

        Demand and Price.    The demand for oil is susceptible to volatility related to, among other factors, the level of global economic activity and may also fluctuate depending on the performance of specific industries. We expect that a decrease in economic activity, in the United States and elsewhere, would adversely affect demand for oil we expect to produce. Since we have not generated revenues, these key factors will only affect our financial statements when we produce and sell hydrocarbons.

        We expect to earn income from:

•

domestic and international sales, which consist of sales of oil and natural gas;

•

sales to international markets; and

•

other sources, including services, investment income and foreign exchange gains.

        We expect that our expenses will include:

•

costs of sales (which are composed of production costs, insurance, and costs associated with the operation of our wells);

•

maintenance and repair of property and equipment;

•

costs of acquiring new leases or licenses;

•

costs of acquiring seismic data;

•

depreciation and amortization of fixed assets;

•

depletion of oilfields;

•

exploration costs;

•

selling expenses (which include expenses relating to the transportation, marketing and distribution of our products) and general and administrative expenses; and

•

interest expense and foreign exchange losses.

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        We expect that fluctuations in our financial condition and results of operations will be driven by a combination of factors, including:

•

the volume of oil we produce and sell;

•

changes in the domestic and international prices of oil, which are denominated in U.S. dollars;

•

fluctuations in the royalty rates on the leases that we hold;

•

our success in future bidding rounds for leases and concessions;

•

political and economic conditions in the United States, Angola and Gabon; and

•

the amount of taxes and duties that we are required to pay with respect to our future operations, by virtue of our status as a U.S. company and our involvement in the oil and gas industry.

Results of Operations

        We operate our business in two geographic segments: the U.S. Gulf of Mexico 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.

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Fiscal Years Ended December 31, 2012 vs. 2011

	Year Ended December 31,
							Increase (Decrease)			Percentage Change
	2012			2011
	($ in thousands)
U.S. Gulf of Mexico Segment:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		32,874			10,707			22,167			207	%
Dry hole expense and impairment		134,085			23,323			110,762			475	%
General and administrative		63,270			45,742			17,528			38	%
Depreciation and amortization		967			653			314			48	%
Total operating costs and expenses		231,196			80,425			150,771			187	%
Operating income (loss)		(231,196	)		(80,425	)		150,771			187	%
Other income (expense)
Interest income		5,036			4,194			842			20	%
Interest expense		(3,212	)		—			3,212			—
Total other income (expense)		1,824			4,194			(2,370	)		(57	)%
Net income (loss) before income tax		(229,372	)		(76,231	)		153,141			201	%
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(229,372	)	$	(76,231	)	$	153,141			201	%
West Africa Segment:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		28,709			21,532			7,177			33	%
Dry hole expense and impairment		—			22,409			(22,409	)		(100	)%
General and administrative		24,693			13,388			11,305			84	%
Depreciation and amortization		230			82			148			180	%
Total operating costs and expenses		53,632			57,411			(3,779	)		(7	)%
Operating income (loss)		(53,632	)		(57,411	)		(3,779	)		(7	)%
Other income (expense)
Interest income		5			5			—			—
Interest expense		—			—			—			—
Total other income (expense)		5			5			—			—
Net income (loss) before income tax		(53,627	)		(57,406	)		(3,779	)		(7	)%
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(53,627	)	$	(57,406	)	$	(3,779	)		(7	)%
Consolidated Operations:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		61,583			32,239			29,344			91	%
Dry hole expense and impairment		134,085			45,732			88,353			193	%
General and administrative		87,963			59,130			28,833			49	%
Depreciation and amortization		1,197			735			462			63	%
Total operating costs and expenses		284,828			137,836			146,992			107	%
Operating income (loss)		(284,828	)		(137,836	)		146,992			107	%
Other income (expense)
Interest income		5,041			4,199			842			20	%
Interest expense		(3,212	)		—			3,212			—
Total other income (expense)		1,829			4,199			(2,370	)		(57	)%
Net income (loss) before income tax		(282,999	)		(133,637	)		149,362			112	%
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(282,999	)	$	(133,637	)	$	149,362			112	%

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U.S. Gulf of Mexico Segment:

        Oil and gas revenue.    We have not yet commenced oil production in the U.S. Gulf of Mexico. Therefore, we did not realize any oil and gas revenue during the years ended December 31, 2012 and 2011.

        Operating costs and expenses.    Our operating costs and expenses for our U.S. Gulf of Mexico operations consisted of the following during the years ended December 31, 2012 and 2011:

        Seismic and exploration.    Seismic and exploration costs increased by approximately $22.2 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011. The increase was primarily due to a $24.5 million increase in seismic costs and a $0.3 million increase in delay rentals offset by the decrease of $2.6 million in exploration expenses which were primarily attributable to standby and regulatory acceptance costs incurred for Ensco 8503 drilling rig during the year ended December 31, 2011.

        Dry hole expense and impairment.    Dry hole expense and impairment increased by $110.8 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011. The increase is due to impairment of unproved leasehold properties and dry hole expense written off against exploratory wells as reflected in the following table:

	Year Ended December 31,
	2012		2011		Increase (Decrease)
	(in thousands)
Impairment of Unproved leasehold:
Ligurian prospect	$	41,861	$	—	$	41,861
Other leasehold(1)		8,298		—		8,298
Amortization of leasehold with carrying value under $1 million		10,007		9,127		880
Dry Hole Expense:
Ligurian #1 exploratory well		8,100		—		8,100
Ligurian #2 exploratory well		48,994		—		48,994
Heidelberg #2 appraisal well		—		5,999		(5,999	)
Heidelberg #3 appraisal well side track		4,109		—		4,109
Shenandoah #2 appraisal well		12,716		—		12,716
Criollo #1 exploratory well		—		8,197		(8,197	)
	$	134,085	$	23,323	$	110,762

(1)

Other leasehold includes certain unproved oil and gas leases for properties in the U.S. Gulf of Mexico with carrying value greater than $1 million that we have no exploration activity planned, based on our three-year exploration plan, during the remaining term of the leases.

        General and administrative.    General and administrative costs increased by $17.5 million during the year ended December 31, 2012 as compared to the year ended December 31, 2011. The increase in general and administrative costs during this period was primarily attributed to a $16.6 million increase in staff related expenses which includes non-cash equity compensation, a $6.8 million increase in legal and other consulting fees, a $1.0 million increase in information and technology expenses, a $2.3 million increase in office rent and facilities due to the move to our new office building in Houston and a $2.6 million increase in other office related expenses, offset by an increase of $11.8 million in recoveries from partners due to the increase in drilling activities.

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        Depreciation and amortization.    Depreciation and amortization did not change significantly during the year ended December 31, 2012 as compared to the year ended December 31, 2011.

        Other income (expense).    Other income decreased by $2.4 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011. The decrease was primarily due to the increase of $0.8 million from interest and dividends earned in investment securities offset by $3.2 million recognized for the interest expense associated with our 2.625% convertible senior notes due 2019 during the year ended December 31, 2012.

        Income taxes.    As a result of net operating losses, for income tax purposes, we recorded a net deferred tax asset of $269.6 million and $177.2 million with a corresponding full valuation of $269.6 million and $177.2 million for the years ended December 31, 2012 and 2011, respectively.

West Africa Segment:

        Oil and gas revenue.    We have not yet commenced oil production in West Africa. Therefore, we did not realize any oil and gas revenue during the years ended December 31, 2012 and 2011.

        Operating costs and expenses.    Our operating costs and expenses for the West Africa operations consisted of the following during the years ended December 31, 2012 and 2011:

        Seismic and exploration.    Seismic and exploration costs increased by approximately $7.2 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011. The increase was due to the net effect of $9.7 million for standby costs associated with drilling of the Cameia #2 appraisal well charged to other exploration expenses which were offset by decrease of $2.5 million incurred in seismic costs during the year ended December 31, 2012.

        Dry hole expense and impairment.    Dry hole expense and impairment decreased by $22.4 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011. The decrease was due to a $22.4 million charge against the Bicuar #1 exploratory well during the year ended December 31, 2011. The Company did not have any dry hole charge for West Africa operations for the year ended December 31, 2012.

        General and administrative.    General and administrative costs increased by $11.3 million during the year ended December 31, 2012 as compared to the year ended December 31, 2011. The increase in general and administrative costs during this period was primarily attributed to a $2.4 million increase in office rent and facilities related to the move to the new office building in Luanda, a $1.1 million increase in expatriate housing and related costs, a $1.3 million increase in other office related expenses and a $6.5 million increase for contractors and consulting services incurred in support of West Africa operations during the year ended December 31, 2012.

        Depreciation and amortization.    Depreciation and amortization did not change significantly during the year ended December 31, 2012 as compared to the year ended December 31, 2011.

        Other income.    There was no significant other income for the West Africa operations during the years ended December 31, 2012 and 2011.

        Income taxes.    As a result of net operating losses, we included a net deferred tax asset of $77.4 million and $30.4 million for West Africa in our U.S. consolidated tax provisions for the years ended December 31, 2012 and 2011, respectively.

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Fiscal Years Ended December 31, 2011 vs. 2010

	Year Ended December 31,
							Increase (Decrease)			Percentage Change
	2011			2010
	($ in thousands)
U.S. Gulf of Mexico Segment:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		10,707			15,984			(5,277	)		(33	)%
Dry hole expense and impairment		23,323			44,178			(20,855	)		(47	)%
General and administrative		45,742			33,674			12,068			36	%
Depreciation and amortization		653			783			(130	)		(17	)%
Total operating costs and expenses		80,425			94,619			(14,194	)		(15	)%
Operating income (loss)		(80,425	)		(94,619	)		(14,194	)		(15	)%
Other income (expense)
Interest income (expense), net		4,194			1,582			2,612			165	%
Total other income (expense)		4,194			1,582			2,612			165	%
Net income (loss) before income tax		(76,231	)		(93,037	)		(16,806	)		(18	)%
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(76,231	)	$	(93,037	)	$	(16,806	)		(18	)%
West Africa Segment:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		21,532			29,046			(7,514	)		(26	)%
Dry hole expense and impairment		22,409			—			22,409			—
General and administrative		13,388			14,389			(1,001	)		(7	)%
Depreciation and amortization		82			4			78			1950	%
Total operating costs and expenses		57,411			43,439			13,972			32	%
Operating income (loss)		(57,411	)		(43,439	)		13,972			32	%
Other income (expense)
Interest income (expense), net		5			—			5			—
Total other income (expense)		5			—			5			—
Net income (loss) before income tax		(57,406	)		(43,439	)		13,967			32	%
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(57,406	)	$	(43,439	)	$	13,967			32	%
Consolidated Operations:
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		32,239			45,030		$	(12,791	)		(28	)%
Dry hole expense and impairment		45,732			44,178			1,554			4	%
General and administrative		59,130			48,063			11,067			23	%
Depreciation and amortization		735			787			(52	)		(7	)%
Total operating costs and expenses		137,836			138,058			(222	)		(0.2	)%
Operating income (loss)		(137,836	)		(138,058	)		(222	)		(0	)%
Other income (expense)
Interest income (expense), net		4,199			1,582			2,617			165	%
Total other income (expense)		4,199			1,582			2,617			165	%
Net income (loss) before income tax		(133,637	)		(136,476	)		(2,839	)		(2	)%
Income tax expense (benefit)		—			—			—			—
Net income (loss)	$	(133,637	)	$	(136,476	)	$	(2,839	)		(2	)%

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U.S. Gulf of Mexico Segment:

        Oil and gas revenue.    We have not yet commenced oil production in the U.S. Gulf of Mexico. Therefore, we did not realize any oil and gas revenue during the years ended December 31, 2011 and 2010.

        Operating costs and expenses.    Our operating costs and expenses for our U.S. Gulf of Mexico operations consisted of the following during the years ended December 31, 2011 and 2010:

        Seismic and exploration.    Seismic and exploration costs decreased by approximately $5.3 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010. The decrease was due to $9.8 million incurred for leasehold delay rentals and drilling preparation expenditures and $0.9 million incurred for seismic costs during the year ended December 31, 2011, which were offset by $13.5 million incurred for force majeure costs related to suspended drilling activities in the U.S. Gulf of Mexico, $0.9 million incurred for seismic costs, $7.0 million incurred for leasehold delay rentals and drilling preparation costs in the U.S. Gulf of Mexico minus the reclassification of $5.4 million for past technical costs to West Africa entities for recovery from partners during the year ended December 31, 2010.

        Dry hole expense and impairment.    Dry hole expense and impairment decreased by $20.9 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010. The decrease is due to impairment of unproved leasehold properties and dry hole expense written off against exploratory wells as reflected in the following table:

	Year Ended December 31,
	2011		2010		Increase (Decrease)
	(in thousands)
Impairment of Unproved leasehold:
Amortization of leasehold with carrying value under $1 million	$	9,127	$	9,237	$	(110	)
Dry Hole Expense:
Heidelberg #1 appraisal well		—		11,130		(11,130	)
Heidelberg #2 appraisal well		5,999		—		5,999
Criollo #1 exploratory well		8,197		8,430		(233	)
Firefox #1 exploratory well		—		12,463		(12,463	)
Ligurian #1 exploratory well pre-spud costs		—		438		(438	)
North Platte #1 exploratory well pre-spud costs		—		2,480		(2,480	)
	$	23,323	$	44,178		(20,855	)

        General and administrative.    General and administrative costs increased by $12.1 million during the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in general and administrative costs during this period was primarily attributed to a $3.7 million increase in staff salaries and bonus costs, a $2.5 million increase in costs relating to equity-based compensation, a $1.4 million increase in information and technology expenses, and a $0.4 million increase in other office related expenses, and a $4.1 million decrease in staff and contractor related costs charged to West Africa operations for recovery from partners.

        Depreciation and amortization.    Depreciation and amortization did not change significantly during the year ended December 31, 2011 as compared to the year ended December 31, 2010.

        Other income.    Other income increased by $2.6 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase was primarily due to the additional

74

interest recognized as a result of the investment of the net proceeds from our public offering of common stock, which closed on April 15, 2011, in certain investment securities and interest earned on investment securities held during the year ended December 31, 2011.

        Income taxes.    As a result of net operating losses, for income tax purposes, we recorded a net deferred tax asset of $177.2 million and $97.6 million with a corresponding full valuation of $177.2 million and $97.6 million for the years ended December 31, 2011 and 2010, respectively.

West Africa Segment:

        Oil and gas revenue.    We have not yet commenced oil production in West Africa. Therefore, we did not realize any oil and gas revenue during the years ended December 31, 2011 and 2010.

        Operating costs and expenses.    Our operating costs and expenses for the West Africa operations consisted of the following during the years ended December 31, 2011 and 2010:

        Seismic and exploration.    Seismic and exploration costs decreased by approximately $7.5 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010. The decrease was due to the net effect of $19.5 million incurred for seismic costs and $2.0 million incurred for drilling preparation expenditures during the year ended December 31, 2011, which were offset by $28.7 million incurred for seismic costs, which amount is net of $15.1 million for past seismic cost recovery from partners, and $0.3 million incurred for drilling preparation costs in West Africa during the year ended December 31, 2010.

        Dry hole expense and impairment.    Dry hole expense and impairment increased by $22.4 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010. The increase was due to a $22.4 million charge against the Bicuar #1 exploratory well during the year ended December 31, 2011.

        General and administrative.    General and administrative costs decreased by $1.0 million during the year ended December 31, 2011 as compared to the year ended December 31, 2010. The decrease in general and administrative costs during this period was primarily attributed to a $1.0 million increase in staff costs, a $2.3 million increase in consultant and contractor fees, a $2.5 million increase in other office related expenses, which were offset by a $4.2 million decrease in social contribution payments, and a decrease of $2.6 million in recoveries from West Africa partners during the year ended December 31, 2011.

        Depreciation and amortization.    Depreciation and amortization did not change significantly during the year ended December 31, 2011 as compared to the year ended December 31, 2010.

        Other income.    There was no significant other income for the West Africa operations during the years ended December 31, 2011 and 2010.

        Income taxes.    The net operating losses in our West Africa operations for the years ended December 31, 2011 and 2010 would not have any significant impact on our consolidated tax provisions in the United States.

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 Cameia pre-salt discovery, we are currently conducting pre-development activities and planning for a phased development approach. We currently estimate first oil and cash flow from Cameia during 2016, assuming continued alignment with our partners and the concessionaire, among other things. Our confidence in conducting pre-development activities and progressing our Cameia discovery toward

75

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. With respect to our non-operated U.S. Gulf of Mexico discoveries, Anadarko, as operator, has publicly indicated that it expects first production from the Heidelberg field in 2016 and first production from the Shenandoah field in 2017.

        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 expenditures 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, including increased industry costs in the U.S. Gulf of Mexico resulting from the Deepwater Horizon incident;

•

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 in our focus areas; 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, the success of our exploration and appraisal drilling program, the number of commercially viable hydrocarbon discoveries made and the quantities of hydrocarbons discovered, the speed with which we can bring such discoveries to production, whether and to what extent we invest in additional oil leases and concessional licenses, and the actual cost of exploration, appraisal and development of our prospects.

        As of December 31, 2012, we had approximately $2.7 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 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 $750 to $900 million for our ongoing operations and general corporate purposes in 2013. Our full year 2012 expenditures were approximately $620 million. 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 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 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.

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Cash Flows

	Year Ended December 31.
	2012			2011			2010
	($ in thousands)
Net cash provided by (used in):
Operating Activities	$	(140,397	)	$	(57,795	)	$	(133,264	)
Investing Activities		(564,761	)		(430,391	)		(758,372	)
Financing Activities		1,838,427			478,012			101,256

        Operating activities.    Net cash of approximately $140.4 million used in operating activities during 2012 was primarily related to cash payments for seismic and exploration expenses incurred in the U.S. Gulf of Mexico and West Africa and purchase of inventory for West Africa. The $57.8 million used in operating activities during 2011 was primarily related to cash payments for seismic and exploration expenses incurred in the U.S. Gulf of Mexico and West Africa. The $133.3 million used in operating activities during 2010 was primarily attributable to the increase in cash payments for seismic data acquisition for the U.S. Gulf of Mexico and offshore West Africa, force majeure expenses relating to Deepwater Horizon incident and expenses incurred relating to mobilization of the Ensco 8503 drilling rig.

        Investing activities.    Net cash used in investing activities in 2012 was approximately $564.8 million, compared with net cash used in investing activities of approximately $430.4 million and $758.4 million in 2011 and 2010, respectively. The net cash used in 2012 primarily relates to capital expenditures relating to the North Platte #1 exploratory well in the deepwater U.S. Gulf of Mexico and the Cameia #1 exploratory well and Cameia #2 appraisal well offshore Angola. The $430.4 million used in investing activities during 2011 was primarily related to capital expenditures relating to the Bicuar #1 and Cameia #1 exploratory wells offshore Angola. The increase in net cash used in 2010 was primarily attributed to the investment of the net proceeds from our initial public offering in certain held-to-maturity securities.

        Financing activities.    Net cash provided by financing activities in 2012 was approximately $1,838 million, compared with net cash provided by financing activities of approximately $478.0 million and $101.3 million in 2011 and 2010, respectively. The increase in net cash provided by financing activities in 2012 compared to 2011 was attributed to the net proceeds we received from the issuance of our 2.625% convertible senior notes due 2019 in December 2012 and our public offering of common stock in February 2012. The increase in net cash provided by financing activities in 2011 compared to 2010 was primarily attributed to the proceeds we received from our public offering of our common stock in April 2011. The $101.3 million net cash provided by financing activities in 2010 was related to net proceeds received in January 2010 from the underwriters' exercise of their over-allotment option in connection with our initial public offering in December 2009.

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Contractual Obligations

        The following table summarizes by period the payments due for our estimated contractual obligations as of December 31, 2012:

	Payments Due By Year
	2013		2014		2015		2016		2017		Thereafter		Total
	($ in thousands)
Drilling Rig and Related Contracts	$	594,374	$	342,321	$	154,920	$	60,025	$	—	$	—	$	1,151,640
Operating Leases		11,200		9,860		9,515		6,063		3,571		10,402		50,611
Lease Rentals(1)		6,413		5,736		5,502		3,610		3,157		1,071		25,489
Social Payment Obligations(2)		49,019		51,101		48,569		62,854		5,714		—		217,257
Long-term Debt Obligations(3):
Principal		—		—		—		—		—		1,380,000		1,380,000
Interest		34,615		36,225		36,225		36,225		36,225		72,450		251,965
Total	$	695,621	$	445,243	$	254,731	$	168,777	$	48,667	$	1,463,923	$	3,076,962

(1)

Relates to the annual delay rental payments payable to the Office of Natural Resources Revenue within the U.S. Department of the Interior with respect to our U.S. Gulf of Mexico leases. These annual payments are required to maintain the leases from year to year.

(2)

Includes our contractual payment obligations for social projects such as the Sonangol Research and Technology Center and academic scholarships for Angolan students that we were and are contractually obligated to pay in consideration for the Angolan government granting us the licenses to explore for and develop hydrocarbons offshore Angola. Pursuant to the terms of the RSAs for Blocks 9 and 21 and the PSC for Block 20, we are not required to pay annual rental payments to maintain the licenses from year to year.

(3)

Represents principal amount of our 2.625% convertible senior notes due December 2019 and interest payable semi-annually in arrears on June 1 and December 1 of each year, beginning on June 1, 2013.

        In the future, we may be party to additional contractual arrangements including arrangements listed below, which will subject us to further contractual obligations:

•

credit facilities and other debt instruments;

•

contracts for the lease of additional drilling rigs;

•

contracts for the provision of production facilities;

•

infrastructure construction contracts; and

•

long term oil and gas property lease arrangements.

Off-Balance Sheet Arrangements

        As of December 31, 2012, we did not have any off-balance sheet arrangements.

Critical Accounting Policies

        This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with

78

generally accepted accounting principles in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in Note 2 to our consolidated financial statements. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.

        Revenue Recognition.    We plan to follow the "sales" (or cash) method of accounting for oil and gas revenues. Under this method, we will recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. As of December 31, 2012, no revenues have been recognized in our financial statements.

        We recognize interest income on bank balances and deposits on a time basis, by reference to the principal outstanding and at the effective interest rate applicable.

        Cash and Cash Equivalents.    Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less from the date of purchase. Demand deposits typically exceed federally insured limits; however we periodically assess the financial condition of the institutions where these funds are held as well as the credit ratings of the issuers of the highly liquid instruments and believe that the credit risk is minimal.

        Investments.    We adopted a policy on accounting for our investments, which consist entirely of debt securities, based on the accounting guidance relating to "Accounting for Certain Investments in Debt and Equity Securities." The debt securities are carried at amortized costs and classified as held-to-maturity as we have the 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.

        We conduct a regular assessment of our debt securities with unrealized losses to determine whether securities have other-than-temporary impairment. 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 we intend to sell or whether it is more likely than not that we will be required to sell the debt securities.

        Property, Plant and Equipment.    We use the "successful efforts" method of accounting for our oil properties. Acquisition costs for unproved leasehold properties and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the areas as a result of drilling those wells. Under the successful efforts method of accounting, proved leasehold costs are capitalized and amortized over the proved developed and undeveloped reserves on a units-of-production basis. Successful drilling costs, costs of development and developmental dry holes are capitalized and amortized over the proved developed reserves on a units-of-production basis. Unproved leasehold costs are capitalized and are not amortized, pending an evaluation of their exploration potential. Significant unproved leasehold costs are assessed on an individual basis periodically to determine if an impairment of the cost of individual properties has occurred. Factors taken into account for impairment analysis include results of the technical studies conducted, lease terms and management's future exploration plans. The cost of impairment is charged to expense in the period in which it occurs. Costs incurred for exploratory dry holes, geological, and geophysical work (including the cost of seismic data) and delay rentals are charged to expense as incurred. Costs of other property and equipment are depreciated on a straight-line based on their respective useful lives.

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        Inventory.    Inventories consist of various tubular products that will be used in our anticipated drilling program. The inventory is stated at the average cost. Cost is determined on a weighted average method and comprises of purchase price and other directly attributable costs.

        Income Taxes.    Prior to December 15, 2009, no provision for U.S. federal income taxes related to our operations was included in the accompanying financial statements. As a partnership, we were not subject to federal or state income tax, and the tax effect of our activities accrued to the partners. The Partnership had obligations associated with providing certain tax-related information to the partners and registrations and filings with applicable governmental taxing authorities.

        Effective December 15, 2009, we began using the liability method of accounting for income taxes in accordance with accounting guidance relating to "Income Taxes" as clarified by Accounting for Uncertainty in Income Taxes. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Since we are in development stage and there can be no assurance that we will generate any earnings or any specific level of earnings in future years, we will establish a valuation allowance for deferred tax assets (net of liabilities).

        Use of Estimates.    The preparation of our consolidated financial statements in conformity with United States generally accepted accounting principles requires us to make estimates and assumptions that impact our reported assets and liabilities, disclosure of contingent assets and liabilities at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates 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 we believe these estimates are reasonable, actual results could differ from these estimates.

        Estimates of Proved Oil & Natural Gas Reserves.    Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As of December 31, 2012, we do not have any proved reserves. Should proved reserves be found in the future, estimated reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board. The accuracy of these reserve estimates is a function of:

•

the quality and quantity of available data and the engineering and geological interpretation of that data;

•

estimates regarding the amount and timing of future operating cost, severance taxes, development cost and workover cost, all of which may in fact vary considerably from actual results;

•

the accuracy of various mandated economic assumptions (such as the future prices of oil and natural gas); and

•

the judgments of the persons preparing the estimates.

        Asset Retirement Obligations.    We currently do not have any oil and natural gas production or any legal obligations to incur decommissioning in costs. Should such production occur in the future, we expect to have significant obligations under our lease agreements and federal regulation to remove our equipment and restore land or seabed at the end of oil and natural gas production operations. These

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asset retirement obligations ("ARO") are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and natural gas platforms. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulation often have vague descriptions of what constitutes, removal. Asset removal technologies and cost are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Pursuant to the accounting guidance relating to "Assets Retirement Obligations", we are required to record a separate liability for the discounted present value of our asset retirement obligations, with an offsetting increase to the related oil and natural gas properties representing asset retirement costs on our balance sheet. The cost of the related oil and natural gas asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

        Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, we will make corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. Increases in the discounted abandonment liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the consolidated statement of operations.

        Earnings (Loss) Per Share.    Basic earnings (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. Diluted earnings (loss) per share incorporate the potential dilutive impact of options and unvested stock outstanding during the periods presented, unless their effect is anti-dilutive. In addition, we apply the if-converted method to our convertible debt instruments, the effect of which is that conversion will not be assumed for purposes of computing diluted earnings (loss) per share if the effect would be anti-dilutive.

        Equity-Based Compensation.    We account for stock-based compensation at fair value. We grant various types of stock-based awards including stock options, restricted stock and performance-based awards. The fair value of stock option awards is determined by 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 our common stock on the grant date. We record compensation cost, net of estimated forfeitures, on a straight-line basis 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 we determine that the achievement of the performance condition is probable, using the per-share fair value measured at grant date.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

        The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risks" refers to the risk of loss arising from changes in commodity prices, interest rates, foreign currency exchange rates, and other relevant market risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of

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our market risk sensitive instruments will be entered into for purposes of risk management and not for speculation.

        Due to the historical volatility of commodity prices, if and when we commence production, we may enter into various derivative instruments to manage our exposure to volatility of commodity market prices. We may use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in commodity prices to our cash flow. All contracts will be settled with cash and would not require the delivery of physical volumes to satisfy settlement. While in times of higher commodity prices this strategy may result in our having lower net cash inflows than we would otherwise have if we had not utilized these instruments, management believes the risk reduction benefits of such a strategy would outweigh the potential costs.

        We may borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. Our objective in borrowing under fixed or variable rate debt is to satisfy capital requirements while minimizing our costs of capital.

Item 8.    Financial Statements and Supplementary Data

        The information required is included in this report as set forth in the "Index to Consolidated Financial Statements" on page F-1 to this Annual Report on Form 10-K.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None

Item 9A.    Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

        As of December 31, 2012, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer ("CEO") and our Chief Financial Officer ("CFO"), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our CEO and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Because of the inherent limitation in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 2012.

Management's Report on Internal Control over Financial Reporting

        The information required to be furnished pursuant to this item is set forth under the caption "Management's Report on Internal Control over Financial Reporting" in Item 8 of this Annual Report on Form 10-K.

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Attestation Report of the Registered Public Accounting Firm

        The information required to be furnished pursuant to this item is set forth under the caption "Report of Independent Registered Public Accounting Firm" in Item 8 of this Annual Report on Form 10-K.

Changes in Internal Control Over Financial Reporting

        There has been no change in our internal control over financial reporting during the fourth quarter ended December 31, 2012, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.    Other Information

Amended and Restated Stockholders Agreement

        On February 21, 2013, we entered into an amended and restated stockholders agreement with funds affiliated with First Reserve Corporation, Goldman, Sachs & Co., Riverstone Holdings LLC, The Carlyle Group, and KERN Partners Ltd. (our "former financial sponsors"), which amended and restated a previous stockholders agreement which was entered in connection with our IPO. This amended and restated stockholders agreement removed the rights of such former financial sponsors to designate certain members of the Board and the committees of the Board. The former financial sponsors retain, among other things, certain rights to obtain information from us, provided that they agree to keep such information confidential and agree to comply with all applicable securities laws in connection therewith. As of the date of the amended and restated stockholders agreement, the former financial sponsors owned approximately 42% of the shares of our outstanding common stock. In addition, seven of our twelve directors (namely, Peter R. Coneway, Michael G. France, N. John Lancaster, Kenneth W. Moore, Scott L. Lebovitz, Kenneth A. Pontarelli and D. Jeff van Steenbergen) are employed by respective affiliates of the former financial sponsors and were originally designated to our board pursuant to the terms of the prior stockholders agreement. A copy of the amended and restated stockholders agreement is contained in Exhibit 10.36 hereto, which exhibit is incorporated by reference into this Item 9B. The above description is qualified in its entirety by reference to such exhibit.

Deferred Compensation Plan under the Cobalt International Energy, Inc. Long Term Incentive Plan

        In December 2012, the Compensation Committee of our Board of Directors adopted the Cobalt International Energy, Inc. Deferred Compensation Plan under the Cobalt International Energy, Inc. Long Term Incentive Plan. Our prior deferred compensation plan required that all deferred amounts be distributed in shares of common stock on January 15, 2012, after which the plan expired pursuant to its terms. The new Deferred Compensation Plan permits an eligible participant to defer receipt of all or a portion of the participant's base salary for a plan year and/or all or a portion of the participant's annual bonus with respect to a plan year. Any and all deferrals under the Deferred Compensation Plan will be notionally invested and will settle in shares of our common stock. As of December 31, 2012, there were no participants under the Deferred Compensation Plan. We do not believe that the adoption of the Deferred Compensation Plan under our Long Term Incentive Plan is "material", as that term is used in Item 5.02(e) of Form 8-K.

Cobalt International Energy, Inc. Long Term Incentive Plan (Amended and Restated as of February 21, 2013)

        Effective as of February 21, 2013, our Board of Directors amended and restated our Long Term Incentive Plan to include certain provisions required by the "qualified performance-based compensation" exception under Section 162(m) of the Internal Revenue Code and to update the plan. We do not believe that the amendments to the plan as reflected in the Long Term Incentive Plan (as Amended and Restated) are "material", as that term is used in Item 5.02(e) of Form 8-K.

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PART III

Item 10.    Directors, Executive Officers and Corporate Governance

        The information required by this item is set forth under the captions "Election of Directors," "Corporate Governance" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our definitive Proxy Statement (the "2013 Proxy Statement") for our annual meeting of stockholders to be held on April 25, 2013, which sections are incorporated herein by reference.

        Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to our executive officers is set forth in Part I of this Annual Report on Form 10-K.

Item 11.    Executive Compensation

        The information required by this item is set forth in the sections entitled "Election of Directors—Director Compensation," "Executive Compensation" and "Corporate Governance" in the 2013 Proxy Statement, which sections are incorporated herein by reference.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

        The information required by this item is set forth in the sections entitled "Security Ownership of Certain Beneficial Owners and Management" and "Executive Compensation—Equity Compensation Plan Information" in the 2013 Proxy Statement, which sections are incorporated herein by reference.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

        The information required by this item is set forth in the section entitled "Corporate Governance" and "Certain Relationships and Related Transactions" in the 2013 Proxy Statement, which sections are incorporated herein by reference.

Item 14.    Principal Accounting Fees and Services

        The information required by this item is set forth in the section entitled "Ratification of Appointment of Independent Auditors" in the 2013 Proxy Statement, which section is incorporated herein by reference.

GLOSSARY OF SELECTED OIL AND GAS TERMS

"2-D seismic data"	Two-dimensional seismic data, being an interpretive data that allows a view of a vertical cross-section beneath a prospective area.
"3-D seismic data"	Three-dimensional seismic data, being geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic data.
"Appraisal well"	A well drilled after an exploratory well to gain more information on the drilled reservoirs.
"Barrel"	A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.

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"Below salt"	A term encompassing both subsalt, as used in connection with the U.S. Gulf of Mexico, and pre-salt, as used in connection with offshore West Africa.
"Blowouts"	Blowout is the uncontrolled release of a formation fluid, usually gas, from a well being drilled, typically for petroleum production.
"Closure"	A trapping configuration.
"Completion"	The procedure used in finishing and equipping an oil or natural gas well for production.
"Delay rental"	Payment made to the lessor under a non-producing oil and natural gas lease at the beginning or end of each year to continue the lease in force for another year during its primary term.
"Development"	The phase in which an oil field is brought into production by drilling development wells and installing appropriate production systems.
"Development well"	A well drilled to a known formation in a discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.
"Drilling and completion costs"	All costs, excluding operating costs, of drilling, completing, testing, equipping and bringing a well into production or plugging and abandoning it, including all labor and other construction and installation costs incident thereto, location and surface damages, cementing, drilling mud and chemicals, drillstem tests and core analysis, engineering and well site geological expenses, electric logs, costs of plugging back, deepening, rework operations, repairing or performing remedial work of any type, costs of plugging and abandoning any well participated in by us, and reimbursements and compensation to well operators.
"Dry hole"	An exploratory, appraisal or development well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
"E&P"	Exploration and production.
"Exploratory well"	A well drilled either (a) in search of a new and as yet undiscovered pool of oil or natural gas or (b) with the hope of significantly extending the limits of a pool already developed.

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"Farm-in"	An agreement whereby an oil company acquires a portion of the leasehold or working interest in a block from the owner of such interest in certain acreage, usually in return for cash and for taking on a portion of the drilling of one or more specific wells or other performance by the assignee as a condition of the assignment. Under a farm-in, the owner of the leasehold or working interest may retain some interest such as an overriding royalty interest, an oil and natural gas payment, offset acreage or other type of interest.
"Farm-out"	An agreement whereby the owner of the leasehold or working interest agrees to assign a portion of his interest in certain acreage subject to the drilling of one or more specific wells or other performance by the assignee as a condition of the assignment. Under a farm-out, the owner of the leasehold or working interest may retain some interest such as an overriding royalty interest, an oil and natural gas payment, offset acreage or other type of interest.
"Field"	A geographical area under which an oil or natural gas reservoir lies in commercial quantities.
"FERC"	Federal Energy Regulatory Commission
"Finding and development costs"	Capital costs incurred in the acquisition, exploration, appraisal, development and revisions of proved oil and natural gas reserves divided by proved reserve additions.
"FPSO"	Floating Production, Storage and Offloading system.
"Gathering system"	Pipelines and other facilities that transport oil from wells and bring it by separate and individual lines to a central delivery point for delivery into a transmission line or mainline.
"Gross acre"	An acre in which a working interest is owned. The number of gross acres is the total number of acres in which an interest is owned.
"Horizon"	A zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.
"Leases"	Full or partial interests in oil or natural gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas upon payment of rental, bonus, royalty or any other payments.
"Natural gas"	Natural gas is a combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.

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"Narrow-azimuth 3-D seismic data"	Seismic data acquired with receivers located in long lines that are located in line with source position. This acquisition is repeated in closely positioned parallel lines to yield 3-D seismic data coverage.
"Net pay thickness"	The vertical extent of the effective hydrocarbon-bearing rock (expressed in feet). The net pay thickness encountered by an exploratory well may differ from the mean net pay thickness of the prospect due to several factors, including the relative location of the exploratory well on the structure, potential thickness variations that may occur across the prospect and the extent to which potential reservoir horizons are penetrated.
"NORM"	Naturally occurring radioactive materials.
"Oil and natural gas lease"	A legal instrument executed by a mineral owner granting the right to another to explore, drill, and produce subsurface oil and natural gas. An oil and natural gas lease embodies the legal rights, privileges and duties pertaining to the lessor and lessee.
"OPEC"	Organization of the Petroleum Exporting Countries.
"Operator"	A party that has been designated as manager for exploration, drilling, and/or production on a lease. The operator is the party that is responsible for (a) initiating and supervising the drilling and completion of a well and/or (b) maintaining the producing well.
"Play"	A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.
"Porosity"	Porosity is the percentage of pore volume or void space, or that volume within rock that can contain fluids. Porosity can be a relic of deposition (primary porosity, such as space between grains that were not compacted together completely) or can develop through alteration of the rock (secondary porosity, such as when feldspar grains or fossils are preferentially dissolved from sandstones).
"Pre-stack, depth-migrated seismic data processing"	A type of seismic data processing used to position recorded seismic reflections into their correct subsurface location and depth.
"Productive well"	A well that has been drilled to the targeted depth and proves, in our opinion, to be capable of producing either oil or gas in sufficient quantities that will justify completion as an oil or gas well.

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"Prospect(s)"	Potential trap which may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least not in commercial volumes.
"Proved reserves"	Estimated quantities of crude oil, natural gas, NGL's which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).
"Reservoir"	A subsurface body of rock having sufficient porosity and permeability to store and to allow for the mobility of fluids/hydrocarbons included in its pores.
"Royalty"	A fractional undivided interest in the production of oil and natural gas wells, or the proceeds therefrom to be received free and clear of all costs of development, operations or maintenance.
"Signature bonus"	Usually one time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.
"Shut in"	To close the valves on a well so that it stops producing.
"Spud"	The very beginning of drilling operations of a new well, occurring when the drilling bit penetrates the surface utilizing a drilling rig capable of drilling the well to the authorized total depth.
"Wave equation, pre-stack, depth-migrated seismic data processing"	A type of seismic data processing.
"Wide-azimuth seismic data"	Seismic data acquired with receivers located in long lines that have sources positioned in line with additional sources positioned at large lateral offsets. This acquisition is repeated in closely positioned parallel lines to yield 3-D seismic data coverage with increased azimuths of energy penetration.
"Working interest"	An interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner's royalty, any overriding royalties, production costs, taxes and other costs.
"Workover"	Operations on a producing well to restore or increase production.

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PART IV

Item 15.    Exhibits and Financial Statement Schedules

(a)

The following documents are filed as part of this Annual Report on Form 10-K:

(1)    Financial Statements

Cobalt International Energy, Inc. (pka Cobalt International Energy, L.P.)

Management's Report on Internal Control over Financial Reporting	F-2
Reports of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets of Cobalt International Energy, Inc. as of December 31, 2012 and 2011	F-5
Consolidated Statements of Operations of Cobalt International Energy, Inc. for the years ended December 31, 2012, 2011 and 2010, and for the period November 10, 2005 (Inception) through December 31, 2012	F-6
Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity of Cobalt International Energy, Inc. for the years ended December 31, 2012, 2011 and 2010, and for the period November 10, 2005 (Inception) through December 31, 2012.	F-7
Consolidated Statements of Cash Flows of Cobalt International Energy, Inc. for the years ended December 31, 2012, 2011 and 2010, and for the period November 10, 2005 (Inception) through December 31, 2012	F-8
Notes to Consolidated Financial Statements	F-9

(2)    Financial Statement Schedule

        Not applicable.

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(3)    Exhibits

        The following exhibits are filed with this Annual Report on Form 10-K or incorporated by reference:

Exhibit Number			Description of Document
	3.1		Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579))
	3.2		By-laws of the Company (incorporated by reference to Exhibit 3 to the Company's Registration Statement on Form 8-A filed December 11, 2009 (File No. 001-34579))
	4.1		Specimen stock certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	4.2		Base Indenture, dated as of December 17, 2012 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed December 17, 2012 (File No. 001-34579))
	4.3		First Supplemental Indenture, dated as of December 17, 2012 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed December 17, 2012 (File No. 001-34579))
	4.4		Form of 2.625% Convertible Senior Note due 2019 (incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed December 17, 2012 (File No. 001-34579))
	10.1	†	Employment Agreement, dated November 12, 2009, among the Company, the Partnership and Joseph H. Bryant (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.2	†	Employment Agreement, dated October 23, 2009, among the Company, the Partnership and James H. Painter (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.3	†	Employment Agreement, dated October 23, 2009, among the Company, the Partnership and James W. Farnsworth (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.4	†	Severance Agreement, dated October 23, 2009, among the Company, the Partnership and John P. Wilkirson (incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.5		Risk Services Agreement relating to Block 9, between CIE Angola Block 9 Ltd., Sonangol, Sonangol Pesquisa e Produção, S.A., Nazaki Oil and Gás and Alper Oil, Lda (incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579))
	10.6		Risk Services Agreement relating to Block 21, between CIE Angola Block 21 Ltd., Sonangol, Sonangol Pesquisa e Produção, S.A., Nazaki Oil and Gás and Alper Oil, Lda (incorporated by reference to Exhibit 10.8 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579))
	10.7		Exploration and Production Sharing Contract, dated December 13, 2006, between the Republic of Gabon and Total Gabon, S.A. (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))

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Exhibit Number			Description of Document
	10.8		Assignment Agreement, dated November 29, 2007, between CIE Gabon Diaba Ltd. and Total Gabon, S.A. (incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.9		Simultaneous Exchange Agreement, dated April 6, 2009, between the Partnership and TOTAL E&P USA, INC. (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-1/A filed October 9, 2009 (File No. 333-161734))
	10.10		Gulf of Mexico Program Management and AMI Agreement, dated April 6, 2009, between the Partnership and TOTAL E&P USA, INC. (incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1/A filed October 9, 2009 (File No. 333-161734))
	10.11		Offshore Daywork Drilling Contract, dated May 3, 2008, between the Partnership and Ensco Offshore Company (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.12	†	Form of Restricted Stock Award Agreements relating to the Class B interests (incorporated by reference to Exhibit 10.10 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.13	†	Form of Restricted Stock Award Agreements relating to the Class C interests (incorporated by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.14	†	Form of Restricted Stock Award Agreements relating to the Class D interests (incorporated by reference to Exhibit 10.12 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.15	†*	Amended and Restated Long Term Incentive Plan of the Company
	10.16	†	Annual Incentive Plan of the Company (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579))
	10.17	†	Non-Employee Directors Compensation Plan (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed January 29, 2010 (File No. 001-34579))
	10.18	†	Non-Employee Directors Deferral Plan (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed January 29, 2010 (File No. 001-34579))
	10.19	†	Form of Restricted Stock Unit Award Notification under the Non-Employee Directors Compensation Plan (incorporated by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K filed January 29, 2010 (Filed No. 001-34579))
	10.20		Production Sharing Contract, dated December 20, 2011, between CIE Angola Block 20 Ltd., Sociedade Nacional de Combustíveis de Angola—Empresa Pública, Sonangol Pesquisa e Produção, S.A., BP Exploration Angola (Kwanza Benguela) Limited, and China Sonangol International Holding Limited (incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K filed February 21, 2012 (File No. 001-34579))
	10.21		Form of Director Indemnification Agreements (incorporated by reference to Exhibit 10.19 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))

91

Exhibit Number			Description of Document
	10.22	†	Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K filed March 1, 2011 (File No. 001-34579)).
	10.23	†	Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.27 to the Company's Annual Report on Form 10-K filed March 1, 2011 (File No. 001-34579)).
	10.24	†	Separation Agreement between Rodney L. Gray and the Company, dated June 16, 2010, (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed June 21, 2010 (File No. 001-34579)).
	10.25		International Daywork Drilling Contract—Offshore, dated November 8, 2010 between CIE Angola Block 21 Ltd. and Z North Sea Ltd. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed November 12, 2010 (File No. 001-34579)).
	10.26		Special Standby Rate and Potential Suspension Agreement dated November 9, 2010 between Cobalt International Energy, L.P. and Ensco Offshore Company (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed November 12, 2010 (File No. 001-34579)).
	10.27	†	Form of Amendment to Employment Agreements with Joseph H. Bryant, James H. Painter and James W. Farnsworth and Severance Agreements with Samuel H. Gillespie and John P. Wilkirson (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed November 12, 2010 (File No. 001-34579)).
	10.28	†	Employment Agreement, dated September 6, 2011, between the Company and Van P. Whitfield (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed September 8, 2011 (File No. 001-34579))
	10.29		Severance Agreement, dated April 1, 2010, between the Company and Michael D. Drennon (incorporated by reference to Exhibit 10.30 to the Company's Annual Report on Form 10-K filed February 21, 2012 (File No. 001-34579))
	10.30		Registration Rights Agreement, dated December 15, 2009, among the Company and the parties that are signatory thereto (incorporated by reference to Exhibit 10.31 to the Company's Annual Report on Form 10-K filed February 21, 2012 (File No. 001-34579))
	10.31		Offshore Drilling Contract between CIE Angola Block 21 Ltd. and Universal Energy Resources, Inc., dated July 30, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed October 30, 2012 (File No. 001-34579))
	10.32		Underwriting Agreement dated as of February 23, 2012 (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed February 24, 2012 (File No. 001-34579))
	10.33		Underwriting Agreement dated as of December 11, 2012 (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed December 17, 2012 (File No. 001-34579))
	10.34		Underwriting Agreement dated as of January 15, 2013 (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed January 18, 2013 (File No. 001-34579))
	10.35	*	Deferred Compensation Plan of the Company

92

Exhibit Number			Description of Document
	10.36	*	Amended and Restated Stockholders Agreement, dated February 21, 2013, among the Company and the stockholders that are signatory thereto
	21.1	*	List of Subsidiaries
	23.1	*	Consent of Ernst & Young LLP
	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.

†

Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b).

93

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Cobalt International Energy, Inc.
	By:	/s/ JOSEPH H. BRYANT
		Name:	Joseph H. Bryant
		Title:	Chairman of the Board of Directors and Chief Executive Officer
Dated: February 26, 2013

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ JOSEPH H. BRYANT Joseph H. Bryant	Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)	February 26, 2013
/s/ JOHN P. WILKIRSON John P. Wilkirson	Chief Financial Officer and Executive Vice President (Principal Financial Officer and Principal Accounting Officer)	February 26, 2013
/s/ PETER R. CONEWAY Peter R. Coneway	Director	February 26, 2013
/s/ MICHAEL G. FRANCE Michael G. France	Director	February 26, 2013
/s/ JACK E. GOLDEN Jack E. Golden	Director	February 26, 2013
/s/ N. JOHN LANCASTER N. John Lancaster	Director	February 26, 2013

94

Signature	Title	Date
/s/ SCOTT L. LEBOVITZ Scott L. Lebovitz	Director	February 26, 2013
/s/ JON A. MARSHALL Jon A. Marshall	Director	February 26, 2013
/s/ KENNETH W. MOORE Kenneth W. Moore	Director	February 26, 2013
/s/ KENNETH A. PONTARELLI Kenneth A. Pontarelli	Director	February 26, 2013
/s/ MYLES W. SCOGGINS Myles W. Scoggins	Director	February 26, 2013
/s/ D. JEFF VAN STEENBERGEN D. Jeff van Steenbergen	Director	February 26, 2013
/s/ MARTIN H. YOUNG, JR. Martin H. Young, Jr.	Director	February 26, 2013

95

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
COBALT INTERNATIONAL ENERGY, INC.

Management's Report on Internal Control over Financial Reporting	F-2
Reports of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets of Cobalt International Energy, Inc. as of December 31, 2012 and 2011	F-5
Consolidated Statements of Operations of Cobalt International Energy, Inc. for the years ended December 31, 2012, 2011 and 2010, and for the period November 10, 2005 (Inception) through December 31, 2012.	F-6
Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity of Cobalt International Energy, Inc. for the years ended December 31, 2012, 2011 and 2010, and for the period November 10, 2005 (Inception) through December 31, 2012.	F-7
Consolidated Statements of Cash Flows of Cobalt International Energy, Inc. for the years ended December 31, 2012, 2011 and 2010, and for the period November 10, 2005 (Inception) through December 31, 2012.	F-8
Notes to Consolidated Financial Statements	F-9

F-1

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

        Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by Securities and Exchange Commission rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States (GAAP). Our internal control over financial reporting includes those policies and procedures that:

•

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

•

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and

•

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

        There are inherent limitations to the effectiveness of internal control over financial reporting, however well designed, including the possibility of human error and the possible circumvention of or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that an internal control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

        Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

        Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2012. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

/s/ JOSEPH H. BRYANT
Joseph H. Bryant
Chairman of the Board of Directors and Chief Executive Officer /s/ JOHN P. WILKIRSON
John P. Wilkirson
Chief Financial Officer and Executive Vice President

F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of
Cobalt International Energy, Inc.

        We have audited Cobalt International Energy, Inc.'s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Cobalt International Energy, Inc.'s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, Cobalt International Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2012 consolidated financial statements of Cobalt International Energy, Inc. (a development stage enterprise) and our report dated February 26, 2013 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas
February 26, 2013

F-3

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of
Cobalt International Energy, Inc.

        We have audited the accompanying consolidated balance sheets of Cobalt International Energy, Inc. (a development stage enterprise) as of December 31, 2012 and 2011, and the related consolidated statements of operations, changes in partners' capital and stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2012 and for the period November 10, 2005 (inception) through December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cobalt International Energy, Inc. at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012 and for the period November 10, 2005 (inception) through December 31, 2012, in conformity with U.S. generally accepted accounting principles.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cobalt International Energy, Inc.'s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2013 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas
February 26, 2013

F-4

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

Consolidated Balance Sheets

	December 31,
	2012			2011
	($ in thousands, except per share data)
Assets
Current assets:
Cash and cash equivalents	$	1,425,815		$	292,546
Joint interest and other receivables		61,592			56,983
Prepaid expenses and other current assets		23,941			22,214
Inventory		65,286			36,049
Short-term restricted funds		90,440			69,009
Short-term investments		789,668			858,293
Total current assets		2,456,742			1,335,094
Property, plant, and equipment:
Oil and gas properties, successful efforts method of accounting, net of accumulated depletion of $0		1,094,464			861,955
Other property and equipment, net of accumulated depreciation and amortization of $4,751 and $3,555, as of December 31, 2012 and 2011, respectively		5,292			1,371
Total property, plant, and equipment, net		1,099,756			863,326
Long-term restricted funds		395,652			270,235
Long-term investments		36,267			47,232
Other assets		23,042			12,057
Total assets	$	4,011,459		$	2,527,944
Liabilities and Stockholders' Equity
Current liabilities:
Trade and other accounts payable	$	67,876		$	71,186
Accrued liabilities		44,061			34,418
Short-term contractual obligations		49,019			132,465
Total current liabilities		160,956			238,069
Long-term debt		991,191			—
Long-term contractual obligations		168,238			210,961
Other long-term liabilities		1,856			—
Total long-term liabilities		1,161,285			210,961
Stockholders' equity:
Common stock, $0.01 par value per share; 2,000,000,000 shares authorized 406,596,884 and 387,531,630 issued and outstanding as of December 31, 2012 and 2011, respectively		4,066			3,875
Additional paid-in capital		3,612,987			2,719,875
Accumulated deficit during the development stage		(927,835	)		(644,836	)
Total stockholders' equity		2,689,218			2,078,914
Total liabilities and stockholders' equity	$	4,011,459		$	2,527,944

See accompanying notes.

F-5

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

Consolidated Statements of Operations

										For the Period November 10, 2005 (Inception) Through December 31, 2012
	Year Ended December 31
	2012			2011			2010
	($ in thousands except per share data)
Oil and gas revenue	$	—		$	—		$	—		$	—
Operating costs and expenses:
Seismic and exploration		61,583			32,239			45,030			390,173
Dry hole expense and impairment		134,085			45,732			44,178			238,733
General and administrative		87,963			59,130			48,063			305,942
Depreciation and amortization		1,197			735			787			4,751
Total operating costs and expenses		284,828			137,836			138,058			939,599
Operating income (loss)		(284,828	)		(137,836	)		(138,058	)		(939,599	)
Other income (expense):
Interest income		5,041			4,199			1,582			15,044
Interest expense		(3,212	)		—			—			(3,280	)
Total other income (expense)		1,829			4,199			1,582			11,764
Net income (loss) before income tax		(282,999	)		(133,637	)		(136,476	)		(927,835	)
Income tax expense		—			—			—			—
Net income (loss)	$	(282,999	)	$	(133,637	)	$	(136,476	)	$	(927,835	)
Basic and diluted income (loss) per common share	$	(0.70	)	$	(0.35	)	$	(0.39	)
Weighted average common shares outstanding		403,356,174			376,603,520			349,342,050

See accompanying notes.

F-6

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

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) through December 31, 2008		—		1,029,572			4,365			—			—			—			(293,466	)		740,471
Class A limited partners' contributions		—		227,166			—			—			—			—			—			227,166
Class B and C limited partners' equity compensation		—		—			2,619			734			—			—			—			3,353
Common stock issued upon corporate reorganization		—		(1,256,738	)		(6,984	)		(734	)		2,743			1,261,713			—			—
Equity based compensation		—		—			—			—			—			2,402			—			2,402
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
Net income (loss)		—		—			—			—			—			—			(81,257	)		(81,257	)
Balance, December 31, 2009		—		—			—			—			3,405			2,112,900			(374,723	)		1,741,582
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 for restricted stock		—		—			—			—			22			(22	)		—			—
Equity based compensation		—		—			—			—			—			12,672			—			12,672
Net income (loss)		—		—			—			—			—			—			(136,476	)		(136,476	)
Balance, December 31, 2010	$	—	$	—		$	—		$	—		$	3,507		$	2,226,726		$	(511,199	)	$	1,719,034
Common stock issued at public offering, net of costs		—		—			—			—			357			477,846			—			478,203
Common stock issued for restricted stock		—		—			—			—			12			(12	)		—			—
Equity based compensation		—		—			—			—			—			15,505			—			15,505
Common stock withheld for taxes on equity based compensation		—		—			—			—			(1	)		(190	)		—			(191	)
Net income (loss)		—		—			—			—			—			—			(133,637	)		(133,637	)
Balance, December 31, 2011	$	—	$	—		$	—		$	—		$	3,875		$	2,719,875		$	(644,836	)	$	2,078,914
Common stock issued at public offering, net of costs		—		—			—			—			181			489,128			—			489,309
Common stock issued for restricted stock and restricted stock units		—		—			—			—			10			(10	)		—			—
Equity based compensation		—		—			—			—			—			22,410			—			22,410
Exercise of stock options		—		—			—			—			—			338			—			338
Common stock withheld for taxes on equity based compensation		—		—			—			—			—			(170	)		—			(170	)
Conversion option relating to 2.625% convertible senior notes, net of allocated costs		—		—			—			—			—			381,416			—			381,416
Net income (loss)		—		—			—			—			—			—			(282,999	)		(282,999	)
Balance, December 31, 2012	$	—	$	—		$	—		$	—		$	4,066		$	3,612,987		$	(927,835	)	$	2,689,218

See accompanying notes.

F-7

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

Consolidated Statements of Cash Flows

										For the Period November 10, 2005 (Inception) Through December 31, 2012
	Year Ended December 31
	2012			2011			2010
	($ In thousands)
Cash flows provided from operating activities
Net income (loss)	$	(282,999	)	$	(133,637	)	$	(136,476	)	$	(927,835	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization		1,197			735			787			4,751
Dry hole expense and impairment of unproved properties		134,085			45,732			44,178			238,733
Equity based compensation		22,410			15,505			12,672			60,707
Amortization of premium (accretion of discount)		15,091			22,082			1,608			32,811
Other		—			—			—			558
Changes in operating assets and liabilities:
Joint interest and other receivables		(1,518	)		(59,515	)		31,266			(60,118	)
Inventory		(29,237	)		(1,621	)		(28,047	)		(65,286	)
Prepaid expense and other current assets		(1,726	)		(13,209	)		398			(23,941	)
Deferred charges		(10,985	)		2,467			(14,524	)		(23,042	)
Trade and other accounts payable		(3,309	)		59,196			(22,977	)		67,877
Accrued liabilities and other		16,594			4,470			(22,149	)		57,314
Net cash provided by (used in) operating activities		(140,397	)		(57,795	)		(133,264	)		(637,471	)
Cash flows from investing activities
Capital expenditures for oil and gas properties		(142,841	)		—			(1,746	)		(846,948	)
Capital expenditures for other property and equipment		(5,139	)		(782	)		(1,185	)		(10,065	)
Exploratory wells drilling in process		(329,534	)		(86,979	)		(32,585	)		(593,905	)
Proceeds from sale of oil and gas properties		—			—			5,656			339,001
Change in restricted cash		29,573			(541	)		(151,527	)		(312,087	)
Proceeds from maturity of investment securities		1,082,876			1,288,067			224,985			2,597,706
Purchase of investment securities		(1,199,696	)		(1,630,156	)		(801,970	)		(3,633,737	)
Net cash provided by (used in) investing activities		(564,761	)		(430,391	)		(758,372	)		(2,460,035	)
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		—			—			101,256			950,703
Proceeds from public offering, net of costs		489,309			478,203			—			967,511
Proceeds from debt offering, net of costs		1,348,950			—			—			1,348,950
Proceed from exercise of stock options		338			—			—			338
Payments for common stock withheld for taxes on equity based compensation		(170	)		(191	)		—			(361	)
Net cash provided by (used in) financing activities		1,838,427			478,012			101,256			4,523,321
Net increase (decrease) in cash and cash equivalents		1,133,269			(10,174	)		(790,380	)		1,425,815
Cash and cash equivalents, beginning of period		292,546			302,720			1,093,100			—
Cash and cash equivalents, end of period	$	1,425,815		$	292,546		$	302,720		$	1,425,815
Non-Cash Disclosures
Change in accrued capital expenditures	$	(105,802	)	$	357,900		$	2,011		$	17,048
Transfer of investment securities to and from restricted funds	$	178,830		$	—		$	—		$	178,830

See accompanying notes.

F-8

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

Notes to Consolidated Financial Statements

1. Organization and Operations

Organization

        Cobalt International Energy, Inc. (the "Company") was incorporated pursuant to the laws of the State of Delaware in August 2009 to become a holding company for Cobalt International Energy, L.P. (the "Partnership"). The Partnership is a Delaware limited partnership formed on November 10, 2005, by funds affiliated with Goldman, Sachs & Co., Riverstone Holdings LLC and The Carlyle Group as well as members of the Partnership's management team, collectively constituting Class A limited partners. In 2006, funds affiliated with KERN Partners Ltd. and certain limited partners in such funds affiliated with KERN Partners Ltd, were admitted as Class A limited partners. In 2007, First Reserve Corporation and Four Winds Consulting were admitted as Class A limited partners.

        A corporate reorganization occurred concurrently with the completion of the initial public offering ("IPO") on December 21, 2009. All the outstanding interests of the Partnership were exchanged for 283,200,000 shares of the Company's common stock and as a result the Partnership became wholly-owned by the Company. The shares of CIP GP Corp., the general partner of the Partnership were contributed by certain of the Class A limited partners holding such shares to the Company for no consideration. In December 2011, GIP GP Corp. merged into a Delaware limited liability company, Cobalt International Energy, GP LLC. Prior to reorganization, the Company was not subject to federal or state income taxes. Upon completion of the corporate reorganization, the Company became subject to federal and state income taxes.

        On December 21, 2009 the Company closed its IPO with the issuance of 63,000,000 shares of common stock from the public offering and 3,125,000 of shares issued in a private placement at a price of $13.50 per share. On January 7, 2010, the Company closed the sale of an additional 7,978,000 shares of its common stock at the public offering price of $13.50 per share pursuant to the exercise of the over-allotment option by the underwriters of the IPO.

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

Operations

        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 both the U.S. Gulf of Mexico at North Platte, Heidelberg and Shenandoah and offshore Angola at Cameia. The Company's plan is to continue to mature and drill what it believes are its most promising prospects in the deepwater of the U.S. Gulf of Mexico and the deepwater offshore Angola and Gabon as it further appraises, evaluates and progresses its existing discoveries toward potential sanction and development. The Company operates its business in two geographic segments: the U.S. Gulf of Mexico and West Africa.

        As of December 31, 2012, the Company had no proved oil and gas reserves.

F-9

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

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies

Basis of Presentation

        The accompanying 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 relating to "Development Stage Entities."

        At December 31, 2012, the accompanying consolidated financial statements include the accounts of Cobalt and its wholly owned subsidiary, Cobalt International Energy, L.P. ("Partnership"). Prior to the effective date of the corporate reorganization, both entities were under common control arising from common direct or indirect ownership of each. The transfer of the Partnership interests to Cobalt represented a reorganization of entities under common control and was accounted for at historical cost. See Note 1.

Reclassifications

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

Use of Estimates

        The preparation of financial statements in conformity with United States generally accepted accounting principles ("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 the Company makes include (a) accruals related to expenses, (b) assumptions used in estimating fair value of equity based awards and the fair value of the liability component of the convertible senior notes and (c) assumptions used in impairment testing. Although the Company believes these estimates are reasonable, actual results could differ from these estimates.

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,

F-10

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

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

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.

Revenue Recognition

        The Company will follow the "sales" (or cash) method of accounting for oil and gas revenues. Under this method, the Company will recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which the Company is entitled based on its ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. For the years ended December 31, 2012, 2011, 2010 and for the period November 10, 2005 (Inception) through December 31, 2012, no revenues have been recognized in these consolidated financial statements.

Cash and Cash Equivalents

        Cash and cash equivalents consist of demand deposits and funds invested in highly liquid instruments with maturities of three months or less from the date of purchase. Demand deposits typically exceed federally insured limits; however, the Company periodically assesses the financial condition of the institutions where these funds are held as well as the credit ratings of the issuers of the highly liquid instruments and believes that the credit risk is minimal.

Restricted Funds

        Restricted funds primarily consists of funds held in escrow accounts and collateral for letters of credit relating to our operations in the U.S. Gulf of Mexico and offshore Angola.

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 cost 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 and approximate fair market value as of December 31, 2012 and 2011. Income related to these securities is reported as a component of interest income in the Company's consolidated statements of operations. See Note 7—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

F-11

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

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

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. For the years ended December 31, 2012, 2011, 2010 and for the period November 10, 2005 (Inception) through December 31, 2012, the Company has not incurred OTTI of its debt securities.

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 receivables are usually settled within 30 days of the invoice date.

Property, Plant, and Equipment

        The Company uses the "successful efforts" method of accounting for its oil and gas properties. Acquisition costs for unproved leasehold properties and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the areas as a result of drilling those wells. Under the successful efforts method of accounting, proved leasehold costs are capitalized and amortized over the proved developed and undeveloped reserves on a units-of-production basis. Successful drilling costs and developmental dry holes are capitalized and amortized over the proved developed reserves on a units-of-production basis. Significant unproved leasehold costs are capitalized and are not amortized, pending an evaluation of their exploration potential. Unproved leasehold costs are assessed periodically to determine if an impairment of the cost of individual properties has occurred. Factors taken into account for impairment analysis include results of the technical studies conducted, lease terms and management's future exploration plans. The cost of impairment is charged to expense in the period in which it occurs. Costs incurred for exploratory dry holes, geological and geophysical work (including the cost of seismic data), and delay rentals are charged to expense as incurred. Costs of other property and equipment are depreciated on a straight-line based on their respective useful lives.

Asset Retirement Obligations

        The Company currently does not have any oil and natural gas production or any legal obligations to incur decommissioning in costs. Should such production occur in the future, the Company expects to have significant obligations under its lease agreements and federal regulation to remove its equipment and restore land or seabed at the end of oil and natural gas production operations. These asset retirement obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and natural gas platforms. Estimating the future restoration and removal cost is difficult and requires the Company to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulation often have vague descriptions of what constitutes removal. Asset removal technologies and cost are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Pursuant to the accounting guidance relating to "Assets Retirement Obligations." The Company is required to record a separate liability for the estimated fair value of its asset retirement obligations, with an offsetting

F-12

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

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

increase to the related oil and natural gas properties representing asset retirement costs on its balance sheet. The cost of the related oil and natural gas asset, including the asset retirement cost, is depreciated over the useful life of the asset. The estimated fair value of asset retirement obligations is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

        Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, the Company will make corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. Increases in the discounted abandonment liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the consolidated statements of operations.

Inventory

        Inventories consist of various tubular products that are used in the Company's drilling programs. The products are stated at the average cost. Cost is determined using a weighted average method comprised of purchase price and other directly attributable costs.

Income Taxes

        The Company applied the liability method of accounting for income taxes in accordance with accounting guidance related to "Income Taxes" as clarified by "Accounting for Uncertainty in Income Taxes." Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Since the Company is in development stage and there can be no assurance that the Company will generate any earnings or any specific level of earnings in future years, the Company has established a valuation allowance that equals its net deferred tax assets. See Note 17.

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, on a straight-line basis 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. See Note 15.

F-13

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

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Earnings (Loss) Per Share

        Basic earnings (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. Diluted earnings (loss) per share incorporate the potential dilutive impact of options and unvested stock outstanding during the periods presented, unless their effect is anti-dilutive. In addition, the Company applies the if-converted method to our convertible debt instruments, the effect of which is that conversion will not be assumed for purposes of computing diluted earnings (loss) per share if the effect would be anti-dilutive.

Operating Costs and Expenses

        Expenses consist primarily of the costs of acquiring and processing of geological and geophysical data, exploration and appraisal drilling expenses, consultants, telecommunications, payroll and benefit costs, information system and legal costs, office rent, contract costs, and bookkeeping and audit fees.

3. Cash and Cash Equivalents

        As of December 31, 2012 and 2011, cash and cash equivalents consisted of the following:

	December 31,
	2012		2011
	(in thousands)
Cash at banks	$	65,935	$	2,992
Money market funds		1,105,148		104,805
Held-to-maturity securities(1)		254,732		184,749
	$	1,425,815	$	292,546

(1)

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

4. Restricted Funds

        Restricted funds consisted of the following:

	December 31,
	2012		2011
	(in thousands)
Short-term:
Ocean Confidence escrow account	$	—	$	10,804
Collateral on Letters of Credit for Angola(1)		—		53,322
Ensco 8503 escrow account(2)		90,440		4,883
	$	90,440	$	69,009
Long-term:
Ensco 8503 escrow account(2)	$	90,440	$	181,159
Collateral on Letters of Credit for Angola(1)		304,492		88,358
Other vendor restricted deposits		720		718
	$	395,652	$	270,235

(1)

As of December 31, 2012, $304.5 million was held in a collateral account established for letters of credit issued in support of the Company's contractually agreed work program

F-14

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

Notes to Consolidated Financial Statements (Continued)

4. Restricted Funds (Continued)

obligations on Blocks 9, 20 and 21 offshore Angola. The collateral in this account was invested in U.S. Treasury bills and Treasury notes purchased at discounts and at premiums, respectively, resulting in a net carrying value of $302.9 million and in money market funds with total net carrying value of $1.6 million as of December 31, 2012. The contractual maturities of these securities are within one year.

(2)

$180.9 million was held in an escrow account established since December 2009 as a guarantee of performance to Ensco Offshore Company for the Ensco 8503 drilling rig contract. As of December 31, 2012, the Company reclassified $90.4 million from long-term restricted funds to short-term restricted funds as this amount represents 50% reduction of the escrow account upon completion of the first year of the drilling contract from the term commencement date which was January 1, 2012. The Company received the $90.4 million in January 2013. As of December 31, 2012, the short-term and long-term funds in the escrow account were invested in U.S. Treasury bills, purchased at a discount, resulting in a net carrying value of $180.9 million. The contractual maturities of the U.S. Treasury bills are within six months.

5. Joint Interests and Other Receivables

        As of December 31, 2012 and 2011, the balance in joint interest and other receivables consisted of the following:

	December 31,
	2012		2011
	(in thousands)
Partners in the U.S. Gulf of Mexico	$	52,439	$	12,377
Partners in West Africa		2,185		34,311
Accrued interest on investment securities		3,647		7,094
Vendor's receivable		1,526		1,502
Other		1,795		1,699
	$	61,592	$	56,983

6. Prepaid Expenses and Other Current Assets

        Prepaid expenses include the prepaid and unamortized portion of payments made for software licenses, related maintenance fees, and insurance. Other current assets include short-term deposits and current portion of the costs associated with the mobilization and equipment upgrades of the Ensco 8503 drilling rig and subsea containment. As of December 31, 2012 and 2011, prepaid expenses and other current assets were $23.9 million and $22.2 million, respectively.

F-15

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

Notes to Consolidated Financial Statements (Continued)

7. Investments

        The Company's investments in held-to-maturity securities which are recorded at amortized cost and approximate fair market value were as follows at December 31, 2012 and 2011:

	December 31,
	2012		2011
	(in thousands)
U.S. Treasury securities	$	483,775	$	379,618
Corporate securities		510,691		535,846
Commercial paper		562,975		369,432
U.S. government agency securities		—		71,856
Municipal bonds		—		42,193
Certificates of deposit		7,000		12,500
Total	$	1,564,441	$	1,411,445

        The Company's held-to-maturity securities were included in the following captions in the Company's balance sheets:

	December 31,
	2012		2011
	(in thousands)
Cash and cash equivalents	$	254,732	$	184,749
Short-term investments		789,668		858,293
Short-term restricted funds		90,440		53,322
Long-term restricted funds		393,334		267,849
Long-term investments		36,267		47,232
	$	1,564,441	$	1,411,445

        The contractual maturities of these held-to-maturity securities at December 31, 2012 and 2011 were as follows:

	December 31,
	2012				2011
	Amortized Cost		Estimated Fair Value		Amortized Cost		Estimated Fair Value
	($ in thousands)
Within 1 year	$	1,528,174	$	1,528,174	$	1,364,213	$	1,364,213
After 1 year		36,267		36,267		47,232		47,232
	$	1,564,441	$	1,564,441	$	1,411,445	$	1,411,445

F-16

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

Notes to Consolidated Financial Statements (Continued)

8. Fair Value Measurements

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

	Level 1				Level 2
	Amortized Cost		Fair Value(1)		Amortized Cost		Fair Value(1)		Balance as of December 31, 2012
	($ 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
Certificate 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

F-17

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

Notes to Consolidated Financial Statements (Continued)

8. Fair Value Measurements (Continued)

	Level 1				Level 2
	Amortized Cost		Fair Value(1)		Amortized Cost		Fair Value(1)		Balance as of December 31, 2011
	($ in Thousands)
Cash and cash equivalents:
Cash	$	2,992	$	2,992	$	—	$	—	$	2,992
Money market funds		104,805		104,805		—		—		104,805
Commercial paper		—		—		172,249		172,249		172,249
Certificate of deposits		—		—		12,500		12,500		12,500
Subtotal		107,797		107,797		184,749		184,749		292,546
Short-term restricted funds:
Cash		4,883		4,883		—		—		4,883
Money market funds		10,804		10,804		—		—		10,804
U.S. Treasury bills		—		—		53,322		53,322		53,322
Subtotal		15,687		15,687		53,322		53,322		69,009
Short-term investments:
U.S. Treasury bills		—		—		112,507		112,507		112,507
U.S. Government agency securities		—		—		40,000		40,000		40,000
Corporate bonds		—		—		466,411		466,411		466,411
Municipal bonds		—		—		42,193		42,193		42,193
Commercial paper		—		—		197,182		197,182		197,182
Subtotal		—		—		858,293		858,293		858,293
Long-term restricted funds:
Cash		718		718		—		—		718
Money market funds		1,668		1,668		—		—		1,668
U.S. Treasury bills		—		—		40,597		40,597		40,597
U.S. Treasury notes		—		—		173,192		173,192		173,192
Corporate bonds		—		—		54,060		54,060		54,060
Subtotal		2,386		2,386		267,849		267,849		270,235
Long-term investments:
U.S. Government agency securities		—		—		31,856		31,856		31,856
Corporate bonds		—		—		15,376		15,376		15,376
Subtotal		—		—		47,232		47,232		47,232
Total	$	125,870	$	125,870	$	1,411,445	$	1,411,445	$	1,537,315

(1)

As of December 31, 2012 and 2011, the Company did not record any OTTI on these assets.

F-18

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

Notes to Consolidated Financial Statements (Continued)

9. Property, Plant, and Equipment

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

		December 31,
	Estimated Useful Life (Years)
		2012			2011
		($ in thousands)
Oil and Gas Properties:
Unproved oil and gas properties		$	721,853		$	701,892
Less: accumulated valuation allowance			(78,413	)		(18,275	)
			643,440			683,617
Exploratory wells in process			451,024			178,338
Total oil and gas properties, net			1,094,464			861,955
Other Property and Equipment:
Computer equipment and software	3		3,166			2,847
Office equipment and furniture	3 - 5		2,093			1,114
Vehicles	3		268			129
Leasehold improvements	3 - 10		2,298			836
			7,825			4,926
Less: accumulated depreciation and amortization(1)			(2,533	)		(3,555	)
Total other property and equipment, net			5,292			1,371
Property, plant, and equipment, net		$	1,099,756		$	863,326

(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 therefore had no impact on the consolidated statements of operations and consolidated statements of cash flow.

        The Company recorded $1.2 million, $0.7 million and $0.8 million of depreciation and amortization expense for the years ended December 31, 2012, 2011 and 2010, respectively, and $4.8 million for the period November 10, 2005 (inception) through December 31, 2012, 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 December 31, 2012, $122.8 million was paid during the first quarter of 2012 and the remaining $214.3 million was accrued in short-term and long-term contractual obligations—see Note 12. In addition to the Block 20 interests, the Company has $10.8 million of unproved property acquisition costs relating to its 40% working interests in Blocks 9 and 21 offshore Angola and its 21.25% working interest in the Diaba block offshore Gabon. As of December 31, 2012, the Company also has $285.6 million of unproved property acquisition costs, net of allowance for impairment, relating to its U.S. Gulf of Mexico properties. The $285.6 million includes

F-19

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

Notes to Consolidated Financial Statements (Continued)

9. Property, Plant, and Equipment (Continued)

$20.0 million of acquisition costs incurred on various working interests in unproved properties located in the U.S. Gulf of Mexico acquired by the Company in 2012. As of December 31, 2012 and 2011, the Company has a net total of $643.4 million and $683.6 million, respectively, of unproved property acquisition costs on the consolidated balance sheets.

        Acquisition costs of unproved leasehold 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. Unproved oil and gas leases for properties in the U.S. Gulf of Mexico with carrying value greater than $1 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 2012 through 2020. As of December 31, 2012 and 2011, the balance for unproved leaseholds that were subject to amortization before impairment provision was $69.1 million and $65.1 million, respectively. The Company recorded lease impairment allowance of $60.2 million, $9.1 million and $9.1 million for years ended December 31, 2012, 2011, 2010, respectively and $78.4 million for the period November 10, 2005 (inception) through December 31, 2012.

Capitalized Exploratory Well 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 location before proceeding with development activities.

F-20

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

Notes to Consolidated Financial Statements (Continued)

9. Property, Plant, and Equipment (Continued)

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

	December 31, 2012			December 31, 2011
	($ in thousands)
Beginning of period	$	178,338		$	106,881
Addition to capitalized exploratory well cost pending determination of proved reserves
U.S. Gulf of Mexico:
Shenandoah #1 Exploratory Well		200			(53	)
Shenandoah #2 Appraisal Well		12,716			—
Shenandoah #2 Replacement Well		18,271			—
Heidelberg #1 Exploratory Well		(419	)		—
Heidelberg #2 Appraisal Well		—			5,999
Heidelberg #3 Appraisal Well		8,628			4,056
Heidelberg #3 Appraisal Well Side Track		4,108			—
Heidelberg Early Development		5,941			—
Ligurian #2 Exploratory Well		46,961			2,034
Criollo #1 Exploratory Well		—			(822	)
North Platte #1 Exploratory Well		72,559			—
North Platte #1 By-Pass Core		7,229			—
North Platte Early Development		2,042			—
Other Pre-Spud Costs		59			—
West Africa:
Bicuar #1 Exploratory Well pre-spud costs(1)		(3,035	)		25,444
Cameia #1 Exploratory Well		33,958			71,405
Cameia #2 Appraisal Well		133,328			—
Cameia Early Development		4,058			—
Reclassifications to wells, facilities, and equipment based on determination of proved reserves		—			—
Amounts charged to expense(2)		(73,918	)		(36,606	)
End of period	$	451,024		$	178,338

(1)

The amount of $3,035 represents pre-spud mobilization and insurance costs allocated to the Bicuar #1 pre-salt exploratory well planned as one of two exploratory wells initially scheduled to be drilled offshore Angola. With the success of the Cameia #1 exploratory well, the drilling of the Cameia #2 appraisal well was substituted for the Bicuar #1 pre-salt exploratory well. Hence these costs were reallocated to the Cameia #2 appraisal well.

(2)

The amount of $73,918 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 for the year ended December 31, 2012.

F-21

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

Notes to Consolidated Financial Statements (Continued)

9. Property, Plant, and Equipment (Continued)

	Spud Year		December 31, 2012		December 31, 2011
			($ in thousands)
Cumulative costs:
U.S. Gulf of Mexico
Shenandoah #1 Exploratory Well		2008	$	69,668	$	69,468
Shenandoah #2 Appraisal Well		2012		—		—
Shenandoah #2 Replacement Well		2012		18,272		—
Heidelberg #1 Exploratory Well		2008		19,822		20,240
Heidelberg #3 Appraisal Well		2011		12,683		4,056
Heidelberg Early Development		2012		5,941		—
Ligurian #1 Exploratory Well		2009		—		8,100
Ligurian #2 Exploratory Well		2011		—		2,034
North Platte #1 Exploratory Well		2012		72,559		—
North Platte #1 By Pass Core		2012		7,229		—
North Platte Early Development		2012		2,042		—
Other Pre-Spud Costs		2012		59		—
West Africa:
Bicuar #1 Exploratory Well		2011		—		3,035
Cameia #1 Exploratory Well		2011		105,363		71,405
Cameia #2 Appraisal Well		2012		133,328		—
Cameia Early Development		2012		4,058		—
			$	451,024	$	178,338
Exploratory Well costs capitalized for a period greater than one year after completion of drilling (included in table above)			$	194,853	$	97,861

        As of December 31, 2012, capitalized exploratory well costs that have been suspended longer than one year are associated with the Shenandoah #1, Heidelberg #1 and Cameia #1 projects. These exploratory well costs 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 projects 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 projects, the associated costs will be expensed at that time.

        As of December 31, 2012, no exploratory wells have been drilled by the Company offshore Gabon.

10. Other Assets

        As of December 31, 2012, the $23.0 million in other assets includes the debt issue costs associated with the issuance of the 2.625% convertible senior notes, as described in Note 11, and which are amortized over the life of the Notes using the effective interest method. As of December 31, 2011, the $12.1 million in other assets includes costs associated with the mobilization and equipment upgrades of the Ensco 8503 drilling rig and subsea containment were amortized over the terms of the drilling rig

F-22

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

Notes to Consolidated Financial Statements (Continued)

10. Other Assets (Continued)

contract. These costs were fully expensed or capitalized to oil and gas properties as exploratory drilling costs, depending on the drilling results as of December 31, 2012.

11. 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 will be payable semi-annually in arrears on June 1 and December 1 of each year, beginning on June 1, 2013. The Notes will mature on December 1, 2019, unless earlier repurchased or converted in accordance 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 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 rates used to amortize the debt discount and the liability component of the debt issue costs were approximately 8.01% and 8.40%, respectively, 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

F-23

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

Notes to Consolidated Financial Statements (Continued)

11. Long-term Debt (Continued)

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:

	December 31,
	2012							2011
	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	$	(388,809	)	$	991,191	$	—	$	—	$	—

(1)

Unamortized discount will be amortized over the remaining life of the Notes which is 7 years.

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

	December 31,
	2012			2011
Carrying amount of equity component of 2.625% convertible senior notes
Debt discount relating to value of conversion option	$	390,540		$	—
Debt issue costs		(9,124	)		—
Total	$	381,416		$	—

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

        Interest expense, excluding amortization of debt issue costs, was as follows:

							For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Interest expense associate with accrued interest	$	1,409	$	—	$	—	$	1,409
Interest expense associated with accretion of debt discount		1,731		—		—		1,731
Total	$	3,140	$	—	$	—	$	3,140

F-24

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

Notes to Consolidated Financial Statements (Continued)

12. Contractual Obligations

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

	December 31,
	2012		2011
	($ in thousands)
Short-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	150	$	1,300
Social obligation payments for Block 21, offshore Angola		300		2,600
Social obligation and bonus payments for Block 20, offshore Angola(1)(2)		48,569		128,565
	$	49,019	$	132,465
Long-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	848	$	800
Social obligation payments for Block 21, offshore Angola		1,684		1,600
Social obligation and bonus payments for Block 20, offshore Angola(2)		165,706		208,561
	$	168,238	$	210,961

(1)

$42.9 million of this amount was paid in January 2013.

(2)

The total amount of social obligation payments for Block 20 has been capitalized. See Note 9.

13. Stockholders' Equity

        On April 15, 2011, the Company issued 35,650,000 shares of its common stock at a public offering price of $14.00 per share.

        On December 21, 2011, the Company withheld and cancelled an aggregate amount of 13,763 shares of its common stock, at a price of $13.85 per share, to satisfy tax withholding obligations of certain of our employees that arose upon the lapse of restrictions on restricted stock.

F-25

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

Notes to Consolidated Financial Statements (Continued)

13. Stockholders' Equity (Continued)

        On January 15, 2012, the Company withheld the issuance of an aggregate amount of 9,127 shares of its common stock, at a price of $18.74 per share, to satisfy tax withholding obligations of certain of its officers that arose upon the distribution of deferred stock compensation.

        On February 29, 2012, the Company issued 18,050,000 shares of common stock at a public offering price of $28.00 per share.

        On December 17, 2012, the Company issued $1.38 billion aggregate principal amount of its 2.625% convertible senior notes due 2019. As of December 31, 2012, $381.4 million was recorded as the equity component of the Notes. See also Note 11—Long-term Debt.

14. Seismic and Exploration Expenses

        Seismic and exploration expenses consisted of the following:

								For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Seismic costs	$	42,447	$	20,443	$	39,748		$	342,048
Seismic cost recovery(1)		—		—		(15,126	)		(25,126	)
Leasehold delay rentals		6,383		6,075		5,989			32,903
Force Majeure expense(2)		—		—		13,549			13,549
Drilling rig expense		12,753		5,721		870			26,799
	$	61,583	$	32,239	$	45,030		$	390,173

(1)

These amounts represent reimbursement from partners of past seismic costs incurred by the Company.

(2)

These amounts represent 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.

15. Equity based Compensation

        Overview.    Under the Company's Long Term Incentive Plan (the "Incentive Plan"), the Company may issue stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other stock-based awards to employees. At December 31, 2012, approximately 9.0 million shares remain available for grant under the Incentive Plan.

        On January 28, 2010, the Company adopted the Non-Employee Directors Compensation Plan (the "NED Plan"). Under the NED Plan, the Company may issue options, restricted stock units, other

F-26

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

Notes to Consolidated Financial Statements (Continued)

15. Equity based Compensation (Continued)

stock-based award or retainers to non-employee directors. At December 31, 2012, 555,294 shares remain available for grant under the NED Plan.

        In accordance with ASC No. 718, Compensation—Stock Compensation, the Company recognizes compensation cost for equity-based compensation to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant, net of estimated forfeitures. If actual forfeitures differ from the Company's estimates, additional adjustments to compensation expense will be required in future periods.

        Restricted Stock.    The Company accounted for the restricted stock based on ASC Topic 718 as described above. 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.

        The following table summarizes the information about the restricted stock awarded to employees for each of the three years in the period ended December 31, 2012:

	Years Ended December 31,
	2012					2011					2010
	Restricted Shares			Weighted Average Grant Date Fair Value Per Share		Restricted Shares			Weighted Average Grant Date Fair Value Per Share		Restricted Shares			Weighted Average Grant Date Fair Value Per Share
Non-vested shares at beginning of year		4,599,783		$	11.27		5,570,895		$	9.77		8,015,041		$	7.67
Granted		487,710		$	26.01		214,792		$	8.54		442,156		$	9.96
Vested		(738,628	)	$	13.05		(1,185,904	)	$	3.75		(2,213,277	)	$	0.51
Forfeited or expired		(308,040	)	$	12.17		—			—		(673,025	)	$	15.35
Non-vested shares at end of year		4,040,825		$	13.05		4,599,783		$	11.27		5,570,895		$	9.77
Weighted-average period remaining		1.87 years					2.5 years					3.3 years
Unrecognized compensation ($ in thousands)	$	23,827				$	29,559				$	41,599

        For the year ended December 31, 2010, 45,000 nonvested restricted shares held by a former officer of the Company were accounted for as vested and 585,778 nonvested restricted shares were forfeited pursuant to the terms of the Separation Agreement between the officer and the Company. The terms of the Separation Agreement were accounted for in accordance with ASC No. 718, Compensation—Stock Compensation and resulted in $0.5 million recognized in stock compensation expense for the

F-27

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

Notes to Consolidated Financial Statements (Continued)

15. Equity based Compensation (Continued)

vested shares and $2.4 million recognized as a reduction to the stock compensation expense for the forfeited shares during the year ended December 31, 2010.

        A total of 33,204 restricted stock units awards were granted to non-employee directors during the year ended December 31, 2012 for annual retainers. As of December 31, 2012, the Company has granted a cumulative total of 137,945 restricted stock units to non-employee directors. For the year ended December 31, 2012 and 2011, the Company also granted 12,221 and 23,595 shares of common stock as retainer awards to non-employee directors who elected to be compensated by stock in lieu of cash payments. The weighted average fair value of these shares at grant date was $21.35.

        Non-Qualified Stock Options.    The Company grants non-qualified stock options to employees at an exercise price equal to the market value of the Company's common stock on the grant date. The non-qualified stock option awards have contractual terms of 10 years. The options granted in December 2010 vest ratably over a four-year period from date of grant and the options granted in February 2012 cliff vest on December 31, 2014.

        The fair value of each stock option granted is determined using the Black-Scholes-Merton option-pricing model based on several assumptions. These assumptions are based on management's best estimate at the time of grant. The Company used the following the weighted average of each assumption based on the grants in each fiscal year (there were no new stock options granted in 2011):

	2012
Expected Term in Years		6.50
Expected Volatility		54.92	%
Expected Dividends		0	%
Risk-Free Interest Rate		0.46	%

        The Company estimates expected volatility based on an analysis of its stock price since the IPO and comparing the stock price volatility for the period from IPO date through December 31, 2012 with the historical stock price volatility of a similar exploration and production company. The Company estimates the expected term of its option awards based on the vesting period and average remaining contractual term, referred to as the "simplified method". The Company uses this method to provide a reasonable basis for estimating its expected term based on a lack of sufficient historical employee exercise data on stock option awards.

F-28

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

Notes to Consolidated Financial Statements (Continued)

15. Equity based Compensation (Continued)

        A summary of the stock options activities for the year ended December 31, 2012 is presented below:

	Shares			Weighted Average Exercise Price		Weighted-Average Remaining Contractual Term (years)		Aggregate Intrinsic Value (thousands)
Outstanding at January 1, 2012		1,133,960		$	12.45		8.9	$	7,688
Granted		457,704		$	30.50		9.1
Exercised		(27,147	)	$	12.45		7.9	$	425
Forfeited or expired		(130,124	)	$	16.24
Outstanding at December 31, 2012		1,434,393		$	17.87		8.29	$	12,158
Vested or expected to vest at December 31, 2012		891,665		$	20.81		8.49	$	5,795
Exercisable at December 31, 2012		505,578		$	12.45		7.92	$	6,123

        The weighted-average grant-date fair value of stock options granted during 2012 and 2011 was $17.92 and $0 per option, respectively, using the Black-Scholes option-pricing model. 27,147 stock options were exercised during the year ended December 31, 2012. As of December 31, 2012, there were 1,434,393 shares of common stock underlying outstanding stock options. As of December 31, 2012, $8.3 million of total unrecognized compensation cost related to stock option is expected to be recognized over a weighted-average period of 1.95 years.

        Restricted Stock Units.    On December 3, 2010, the Company granted 198,838 restricted stock units to employees based on the Restricted Stock Unit (RSU) Award Agreement. Under the RSU Award Agreement the share-based payment is earned based on the number of successful wells drilled during the three year period ending December 31, 2013. The RSU award will vest within a range of 0% to 200% of the number of RSU shares awarded on scheduled vesting dates contingent upon the recipient's continued service at each vesting date and based on the achievement of successful wells drilled as defined in the RSU Award Agreement. In no event shall the recipients vest in an amount greater than 200% of the Award or in aggregate 397,676 RSU shares. The percentage of the RSU awards vested at each of the three year periods ending December 31, 2013 is calculated by the number of successful wells drilled during the respective years multiplied by vesting percentage ranging from 25% to 37.5%. The RSU Award Agreement therefore has multiple implicit service periods which are determined by and when the Company drills a successful well. The fair value of the RSUs at grant date was $12.45 per share. However, on February 24, 2012, the Company amended certain terms and conditions of its RSU award agreement which resulted in the Company using the fair value of $30.50 per share at modification date to recognize the equity based compensation expense for the RSUs that vested during 2012. For the year ended December 31, 2012, the Company recognized $4.3 million of stock compensation for the RSUs based on performance targets achieved from the success of the Cameia #1 and North Platte #1 exploratory well, among other considerations. As of December 31, 2012 and 2011, unrecognized compensation cost related to restricted stock units ranged from approximately $2.0 million to $12.1 million.

F-29

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

Notes to Consolidated Financial Statements (Continued)

15. Equity based Compensation (Continued)

        A summary of the restricted stock units activities for the year ended December 31, 2012 is presented below:

	Years Ended December 31,
	2012					2011				2010
	Number of shares relating Restricted Stock Units			Weighted Average Grant Date Fair Value Per Unit		Number of shares relating Restricted Stock Units		Weighted Average Grant Date Fair Value Per Unit		Number of shares relating Restricted Stock Units		Weighted Average Grant Date Fair Value Per Unit
Non-vested at December 31, 2011		198,838		$	12.45		198,838	$	12.45		198,838	$	12.45
Granted		—			—		—		—		—		—
Vested		(74,537	)	$	30.50		—		—		—		—
Forfeited or expired		(15,026	)	$	30.50		—		—		—		—
Non-vested at December 31, 2012		109,275		$	30.50		198,838	$	12.45		198,838	$	12.45
Weighted-average period remaining		1 year					2 years				3 years

        The table below summarizes the equity-based compensation costs recognized for each of the three years in the period ended December 31, 2012, and for the period November 10, 2005 (inception) through December 31, 2012:

							For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Restricted stock:
Employees	$	13,378	$	12,860	$	12,064	$	46,594
Non-employee directors		970		804		507		2,281
Stock options:
Employees		3,790		1,841		101		5,732
Restricted stock units (performance-based)		4,272		—		—		4,272
Deferred stock compensation(1)		—		—		—		1,828
	$	22,410	$	15,505	$	12,672	$	60,707

(1)

In December 2008, the Company adopted a deferred compensation plan and provided certain executive officers the opportunity to defer under the Plan all or a portion of their salary and/or annual bonus for 2009. Amounts deferred under the Plan generally are deemed to be invested in a money market account prior to the IPO and shares of the Company's common stock following the IPO. Subject to accelerated payment under specified circumstances, the deferred amounts were distributed to these executives in January 2012 in the form of shares of the Company's common stock. As of December 31, 2012, there were 121,637 shares under the Plan were distributed to these executives.

F-30

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

Notes to Consolidated Financial Statements (Continued)

16. Employee Benefit Plan

        In 2006, the Company established the Cobalt International Energy, L.P., defined contribution 401(k) plan (the Plan). All employees of the Company after three months of continuous employment are eligible to participate in the Plan. The plan is discretionary and provides a 6% employee contribution match as determined by the Company's Board of Directors. Effective December 31, 2009, the Plan was amended to discontinue the employer's matching contributions. Effective January 1, 2012, the Company reinstituted the 6% employee contribution match. For each of the years ended December 31, 2012, 2011 and 2010, the Company recorded $0.5 million, $0 million and $0 million, respectively, in benefits contributions to the Plan, which are included in the general and administrative expenses. For the period November 10, 2005 (inception) through December 31, 2012, the Company recorded a cumulative of $2.0 million in benefits contributions to the Plan.

17. Income Taxes

        For the years ended December 31, 2012, 2011 and 2010, the Company recorded a net deferred tax asset of $269.6 million, $177.2 million and $97.6 million, respectively with a corresponding full valuation allowance of $269.6 million $177.2 million and $97.6 million, respectively, for the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

        The components of the income tax provision (benefit) are as follows:

	Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Current taxes:
U.S. federal	$	—	$	—	$	—
Foreign		—		—		—
Deferred taxes:
U.S. federal		—		—		—
Foreign		—		—		—
Total	$	—	$	—	$	—

F-31

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

Notes to Consolidated Financial Statements (Continued)

17. Income Taxes (Continued)

        The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company's income tax expense (benefit) for each of the three years in the period ended December 31, 2012 are as follows:

	Year Ended December 31,
	2012			2011			2010
	($ in thousands)
U.S.:
Net income (loss) as reported	$	(229,372	)	$	(76,231	)	$	(93,037	)
Less: net income (loss) applicable to period before corporate reorganization		—			—			—
Foreign:
Net income (loss) as reported	$	(53,627	)		(57,406	)		(43,439	)
Less: net income (loss) applicable to period before corporate reorganization		—			—			—
Net income (loss) applicable to period after corporate reorganization	$	(282,999	)	$	(133,637	)	$	(136,476	)

	Year Ended December 31,
	2012					2011					2010
	($ in thousands)
Income tax expense (benefit) at the federal statutory rate		(99,050	)	35.0	%	$	(46,773	)	35.0	%	$	(47,767	)	35.0	%
State income taxes, net of federal income tax benefit(1)		(512	)	0.2	%		(2,579	)	1.9	%		(339	)	0.3	%
Foreign NOL and deferred adjustments(2)		4,447		-1.6	%		(30,407	)	22.8	%		—		—
Deferred income taxes established at date of corporate reorganization(3)		—		—			—		—			(8,735	)	6.3	%
Other(4)		2,678		-0.9	%		117		0.1	%		176		0.1	%
Valuation allowance		92,437		-32.7	%		79,642		59.6	%		56,665		41.5	%
	$	—		—		$	—		—		$	—		—

(1)

The 2012 state income tax reflects lower franchise apportionment factor in Louisiana resulting from the dissolution of Cobalt's blocker entities in December 2011.

(2)

Prior to 2011, the Company did not have any registered presence for reporting foreign NOLs.

(3)

The $8.7 million in 2010 relates to an adjustment to include the 2009 NOL of an affiliate company acquired during the 2009 pre-IPO corporate reorganization.

(4)

The $2.7 million relates to the excess tax benefits associated with equity based compensation.

        Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax

F-32

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

Notes to Consolidated Financial Statements (Continued)

17. Income Taxes (Continued)

purposes. The significant components of the Company's deferred tax assets and liabilities were as follows:

	As of December 31,
	2012			2011
	($ in thousands)
Deferred tax liabilities:
Oil and gas properties	$	23,867		$	4,555
Other		—			452
Total deferred tax liabilities		23,867			5,007
Deferred tax assets:
Seismic and exploration costs		100,414			54,005
Stock-based compensation		12,340			9,329
Domestic NOL carry forwards		158,310			86,599
Foreign NOL carry forwards		20,624			30,407
Other		1,818			1,869
Valuation allowance		(269,639	)		(177,202	)
Total deferred assets, net		23,867			5,007
Net deferred tax assets	$	—		$	—

        The Company has established a full valuation allowance against the deferred tax assets where the Company has determined that it is more likely than not that all of the deferred tax assets will not be realized. Because of the full valuation allowance, no income tax expense or benefit is reflected on the consolidated statement of operations for each of the three years in the period ended December 31, 2012.

        The NOL carryforward for federal and state income tax purposes of approximately $542.2 million and $43.1 million, respectively, and as of December 31, 2012 begins to expire in 2025 and 2024, respectively. The utilization of the NOL carryforwards is dependent upon generating sufficient future taxable income in the appropriate jurisdictions within the carryforward period.

        As of December 31, 2012, we had NOL carryforward for foreign income tax purposes of approximately $39.8 million which begins to expire in 2014. The company has determined that it is more likely than not, that the foreign NOLs will not be fully realized. Therefore, a full valuation allowance was established for these net deferred tax assets.

        There were no unrecognized tax benefits or accrued interest or penalties associated with unrecognized tax benefits as of December 31, 2012 and 2011.

F-33

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

Notes to Consolidated Financial Statements (Continued)

18. Commitments

        The following table summarizes by period the payments due for our estimated commitments, excluding long-term debt, as of December 31, 2012:

	Payments Due By Year
	2013		2014		2015		2016		2017		Thereafter
	($ in thousands)
Drilling Rig and Related Contracts	$	594,374	$	342,321	$	154,920	$	60,025	$	—	$	—
Operating Leases		11,200		9,860		9,515		6,063		3,571		10,402
Lease Rentals(1)		6,413		5,736		5,502		3,610		3,157		1,071
Social Payment Obligations(2)		49,019		51,101		48,569		62,854		5,714		—
Total	$	661,006	$	409,018	$	218,506	$	132,552	$	12,442	$	11,473

(1)

Relates to the annual delay rental payments payable to the Office of Natural Resources Revenue within the U.S. Department of the Interior with respect to the Company's U.S. Gulf of Mexico leases. These annual payments are required to maintain the leases from year to year.

(2)

Includes the Company's contractual payment obligations for social projects such as the Sonangol Research and Technology Center and academic scholarships for Angolan students that the Company was and is contractually obligated to pay in consideration for the Angolan government granting it the licenses to explore for and develop hydrocarbons offshore Angola. Pursuant to the terms of the Risk Services Agreements for Blocks 9 and 21 and the Production Sharing Agreement for Block 20, the Company is not required to pay annual rental payments to maintain the licenses from year to year.

        The Company recorded $12.1 million, $7.7 million and $6.9 million of office and delay rental expense for years ended December 31, 2012, 2011 and 2010, respectively, and a cumulative of $42.4 million for the period November 10, 2005 (Inception) through December 31, 2012.

19. Segment Information

        As described in Note 1, "Organization and Operations", the Company currently has two geographic operating segments for its exploratory operations. The operating segments are focused in the deepwater

F-34

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

Notes to Consolidated Financial Statements (Continued)

19. Segment Information (Continued)

U.S. Gulf of Mexico and offshore West Africa. The following tables provide the geographic operating segment information for each of the three years in the period ended December 31, 2012:

	U.S. Gulf of Mexico			West Africa			Total
	($ in thousands)
Year ended December 31, 2012
Operating costs and expense	$	231,196		$	53,632		$	284,828
Interest (income) expense		(1,824	)		(5	)		(1,829	)
Net income (loss)	$	(229,372	)	$	(53,627	)	$	(282,999	)
Additions to Property and Equipment, net(1)	$	67,068		$	169,362		$	236,430
Year ended December 31, 2011
Operating costs and expense	$	80,425		$	57,411		$	137,836
Interest (income) expense		(4,194	)		(5	)		(4,199	)
Net income (loss)	$	(76,231	)	$	(57,406	)	$	(133,637	)
Additions to Property and Equipment, net(1)	$	(12,324	)	$	411,882		$	399,558
Year ended December 31, 2010
Operating costs and expense	$	94,619		$	43,439		$	138,058
Interest (income) expense		(1,582	)		—			(1,582	)
Net income (loss)	$	(93,037	)	$	(43,439	)	$	(136,476	)
Additions to Property and Equipment, net(1)	$	(7,844	)	$	—		$	(7,844	)

(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.

20. 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.

F-35

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

Notes to Consolidated Financial Statements (Continued)

21. Selected Quarterly Financial Data—Unaudited

        Unaudited quarterly financial data for the years ended December 31, 2012 and 2011 are as follows:

	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
	($ in thousands)
Year ended December 31, 2012
Operating costs and expenses	$	37,715		$	142,155		$	40,553		$	64,405
Operating income (loss)		(37,715	)		(142,155	)		(40,553	)		(64,405	)
Net income (loss)		(36,531	)		(140,723	)		(39,214	)		(66,531	)
Basic and diluted income (loss) per common share(1)	$	(0.09	)	$	(0.35	)	$	(0.10	)	$	(0.16	)
Year ended December 31, 2011
Operating costs and expenses	$	16,755		$	20,536		$	48,242		$	52,303
Operating income (loss)		(16,755	)		(20,536	)		(48,242	)		(52,303	)
Net income (loss)		(16,058	)		(19,478	)		(46,987	)		(51,114	)
Basic and diluted income (loss) per common share(1)	$	(0.05	)	$	(0.05	)	$	(0.12	)	$	(0.13	)

(1)

Totals may not add due to rounding.

22. Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

        The supplementary oil and gas data that follows is presented in accordance with supplemental disclosure requirements under ASC No. 932, "Extractive Activities—Oil and Gas" and includes (1) capitalized costs, costs incurred and results of operations related to oil and gas producing activities, (2) net proved oil and gas reserves producing activities, (3) net proved oil and gas reserves, and (4) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Since the Company did not have any proved reserves as of December 31, 2012 and 2011, there will be no disclosures on (2), (3) and (4) above.

F-36

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

Notes to Consolidated Financial Statements (Continued)

22. Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Continued)

Capitalized Costs Related to Oil and Gas Activities

	U.S. Gulf of Mexico			West Africa		Total
	($ in thousands)
As of December 31, 2012
Unproved properties(1)	$	572,257		$	600,620	$	1,172,877
Accumulated valuation allowance		(78,413	)		—		(78,413	)
		493,844			600,620		1,094,464
Proved properties		—			—		—
Net capitalized costs	$	493,844		$	600,620	$	1,094,464
As of December 31, 2011
Unproved properties	$	447,919		$	432,311	$	880,230
Accumulated valuation allowance		(18,275	)		—		(18,275	)
		429,644			432,311		861,955
Proved properties		—			—		—
Net capitalized costs	$	429,644		$	432,311	$	861,955

(1)

Unproved properties includes capitalized costs net of sale/like-kind exchange of leasehold interests transactions that occurred in 2012 of approximately $0.8 million for U.S. Gulf of Mexico. No gain or loss was recognized for these transactions for the year ended December 31, 2012.

F-37

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

Notes to Consolidated Financial Statements (Continued)

22. Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Continued)

Costs Incurred in Oil and Gas Activities

        The following table reflects total costs incurred, both capitalized and expensed, for oil and gas property acquisition, exploration and development activities.

	U.S. Gulf of Mexico		West Africa		Total
	($ in thousands)
Year ended December 31, 2012
Property acquisition
Unproved	$	19,961	$	—	$	19,961
Proved		—		—		—
Exploration
Capitalized		104,376		168,309		272,685
Expensed		32,874		28,709		61,583
Development		—		—		—
Total Costs Incurred	$	157,211	$	197,018	$	354,229
Year ended December 31, 2011
Property acquisition
Unproved	$	—	$	337,126	$	337,126
Proved		—		—		—
Exploration
Capitalized		11,213		96,849		108,062
Expensed		10,707		21,532		32,239
Development		—		—		—
Total Costs Incurred	$	21,920	$	455,507	$	477,427
Year ended December 31, 2010
Property acquisition
Unproved	$	1,746	$	—	$	1,746
Proved		—		—		—
Exploration
Capitalized		34,596		—		34,596
Expensed		15,984		29,046		45,030
Development		—		—		—
Total Costs Incurred	$	52,326	$	29,046	$	81,372

F-38

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

Notes to Consolidated Financial Statements (Continued)

22. Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Continued)

        The following table reflects the total acreage of the Company's existing oil and gas properties:

	Thousands of Acres
	Developed				Undeveloped
	Gross		Net		Gross		Net
Acreage at December 31, 2012
U.S. Gulf of Mexico		—		—		1,409		696
West Africa		—		—		5,653		1,841
Total		—		—		7,062		2,537
Acreage at December 31, 2011
U.S. Gulf of Mexico		—		—		1,323		644
West Africa		—		—		5,653		1,841
Total		—		—		6,976		2,485

F-39

Exhibit Index

Exhibit Number			Description of Document
	3.1		Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579))
	3.2		By-laws of the Company (incorporated by reference to Exhibit 3 to the Company's Registration Statement on Form 8-A filed December 11, 2009 (File No. 001-34579))
	4.1		Specimen stock certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	4.2		Base Indenture, dated as of December 17, 2012 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed December 17, 2012 (File No. 001-34579))
	4.3		First Supplemental Indenture, dated as of December 17, 2012 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed December 17, 2012 (File No. 001-34579))
	4.4		Form of 2.625% Convertible Senior Note due 2019 (incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed December 17, 2012 (File No. 001-34579))
	10.1	†	Employment Agreement, dated November 12, 2009, among the Company, the Partnership and Joseph H. Bryant (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.2	†	Employment Agreement, dated October 23, 2009, among the Company, the Partnership and James H. Painter (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.3	†	Employment Agreement, dated October 23, 2009, among the Company, the Partnership and James W. Farnsworth (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.4	†	Severance Agreement, dated October 23, 2009, among the Company, the Partnership and John P. Wilkirson (incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.5		Risk Services Agreement relating to Block 9, between CIE Angola Block 9 Ltd., Sonangol, Sonangol Pesquisa e Produção, S.A., Nazaki Oil and Gás and Alper Oil, Lda (incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579))
	10.6		Risk Services Agreement relating to Block 21, between CIE Angola Block 21 Ltd., Sonangol, Sonangol Pesquisa e Produção, S.A., Nazaki Oil and Gás and Alper Oil, Lda (incorporated by reference to Exhibit 10.8 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579))
	10.7		Exploration and Production Sharing Contract, dated December 13, 2006, between the Republic of Gabon and Total Gabon, S.A. (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.8		Assignment Agreement, dated November 29, 2007, between CIE Gabon Diaba Ltd. and Total Gabon, S.A. (incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))

Exhibit Number			Description of Document
	10.9		Simultaneous Exchange Agreement, dated April 6, 2009, between the Partnership and TOTAL E&P USA, INC. (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-1/A filed October 9, 2009 (File No. 333-161734))
	10.10		Gulf of Mexico Program Management and AMI Agreement, dated April 6, 2009, between the Partnership and TOTAL E&P USA, INC. (incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1/A filed October 9, 2009 (File No. 333-161734))
	10.11		Offshore Daywork Drilling Contract, dated May 3, 2008, between the Partnership and Ensco Offshore Company (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.12	†	Form of Restricted Stock Award Agreements relating to the Class B interests (incorporated by reference to Exhibit 10.10 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.13	†	Form of Restricted Stock Award Agreements relating to the Class C interests (incorporated by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.14	†	Form of Restricted Stock Award Agreements relating to the Class D interests (incorporated by reference to Exhibit 10.12 to the Company's Registration Statement on Form S-1/A filed October 29, 2009 (File No. 333-161734))
	10.15	†*	Amended and Restated Long Term Incentive Plan of the Company
	10.16	†	Annual Incentive Plan of the Company (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579))
	10.17	†	Non-Employee Directors Compensation Plan (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K filed January 29, 2010 (File No. 001-34579))
	10.18	†	Non-Employee Directors Deferral Plan (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K filed January 29, 2010 (File No. 001-34579))
	10.19	†	Form of Restricted Stock Unit Award Notification under the Non-Employee Directors Compensation Plan (incorporated by reference to Exhibit 99.4 to the Company's Current Report on Form 8-K filed January 29, 2010 (Filed No. 001-34579))
	10.20		Production Sharing Contract, dated December 20, 2011, between CIE Angola Block 20 Ltd., Sociedade Nacional de Combustíveis de Angola—Empresa Pública, Sonangol Pesquisa e Produção, S.A., BP Exploration Angola (Kwanza Benguela) Limited, and China Sonangol International Holding Limited (incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K filed February 21, 2012 (File No. 001-34579))
	10.21		Form of Director Indemnification Agreements (incorporated by reference to Exhibit 10.19 to the Company's Registration Statement on Form S-1/A filed November 27, 2009 (File No. 333-161734))
	10.22	†	Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K filed March 1, 2011 (File No. 001-34579)).
	10.23	†	Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.27 to the Company's Annual Report on Form 10-K filed March 1, 2011 (File No. 001-34579)).

Exhibit Number			Description of Document
	10.24	†	Separation Agreement between Rodney L. Gray and the Company, dated June 16, 2010, (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed June 21, 2010 (File No. 001-34579)).
	10.25		International Daywork Drilling Contract—Offshore, dated November 8, 2010 between CIE Angola Block 21 Ltd. and Z North Sea Ltd. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed November 12, 2010 (File No. 001-34579)).
	10.26		Special Standby Rate and Potential Suspension Agreement dated November 9, 2010 between Cobalt International Energy, L.P. and Ensco Offshore Company (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q filed November 12, 2010 (File No. 001-34579)).
	10.27	†	Form of Amendment to Employment Agreements with Joseph H. Bryant, James H. Painter and James W. Farnsworth and Severance Agreements with Samuel H. Gillespie and John P. Wilkirson (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q filed November 12, 2010 (File No. 001-34579)).
	10.28	†	Employment Agreement, dated September 6, 2011, between the Company and Van P. Whitfield (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed September 8, 2011 (File No. 001-34579))
	10.29		Severance Agreement, dated April 1, 2010, between the Company and Michael D. Drennon (incorporated by reference to Exhibit 10.30 to the Company's Annual Report on Form 10-K filed February 21, 2012 (File No. 001-34579))
	10.30		Registration Rights Agreement, dated December 15, 2009, among the Company and the parties that are signatory thereto (incorporated by reference to Exhibit 10.31 to the Company's Annual Report on Form 10-K filed February 21, 2012 (File No. 001-34579))
	10.31		Offshore Drilling Contract between CIE Angola Block 21 Ltd. and Universal Energy Resources, Inc., dated July 30, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q filed October 30, 2012 (File No. 001-34579))
	10.32		Underwriting Agreement dated as of February 23, 2012 (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed February 24, 2012 (File No. 001-34579))
	10.33		Underwriting Agreement dated as of December 11, 2012 (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed December 17, 2012 (File No. 001-34579))
	10.34		Underwriting Agreement dated as of January 15, 2013 (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K filed January 18, 2013 (File No. 001-34579))
	10.35	*	Deferred Compensation Plan of the Company
	10.36	*	Amended and Restated Stockholders Agreement, dated February 21, 2013, among the Company and the stockholders that are signatory thereto
	21.1	*	List of Subsidiaries
	23.1	*	Consent of Ernst & Young LLP
	31.1	*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

Exhibit Number			Description of Document
	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.

†

Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b).

EX-10.15

Exhibit 10.15

COBALT INTERNATIONAL ENERGY, INC.
LONG TERM INCENTIVE PLAN
(Amended and Restated as of February 21, 2013)

Section 1.    Purpose.    The purpose of the Cobalt International Energy, Inc. Long Term Incentive Plan (as amended from time to time, the “Plan”) is to motivate and reward those employees and other individuals who are expected to contribute significantly to the success of Cobalt International Energy, Inc. (together with its subsidiaries, the “Company”) and its Affiliates to perform at the highest level and to further the best interests of the Company and its shareholders.

Section 2.      Definitions.    As used in the Plan, the following terms shall have the meanings set forth below:

(a)   “Act” means Securities Exchange Act of 1934.

(b)   “Affiliate” means (i) any entity that, directly or indirectly, is controlled by the Company and (ii) any entity in which the Company has a significant equity interest, in each case as determined by the Committee.

(c)   “Award” means any Option, SAR, Restricted Stock, RSU, Performance Award or Other Stock-Based Award granted under the Plan.

(d)   “Award Document” means any agreement, contract or other instrument or document evidencing any Award granted under the Plan, which may, but need not, be executed or acknowledged by a Participant.

(e)   “Beneficiary” means a person entitled to receive payments or other benefits or exercise rights that are available under the Plan in the event of the Participant’s death. If no such person is named by a Participant, or if no Beneficiary designated by the Participant is eligible to receive payments or other benefits or exercise rights that are available under the Plan at the Participant’s death, such Participant’s Beneficiary shall be such Participant’s estate.

(f)    “Board” means the board of directors of the Company.

(g)   “Cause” means, with respect to any Participant, “cause” as defined such Participant’s Employment Agreement, if any, or if not so defined, except as otherwise provided in such Participant’s Award Document, such Participant’s:

(i)  having engaged in material mismanagement in providing services to the Company or its Affiliates;

(ii)  having engaged in conduct that he or she knew would be materially injurious to the Company or its Affiliates;

(iii)  material breach of any applicable Employment Agreement or Lock Up Agreement;

(iv)  having been convicted of, or having entered a plea bargain or settlement admitting guilt for, any felony under the laws of the United States, any state or the District of Columbia where such felony involves moral turpitude or where, as a result of such felony, the continued employment of the Participant would have, or could reasonably be expected to have, a material adverse impact on the reputation of the Company or any of its Affiliates; or

(v)  having been the subject of any order, judicial or administrative, obtained or issued by the Securities and Exchange Commission for any securities violation involving fraud including, for example, any such order consented to by the Participant in which findings of facts or any legal conclusions establishing liability are neither admitted nor denied.

The occurrence of any such event that is susceptible to cure or remedy shall not constitute Cause if such Participant cures or remedies such event within 30 days after the Company provides notice to such Participant.

(h)   “Change in Control” means the occurrence of any one or more of the following events:

(i)  any “person” (as defined in Section 13(d) of the Act), other than (A) an employee benefit plan or trust maintained by the Company or (B) any of the Sponsors (as defined in the Amended and Restated Certificate of Incorporation of the Company as in effect immediately following the closing of the initial public offering of Shares) or their respective affiliates, becomes the “beneficial owner” (as defined in Rule 13d-3 under the Act), directly or indirectly, of securities of the Company representing more than 50% of the combined voting power of the Company’s outstanding securities entitled to vote generally in the election of directors;

(ii)  at any time during a period of 12 consecutive months, individuals who at the beginning of such period constituted the Board and any new member of the Board whose election or nomination for election was approved by a vote of at least a majority of the directors then still in office who either were directors at the beginning of such period or whose election or nomination for election was so approved, cease for any reason to constitute a majority of members of the Board; or

(iii)  the consummation of (A) a merger or consolidation of the Company or any of its subsidiaries with any other corporation or entity, other than a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving entity or, if applicable, the ultimate parent thereof) at least 50% of the combined voting power and total fair market value of the securities of the Company or such surviving entity or parent outstanding immediately after such merger or consolidation, or (B) any sale, lease, exchange or other transfer to any Person (other than an Affiliate of the Company) of assets of the Company and/or any of its subsidiaries, in one transaction or a series of related transactions, having an aggregate fair market value of more than 50% of the fair market value of the Company and its subsidiaries (the “Company Value”) immediately prior to such transaction(s), but only to the extent that, in connection with such transaction(s) or within a reasonable period thereafter, the Company’s stockholders receive distributions of cash and/or assets having a fair market value that is greater than 50% of the Company Value immediately prior to such transaction(s).

Notwithstanding the foregoing, in no event shall a Change in Control be deemed to have occurred with respect to a Participant if the Participant is part of a “group” within the meaning of Section 13(d)(3) of the Act that consummates the Change in Control transaction. In addition, for purposes of the definition of Change in Control, a person engaged in business as an underwriter of securities shall not be deemed to be the beneficial owner of, or to beneficially own, any securities acquired through such person’s participation in good faith in a firm commitment underwriting until the expiration of 40 days after the date of such acquisition.

(i)    “Code” means the Internal Revenue Code of 1986, as amended from time to time, and the rules, regulations and guidance thereunder. Any reference to a provision in the Code shall include any successor provision thereto.

(j)    “Committee” means the Compensation Committee of the Board or such other committee as may be designated by the Board. If the Board does not designate the Committee, references herein to the “Committee” shall refer to the Board.

(k)   “Covered Employee” means an individual who is (i) either a “covered employee” or expected by the Committee to be a “covered employee,” in each case within the meaning of Section 162(m)(3) of the Code or (ii) expected by the Committee to be the recipient of compensation (other than Section 162(m) Compensation) in excess of $1,000,000 for the tax year of the Company with regard to which a deduction in respect of such individual’s Award would be claimed.

(l)    “Disability” means, with respect to any Participant, “disability” as defined in such Participant’s Employment Agreement, if any, or if not so defined, except as otherwise provided in such Participant’s Award Document:

(i)  a permanent and total disability that entitles the Participant to disability income payments under any long-term disability plan or policy provided by the Company under which the Participant is covered, as such plan or policy is then in effect; or

(ii)  if such Participant is not covered under a long-term disability plan or policy provided by the Company at such time for whatever reason, then the term “Disability” means a “permanent and total disability” as defined in Section 22(e)(3) of the Code and, in this case, the existence of any such Disability will be certified by a physician acceptable to the Company.

(m)  “Effective Date” means October 22, 2009.

(n)   “Employment Agreement” means any employment, severance, consulting or similar agreement between the Company or any of its Affiliates and a Participant.

(o)   “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, and the rules, regulations and guidance thereunder. Any reference to a provision in the Exchange Act shall include any successor provision thereto.

(p)   “Fair Market Value” means with respect to Shares, the closing price of a Share on the date in question (or, if there is no reported sale on such date, on the last preceding date on which any reported sale occurred) on the principal stock market or exchange on which the Shares are quoted or traded, or if Shares are not so quoted or traded, fair market value as determined by the Committee, and with respect to any property other than Shares, the fair market value of such property determined by such methods or procedures as shall be established from time to time by the Committee.

(q)   “Good Reason” means, with respect to any Participant, “good reason” as defined in such Participant’s Employment Agreement, if any, or if not so defined, except as otherwise provided in such Participant’s Award Document, the occurrence of any one or both of the following events:

(i)  a material reduction by the Company or any of its Affiliates of such Participant’s base salary; or

(ii)  relocation by the Company or any of its Affiliates of the geographic location of such Participant’s principal place of employment by more than 75 miles from Houston, Texas.

In each case, if such Participant desires to terminate his or her employment or engagement with the Company or such Affiliate for Good Reason, he or she must first give written notice of the facts and circumstances providing the basis for Good Reason to the Company or such Affiliate and allow the Company or such Affiliate 60 days from the date of such notice to remedy, cure or rectify the situation giving rise to Good Reason, and in the absence of any such remedy, cure or rectification, such Participant must terminate his or her employment or engagement for such Good Reason within 120 days after delivery of such written notice.

(r)   “Incentive Stock Option” means an option representing the right to purchase Shares from the Company, granted pursuant to Section 6, that meets the requirements of Section 422 of the Code.

(s)   “Intrinsic Value” with respect to an Option or SAR Award means (i) the price or implied price per Share in a Change in Control or other event over (ii) the exercise or hurdle price of such Award multiplied by (iii) the number of Shares covered by such Award.

(t)    “Lock Up Agreement” means any agreement between the Company or any of its Affiliates and a Participant that provides for restrictions on the transfer of Shares held by such Participant.

(u)   “Non-Qualified Stock Option” means an option representing the right to purchase Shares from the Company, granted pursuant to Section 6, that is not an Incentive Stock Option.

(v)   “Option” means an Incentive Stock Option or a Non-Qualified Stock Option.

(w)  “Other Stock-Based Award” means an Award granted pursuant to Section 10.

(x)   “Participant” means the recipient of an Award granted under the Plan.

(y)   “Performance Award” means an Award granted pursuant to Section 9.

(z)   “Performance Period” means the period established by the Committee at the time any Performance Award is granted or at any time thereafter during which any performance goals specified by the Committee with respect to such Award are measured.

(aa) “Replacement Award” means an Award granted in assumption of, or in substitution for, an outstanding award previously granted by a company acquired by the Company or with which the Company combines.

(bb) “Restricted Stock” means any Share granted pursuant to Section 8.

(cc)  “RSU” means a contractual right granted pursuant to Section 8 that is denominated in Shares. Each RSU represents a right to receive the value of one Share (or a percentage of such value) in cash, Shares or a combination thereof. Awards of RSUs may include the right to receive dividend equivalents.

(dd) “SAR” means any right granted pursuant to Section 7 to receive upon exercise by a Participant or settlement, in cash, Shares or a combination thereof, the excess of (i) the Fair Market Value of one Share on the date of exercise or settlement over (ii) the exercise or hurdle price of the right on the date of grant, or if granted in connection with an Option, on the date of grant of the Option.

(ee) “Section 162(m) Compensation” means “qualified performance-based compensation” under Section 162(m) of the Code.

(ff)  “Shares” means shares of the Company’s common stock.

(gg) “Termination of Service” means, in the case of a Participant who is an employee of the Company or an Affiliate, cessation of the employment relationship such that the Participant is no longer an employee of the Company or Affiliate, or, in the case of a Participant who is an independent contractor, the date the performance of services for the Company or an Affiliate has ended; provided, however, that in the case of an employee, the transfer of employment from the Company to an Affiliate, from an Affiliate to the Company, from one Affiliate to another Affiliate or, unless the Committee determines otherwise, the cessation of employee status but the continuation of the performance of services for the Company or an Affiliate as a director of the Board or an independent contractor shall not be deemed a cessation of service that would constitute a Termination of Service; provided, further, that a Termination of Service will be deemed to occur for a Participant employed by an Affiliate when an Affiliate ceases to be an Affiliate unless such Participant’s employment continues with the Company or another Affiliate.

Section 3.    Eligibility.

(a)   Any employee, consultant or other advisor of, or any other individual who provides services to, the Company or any Affiliate, other than any non-employee director of the Company or any Affiliate, shall be eligible to be selected to receive an Award under the Plan.

(b)   Holders of options and other types of awards granted by a company acquired by the Company or with which the Company combines are eligible for grants of Replacement Awards under the Plan.

Section 4.    Administration.

(a)    Administration of the Plan.    The Plan shall be administered by the Committee. All decisions of the Committee shall be final, conclusive and binding upon all parties, including the Company, its shareholders and Participants and any Beneficiaries thereof. The Committee may issue rules and regulations for administration of the Plan. It shall meet at such times and places as it may determine.

(b)    Composition of Committee.    To the extent necessary or desirable to comply with applicable regulatory regimes, any action by the Committee shall require the approval of Committee members who are (i) independent, within the meaning of and to the extent required by applicable rulings and interpretations of the applicable stock market or exchange on which the Shares are quoted or traded; (ii) a non-employee director within the meaning of Rule 16b-3 under the Exchange Act; and (iii) an outside director pursuant to Section 162(m) of the Code. The Board may designate one or more members of the Board as alternate members of the Committee who may replace any absent or disqualified member at any meeting of the Committee. To the extent permitted by applicable law, the Committee may delegate to one or more officers of the Company the authority to grant Awards, except that such delegation shall not be applicable to any Award for a person then covered by Section 16 of the Exchange Act.

(c)    Authority of Committee.    Subject to the terms of the Plan and applicable law, the Committee (or its delegate) shall have full power and authority to: (i) designate Participants; (ii) determine the type or types of Awards (including Replacement Awards) to be granted to each Participant under the Plan; (iii) determine the number of Shares to be covered by (or with respect to which payments, rights or other matters are to be calculated in connection with) Awards; (iv) determine the terms and conditions of any Award; (v) determine whether, to what extent and under what circumstances Awards may be settled or exercised in cash, Shares, other Awards, other property, net settlement, or any combination thereof, or canceled, forfeited or suspended, and the method or methods by which Awards may be settled, exercised, canceled, forfeited or suspended; (vi) determine whether, to what extent and under what circumstances cash, Shares, other Awards, other property and other amounts payable with respect to an Award under the Plan shall be deferred either automatically or at the election of the holder thereof or of the Committee; (vii) interpret and administer the Plan and any instrument or agreement relating to, or Award made under, the Plan; (viii) establish, amend, suspend or waive such rules and regulations and appoint such agents, trustees, brokers, depositories and advisors and determine such terms of their engagement as it shall deem appropriate for the proper administration of the Plan and due compliance with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations; and (ix) make any other determination and take any other action that the Committee deems necessary or desirable for the administration of the Plan and due compliance with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations.

(d)    Dodd-Frank Clawback.    The Committee shall have full authority to implement any policies and procedures necessary or desirable to comply with Section 10D of the Exchange Act

and any rules promulgated thereunder. Without limiting the foregoing, the Committee may provide in any Award Document that, in event of a financial restatement that reduces the amount of previously awarded incentive compensation that would not have been earned had results been properly reported, outstanding Awards will be cancelled and the Company may clawback (i.e., recapture) realized Option/SAR gains and realized value for vested Restricted Stock or RSUs or earned Performance Awards within 12 months preceding the financial restatement.

(e)    Restrictive Covenants.    The Committee may impose restrictions on any Award with respect to non-competition, confidentiality and other restrictive covenants as it deems necessary or appropriate in its sole discretion.

Section 5.    Shares Available for Awards.

(a)   Subject to adjustment as provided in Section 5(c) and except for Replacement Awards, (i) the maximum number of Shares available for issuance under the Plan shall not exceed 10,741,862 Shares and (ii) no Participant may receive under the Plan in any calendar year (A) Options and SARs that relate to more than 5,370,931 Shares; (B) Restricted Stock and RSUs that relate to more than 5,370,931 Shares or (C) Performance Awards and Other Stock-Based Awards that relate to more than 5,370,931 Shares.

(b)   Any Shares subject to an Award (other than a Replacement Award or IPO Award), that expires, is canceled, forfeited or otherwise terminates without the delivery of such Shares, including (i) the number of Shares surrendered or withheld in payment of any grant, purchase, exercise or hurdle price of an Award or taxes related to an Award and (ii) any Shares subject to an Award to the extent that Award is settled without the issuance of Shares, shall again be, or shall become, available for issuance under the Plan.

(c)   In the event that the Committee determines that, as a result of any dividend or other distribution (whether in the form of cash, Shares or other securities), recapitalization, stock split, reverse stock split, reorganization, merger, consolidation, split-up, spin-off, combination, repurchase or exchange of Shares or other securities of the Company, issuance of warrants or other rights to purchase Shares or other securities of the Company, issuance of Shares pursuant to the anti-dilution provisions of securities of the Company, or other similar corporate transaction or event affecting the Shares, or of changes in applicable laws, regulations or accounting principles, an adjustment is appropriate in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan, then the Committee shall adjust equitably any or all of:

(i)  the number and type of Shares (or other securities) which thereafter may be made the subject of Awards, including the aggregate and individual limits specified in Section 5(a);

(ii)  the number and type of Shares (or other securities) subject to outstanding Awards; and

(iii)  the grant, purchase, exercise or hurdle price with respect to any Award or, if deemed appropriate, make provision for a cash payment to the holder of an outstanding Award;

provided, however, that the number of Shares subject to any Award denominated in Shares shall always be a whole number.

(d)   Any Shares delivered pursuant to an Award may consist, in whole or in part, of authorized and unissued Shares or Shares acquired by the Company.

Section 6.    Options.    The Committee is authorized to grant Options to Participants with the following terms and conditions and with such additional terms and conditions, in either case not inconsistent with the provisions of the Plan, as the Committee shall determine.

(a)   The exercise price per Share under an Option shall be determined by the Committee; provided, however, that, except in the case of Replacement Awards, such exercise price shall not be less than the Fair Market Value of a Share on the date of grant of such Option.

(b)   The term of each Option shall be fixed by the Committee but shall not exceed 10 years from the date of grant of such Option.

(c)   The Committee shall determine the time or times at which an Option may be exercised in whole or in part.

(d)   The Committee shall determine the method or methods by which, and the form or forms, including cash, Shares, other Awards, other property, net settlement, broker assisted cashless exercise or any combination thereof, having a Fair Market Value on the exercise date equal to the relevant exercise price, in which payment of the exercise price with respect thereto may be made or deemed to have been made.

(e)   The terms of any Incentive Stock Option granted under the Plan shall comply in all respects with the provisions of Section 422 of the Code.

Section 7.    Stock Appreciation Rights.    The Committee is authorized to grant SARs to Participants with the following terms and conditions and with such additional terms and conditions, in either case not inconsistent with the provisions of the Plan, as the Committee shall determine.

(a)   SARs may be granted under the Plan to Participants either alone (“freestanding”) or in addition to other Awards granted under the Plan (“tandem”) and may, but need not, relate to a specific Option granted under Section 6.

(b)   The exercise or hurdle price per Share under a SAR shall be determined by the Committee; provided, however, that, except in the case of Replacement Awards, such exercise or hurdle price shall not be less than the Fair Market Value of a Share on the date of grant of such SAR.

(c)   The term of each SAR shall be fixed by the Committee but shall not exceed 10 years from the date of grant of such SAR.

(d)   The Committee shall determine the time or times at which a SAR may be exercised or settled in whole or in part.

Section 8.    Restricted Stock and RSUs.    The Committee is authorized to grant Awards of Restricted Stock and RSUs to Participants with the following terms and conditions and with such additional terms and conditions, in either case not inconsistent with the provisions of the Plan, as the Committee shall determine.

(a)   Shares of Restricted Stock and RSUs shall be subject to such restrictions as the Committee may impose (including any limitation on the right to vote a Share of Restricted Stock or the right to receive any dividend, dividend equivalent or other right), which restrictions may lapse separately or in combination at such time or times, in such installments or otherwise, as the Committee may deem appropriate.

(b)   Any share of Restricted Stock granted under the Plan may be evidenced in such manner as the Committee may deem appropriate, including book-entry registration or issuance of a stock certificate or certificates. In the event any stock certificate is issued in respect of shares of Restricted Stock granted under the Plan, such certificate shall be registered in the name of the

Participant and shall bear an appropriate legend referring to the terms, conditions and restrictions applicable to such Restricted Stock.

(c)   If the Committee intends that an Award granted under this Section 8 shall constitute or give rise to Section 162(m) Compensation, such Award shall be structured in accordance with the requirements of Section 9, including the performance criteria and the Award limitation set forth therein, and any such Award shall be considered a Performance Award for purposes of the Plan.

(d)   The Committee may provide in an Award Document that an Award of Restricted Stock is conditioned upon the Participant making or refraining from making an election with respect to the Award under Section 83(b) of the Code. If a Participant makes an election pursuant to Section 83(b) of the Code with respect to an Award of Restricted Stock, the Participant shall be required to file promptly a copy of such election with the Company.

Section 9.    Performance Awards.    The Committee is authorized to grant Performance Awards to Participants with the following terms and conditions and with such additional terms and conditions, in either case not inconsistent with the provisions of the Plan, as the Committee shall determine:

(a)   Performance Awards may be denominated as a cash amount, number of Shares or units or a combination thereof and are Awards which may be earned upon achievement or satisfaction of performance conditions specified by the Committee. In addition, the Committee may specify that any other Award shall constitute a Performance Award by conditioning the grant to a Participant or the right of a Participant to exercise the Award or have it settled, and the timing thereof, upon achievement or satisfaction of such performance conditions as may be specified by the Committee. The Committee may use such business criteria and other measures of performance as it may deem appropriate in establishing any performance conditions. Subject to the terms of the Plan, the performance goals to be achieved during any Performance Period, the length of any Performance Period, the amount of any Performance Award granted and the amount of any payment or transfer to be made pursuant to any Performance Award shall be determined by the Committee.

(b)   Every Performance Award shall include, if the Committee intends that such Award should constitute Section 162(m) Compensation, a pre-established formula, such that payment, retention or vesting of the Award is subject to the achievement during a Performance Period or Performance Periods, as determined by the Committee, of a level or levels of, or increases in, in each case as determined by the Committee, one or more of the following performance measures with respect to the Company: captured prospects, licenses or leases acquired, contracts executed, operated prospects matured to drill ready, drilling programs commenced, wells commenced, successful wells, drillable prospects, exploratory and appraisal drilling performance, capabilities and critical path items established, operating or total budget, cash management, liquidity measurements, capital raised, captured net risked resource potential, acquisition cost efficiency, central lease sale position, acquisitions of oil and gas interests, measurements of proved, probable or possible reserves, measurements of resources, finding and development costs, overhead costs, general and administration expense, market price of a Share, cash flow, reserve value, net asset value, earnings, net income, value or number of asset dispositions, operating income, cash from operations, revenue, margin, EBITDA (earnings before interest, taxes, depreciation and amortization), EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration expense), net capital employed, return on assets, stockholder return, reserve replacement, return on equity, return on capital employed, production, assets, unit volume, sales, market share, safety and environmental performance objectives, accidents, injuries or fatalities, or strategic business criteria consisting of one or more objectives based on meeting specified goals relating to acquisitions or divestitures, each as determined in accordance with generally accepted accounting principles, where applicable, as consistently applied by the Company. Performance criteria may be measured on an absolute (e.g., plan or budget) or relative basis. Relative performance may be measured against a

group of peer companies, a financial market index or other acceptable objective and quantifiable indices. Except in the case of an award intended to qualify as Section 162(m) Compensation, if the Committee determines that a change in the business, operations, corporate structure or capital structure of the Company, or the manner in which the Company conducts its business, or other events or circumstances render the performance objectives unsuitable, the Committee may modify the performance objectives or the related minimum acceptable level of achievement, in whole or in part, as the Committee deems appropriate and equitable. Performance measures may vary from Performance Award to Performance Award, respectively, and from Participant to Participant, and may be established on a stand-alone basis, in tandem or in the alternative. The Committee shall have the power to impose such other restrictions on Awards subject to this Section 9(b) as it may deem necessary or appropriate to ensure that such Awards satisfy all requirements for Section 162(m) Compensation. Notwithstanding any provision of the Plan to the contrary, the Committee shall not be authorized to increase the amount payable under any Award to which this Section 9(b) applies upon attainment of such pre-established formula.

(c)   Settlement of Performance Awards shall be in cash, Shares, other Awards, other property, net settlement, or any combination thereof, in the discretion of the Committee. The Committee shall specify the circumstances in which, and the extent to which, Performance Awards shall be paid or forfeited in the event of a Participant’s Termination of Service.

(d)   Performance Awards will be settled only after the end of the relevant Performance Period. The Committee may, in its discretion, increase or reduce the amount of a settlement otherwise to be made in connection with a Performance Award but may not exercise discretion to increase any amount payable to a Covered Employee in respect of a Performance Award intended to qualify as Section 162(m) Compensation. Any settlement that changes the form of payment from that originally specified shall be implemented in a manner such that the Performance Award and other related Awards do not, solely for that reason, fail to qualify as Section 162(m) Compensation.

(e)   The maximum dollar value that may be earned by any Participant for each 12 months in a Performance Period with respect to Performance Awards that are intended to constitute Section 162(m) Compensation and are denominated in cash is $20 million. If an Award is cancelled, the cancelled Award shall continue to be counted toward the applicable limitation set forth in this Section 9(e).

Section 10.    Other Stock-Based Awards.    The Committee is authorized, subject to limitations under applicable law, to grant to Participants such other Awards that may be denominated or payable in, valued in whole or in part by reference to, or otherwise based on, or related to, Shares or factors that may influence the value of Shares, including convertible or exchangeable debt securities, other rights convertible or exchangeable into Shares, purchase rights for Shares, Awards with value and payment contingent upon performance of the Company or business units thereof or any other factors designated by the Committee. The Committee shall determine the terms and conditions of such Awards. Shares delivered pursuant to an Award in the nature of a purchase right granted under this Section 10 shall be purchased for such consideration, paid for at such times, by such methods and in such forms, including cash, Shares, other Awards, other property, or any combination thereof, as the Committee shall determine. Cash awards, as an element of or supplement to any other Award under the Plan, may also be granted pursuant to this Section 10.

Section 11.    Effect of Termination of Service or a Change in Control on Awards.

(a)   The Committee may provide, by rule or regulation or in any Award Document, or may determine in any individual case, the circumstances in which, and the extent to which, an Award may be exercised, settled, vested, paid or forfeited in the event of a Participant’s Termination of Service prior to the end of a Performance Period or exercise or settlement of such Award.

(b)   The Committee may set forth the treatment of an Award upon a Change in Control in the applicable Award Document.

(c)   In the case of an Option or SAR Award, except as otherwise provided in the applicable Award Document, upon a Change in Control, a merger or consolidation involving the Company or any other event with respect to which the Committee deems it appropriate, the Committee may cause such Award to be canceled in consideration of (i) the full acceleration of such Award and either (A) a period of at least ten days prior to the effective date of such Change in Control to exercise the Award or (B) a payment in cash or other consideration to the Participant who holds such Award in an amount equal to the Intrinsic Value of such Award (which may be equal to but not less than zero), which, if in excess of zero, shall be payable upon the effective date of such Change in Control, merger, consolidation or other event or (ii) a substitute award (which immediately upon grant shall have an Intrinsic Value equal to the Intrinsic Value of such Award or the value otherwise permitted under Section 409A of the Code).

Section 12.    General Provisions Applicable to Awards.

(a)   Awards shall be granted for no cash consideration or for such minimal cash consideration as may be required by applicable law.

(b)   Awards may, in the discretion of the Committee, be granted either alone or in addition to or in tandem with any other Award or any award granted under any other plan of the Company. Awards granted in addition to or in tandem with other Awards, or in addition to or in tandem with awards granted under any other plan of the Company, may be granted either at the same time as or at a different time from the grant of such other Awards or awards.

(c)   Subject to the terms of the Plan, payments or transfers to be made by the Company upon the grant, exercise or settlement of an Award may be made in the form of cash, Shares, other Awards, other property, net settlement, or any combination thereof, as determined by the Committee in its discretion at the time of grant, and may be made in a single payment or transfer, in installments or on a deferred basis, in each case in accordance with rules and procedures established by the Committee. Such rules and procedures may include provisions for the payment or crediting of reasonable interest on installment or deferred payments or the grant or crediting of dividend equivalents in respect of installment or deferred payments.

(d)   Except as may be permitted by the Committee (except with respect to Incentive Stock Options) or as specifically provided in an Award Document, (i) no Award and no right under any Award shall be assignable, alienable, saleable or transferable by a Participant otherwise than by will or pursuant to Section 12(e) and (ii) during a Participant’s lifetime, each Award, and each right under any Award, shall be exercisable only by the Participant or, if permissible under applicable law, by the Participant’s guardian or legal representative. The provisions of this Section 12(d) shall not apply to any Award that has been fully exercised or settled, as the case may be, and shall not preclude forfeiture of an Award in accordance with the terms thereof.

(e)   A Participant may designate a Beneficiary or change a previous Beneficiary designation at such times prescribed by the Committee by using forms and following procedures approved or accepted by the Committee for that purpose.

(f)    All certificates for Shares and/or other securities delivered under the Plan pursuant to any Award or the exercise thereof shall be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the Plan or the rules, regulations and other requirements of the Securities and Exchange Commission, any stock market or exchange upon which such Shares or other securities are then quoted, traded or listed, and any applicable securities laws, and the Committee may cause a legend or legends to be put on any such certificates to make appropriate reference to such restrictions.

(g)   The Committee may impose restrictions on any Award with respect to non-competition, confidentiality and other restrictive covenants as it deems necessary or appropriate in its sole discretion.

Section 13.    Amendments and Termination.

(a)    Amendment or Termination of Plan.    Except to the extent prohibited by applicable law and unless otherwise expressly provided in an Award Document or in the Plan, the Board may amend, alter, suspend, discontinue or terminate the Plan or any portion thereof at any time; provided, however, that no such amendment, alteration, suspension, discontinuation or termination shall be made without (i) shareholder approval if such approval is required by applicable law or the rules of the stock market or exchange, if any, on which the Shares are principally quoted or traded or (ii) the consent of the affected Participant, if such action would materially adversely affect the rights of such Participant under any outstanding Award, except (x) to the extent any such amendment, alteration, suspension, discontinuance or termination is made to cause the Plan to comply with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations or (y) to impose any “clawback” or recoupment provisions on any Awards in accordance with Section 4(d) of the Plan. Notwithstanding anything to the contrary in the Plan, the Committee may amend the Plan, or create sub-plans, in such manner as may be necessary to enable the Plan to achieve its stated purposes in any jurisdiction in a tax-efficient manner and in compliance with local rules and regulations. The Committee may correct any defect, supply any omission or reconcile any inconsistency in the Plan or any Award in the manner and to the extent it shall deem desirable to carry the Plan into effect.

(b)    Terms of Awards.    The Committee may waive any conditions or rights under, amend any terms of, or amend, alter, suspend, discontinue or terminate any Award theretofore granted, prospectively or retroactively, without the consent of any relevant Participant or holder or Beneficiary of an Award; provided, however, that no such action shall materially adversely affect the rights of any affected Participant or holder or Beneficiary under any Award theretofore granted under the Plan, except (x) to the extent any such action is made to cause the Plan to comply with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations, or (y) to impose any “clawback” or recoupment provisions on any Awards in accordance with Section 4(d) of the Plan; and provided further, that the Committee’s authority under this Section 13(b) is limited in the case of Awards subject to Section 9(b), as provided in Section 9(b).

(c)    No Repricing.    Notwithstanding the foregoing, except as provided in Section 5(c), no action shall directly or indirectly, through cancellation and regrant or any other method, reduce, or have the effect of reducing, the exercise price of any Award established at the time of grant thereof without approval of the Company’s shareholders.

Section 14.    Miscellaneous.

(a)   No employee, Participant or other person shall have any claim to be granted any Award under the Plan, and there is no obligation for uniformity of treatment of employees, Participants or holders or Beneficiaries of Awards under the Plan. The terms and conditions of Awards need not be the same with respect to each recipient. Any Award granted under the Plan shall be a one-time Award that does not constitute a promise of future grants. The Company, in its sole discretion, maintains the right to make available future grants under the Plan.

(b)   The grant of an Award shall not be construed as giving a Participant the right to be retained in the employ of, or to continue to provide services to, the Company or any Affiliate. Further, the Company or the applicable Affiliate may at any time dismiss a Participant, free from any liability, or any claim under the Plan, unless otherwise expressly provided in the Plan or in any

Award Document or in any other agreement binding the parties. The receipt of any Award under the Plan is not intended to confer any rights on the receiving Participant except as set forth in the applicable Award Document.

(c)   Nothing contained in the Plan shall prevent the Company from adopting or continuing in effect other or additional compensation arrangements, and such arrangements may be either generally applicable or applicable only in specific cases.

(d)   The Company shall be authorized to withhold from any Award granted or any payment due or transfer made under any Award or under the Plan or from any compensation or other amount owing to a Participant the amount (in cash, Shares, other Awards, other property, net settlement, or any combination thereof) of applicable withholding taxes due in respect of an Award, its exercise or settlement or any payment or transfer under such Award or under the Plan and to take such other action (including providing for elective payment of such amounts in cash or Shares by the Participant) as may be necessary in the opinion of the Company to satisfy all obligations for the payment of such taxes; provided that if the Committee allows the withholding or surrender of Shares to satisfy a Participant’s tax withholding obligations, the aggregate Fair Market Value of such withheld or surrendered Shares shall not exceed the minimum statutory withholding amount for federal and state tax purposes, including payroll taxes.

(e)   If any provision of the Plan or any Award Document is or becomes or is deemed to be invalid, illegal or unenforceable in any jurisdiction, or as to any person or Award, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to applicable laws, or if it cannot be so construed or deemed amended without, in the determination of the Committee, materially altering the intent of the Plan or the Award Document, such provision shall be stricken as to such jurisdiction, person or Award, and the remainder of the Plan and any such Award Document shall remain in full force and effect.

(f)    Neither the Plan nor any Award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company and a Participant or any other person. To the extent that any person acquires a right to receive payments from the Company pursuant to an Award, such right shall be no greater than the right of any unsecured general creditor of the Company.

(g)   No fractional Shares shall be issued or delivered pursuant to the Plan or any Award, and the Committee shall determine whether cash or other securities shall be paid or transferred in lieu of any fractional Shares, or whether such fractional Shares or any rights thereto shall be canceled, terminated or otherwise eliminated.

Section 15.    Effective Date of the Plan.    The Plan shall be effective as of the Effective Date.

Section 16.    Term of the Plan.    No Award shall be granted under the Plan after the earliest to occur of (i) the tenth year anniversary of the Effective Date, (ii) the maximum number of Shares available for issuance under the Plan have been issued or (iii) the Board terminates the Plan in accordance with Section 13(a). However, unless otherwise expressly provided in the Plan or in an applicable Award Document, any Award theretofore granted may extend beyond such date, and the authority of the Committee to amend, alter, adjust, suspend, discontinue or terminate any such Award, or to waive any conditions or rights under any such Award, and the authority of the Board to amend the Plan, shall extend beyond such date.

Section 17.    Section 409A of the Code.    With respect to Awards subject to Section 409A of the Code, the Plan is intended to comply with the requirements of Section 409A of the Code, and the provisions of the Plan and any Award Document shall be interpreted in a manner that satisfies the requirements of Section 409A of the Code, and the Plan shall be operated accordingly. If any provision

of the Plan or any term or condition of any Award would otherwise frustrate or conflict with this intent, the provision, term or condition will be interpreted and deemed amended so as to avoid this conflict. Notwithstanding any of the foregoing, the Company makes no representations or warranty and shall have no liability to the Participant or any other person if any provisions or payments, compensation or other benefits under the Plan are determined to constitute nonqualified deferred compensation subject to Section 409A of the Code but do not satisfy the provisions thereof.

Section 18.    Governing Law.    The Plan and each Award Document shall be governed by the laws of the State of Delaware, without application of the conflicts of law principles thereof.

EX-10.35

Exhibit 10.35

COBALT INTERNATIONAL ENERGY, INC.

DEFERRED COMPENSATION PLAN

SECTION 1.  Purpose.  Cobalt International Energy, Inc. (the “Company”) hereby adopts and establishes the Cobalt International Energy, Inc. Deferred Compensation Plan (the “Plan”) under the Cobalt International Energy, Inc. Long Term Incentive Plan (the “LTIP”) to allow certain of its executives to defer receipt of a portion of their compensation and to encourage them to acquire additional shares of the Company’s common stock, thereby furthering the best interests of the Company and its shareholders.

SECTION 2.  Definitions.  Capitalized terms used but not defined herein shall have the meanings assigned to them in the LTIP.  As used herein, the following definitions shall apply:

(a)        “Annual Bonus” means the cash bonus, if any, awarded to a Participant by the Company for services rendered under any bonus or cash incentive plan maintained by the Company.

(b)        “Base Salary” means the base salary paid by the Company to or for the benefit of the Participant for services rendered.

(c)        “Eligible Employee” means an Employee who is selected by the Committee to participate in the Plan.

(d)        “Employee” means an employee of the Company or its Affiliates.

(e)        “Disability” means, with respect to a Participant, that such Participant is:

(i)            unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months; or

(ii)           by reason of any medically determinable physical or mental impairment, which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Company.

(f)        “Participant” means an Eligible Employee who elects to participate in the Plan by filing an Election Form in accordance with Section 5(b) and any former Eligible Employee who continues to be entitled to a benefit under the Plan.

(g)        “Plan Year” means a calendar year; provided, however that if a newly-hired or promoted Employee first becomes eligible to participate in the Plan on a day other than the first day of the Plan Year, the initial Plan Year for

such Employee shall be the portion of the calendar year during which the Employee is first eligible to participate in the Plan.

(h)        “Separation from Service” means, with respect to a Participant, the (i) cessation of all services performed by such Participant for the Company or (ii) permanent decrease in the level of services performed by such Participant for the Company (whether as an employee or as an independent contractor) to no more than 20 percent of the average level of services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Company, if such Participant has been providing services to the Company for less than 36 months).

Part I
Participation and Deferrals

SECTION 3.  Administration; Shares Available for Issuance.

(a)        The Plan shall be administered by the Committee.  Subject to the terms of the Plan and applicable law, the Committee shall have full power and authority to: (i) designate Eligible Employees; (ii) determine the terms and conditions of any deferral made under the Plan; (iii) interpret and administer the Plan and any instrument or agreement relating to, or deferral made under, the Plan; (iv) establish, amend, suspend or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the Plan; and (v) make any other determination and take any other action that the Committee deems necessary or desirable for the administration of the Plan.  All decisions of the Committee shall be final, conclusive and binding upon all parties, including the Company, its shareholders and the Participants and any Beneficiaries thereof.

(b)        The maximum number of Shares available for issuance under the Plan is subject to, and shall be counted against, the maximum number of Shares available for issuance under the LTIP.

SECTION 4.  Eligibility; Participation.  Participation in the Plan is limited to a select group of the Company’s key management or highly compensated employees.  Before the beginning of each Plan Year, the Committee shall select those Employees who shall be Eligible Employees for such Plan Year; provided, however, that the Committee may designate a newly-hired or promoted Employee as eligible to participate in the Plan at the time of his or her hire or promotion and in no event later than 30 days following such Employee’s employment commencement date or promotion date, as applicable.  In the event a Participant previously selected to participate in the Plan no longer meets the criteria for participation, such Participant shall become an inactive Participant, retaining all the rights described under the Plan, except the right to make any further deferrals, until such time that the Participant again becomes an active

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Participant.

SECTION 5.  Deferrals.

(a)        Base Salary and Annual Bonus.

(i)            Each Participant may elect to defer receipt of all or any portion of the Base Salary earned by such Participant for any Plan Year, subject to any applicable withholding (“Deferred Base Salary”).  Deferred Base Salary shall be credited to a Participant’s Share Account (as defined below) as of the date the Deferred Base Salary otherwise would have been paid (each such date, the “Base Salary Deferral Date”).

(ii)           Each Participant may elect to defer receipt of all or any portion of any Annual Bonus which may be earned by such Participant for any Plan Year, subject to any applicable withholding (“Deferred Annual Bonus”).  Deferred Annual Bonus shall be credited to a Participant’s Share Account as of the date the Deferred Annual Bonus otherwise would have been paid (each such date, the “Annual Bonus Deferral Date”).

(b)        Election Forms.  A Participant’s deferral election shall be made in the form of a document (an “Election Form”) established for such purpose by the Committee that is executed by such Participant and filed with the Secretary of the Company.  The Election Form will require such Participant to specify:

(i)            the amount or percentage of Base Salary and/or Annual Bonus to be deferred for a Plan Year; and

(ii)           the time at which the deferred amounts will be distributed to such Participant, which time may be (x) a specified date, (y) the Participant’s Separation from Service or (z) the earlier of a specified date and the Participant’s Separation from Service.

(c)        Timing of Elections.

(i)            Base Salary.  Subject to Section 5(c)(iii), an Election Form executed by a Participant shall apply to any Base Salary that is earned by such Participant at any time following the Plan Year in which such Election Form is executed.

(ii)           Annual Bonus.  Subject to Section 5(c)(iii), an Election Form executed by a Participant shall apply to any Annual Bonus that is earned by such Participant at any time following the Plan Year in which such Election Form is executed; provided that if the Annual Bonus qualifies as “performance-based compensation” under Code Section 409A, the Election Form executed by a Participant can be made up until June 30 of the Plan Year to which such Annual Bonus relates if the Committee

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determines that the performance goals applicable to such Annual Bonus are not readily ascertainable at the time of such election.

(iii)          An Election Form filed by a Participant within 30 days after such Participant becomes eligible to participate in the Plan shall apply to any Base Salary or Annual Bonus that is earned by such Participant on or following the date on which such Participant executes such Election Form.

(iv)          Each Election Form to defer Base Salary and/or Annual Bonus will remain in effect until superseded or revoked pursuant to this Section 5.

(d)        Subsequent Election Forms.  A Participant who has an Election Form on file with the Company may execute and file with the Secretary of the Company a subsequent Election Form at any time.  Such subsequent Election Form shall apply to any Base Salary or Annual Bonus that is earned by such Participant following the Plan Year in which such subsequent Election Form is executed.

(e)        Revoking Election Forms.  A Participant may revoke an Election Form at any time by providing written notice to the Secretary of the Company.  Such revocation shall apply to any Base Salary or Annual Bonus that is earned by such Participant following the Plan Year in which such notice is provided; provided that, if a revocation with respect to a Participant’s Annual Bonus is made not later than June 30 of a Plan Year and the Committee determines that the performance goals applicable to such Participant’s Annual Bonus for such Plan Year are not then readily ascertainable, such revocation shall apply also to such Annual Bonus.

(f)        Redeferrals.  Not later than 12 months prior to the date on which Deferred Base Salary or Deferred Annual Bonus is scheduled to be distributed to a Participant, such Participant may elect to redefer such Deferred Base Salary or Deferred Annual Bonus to a date that is not less than five years after such scheduled distribution date.

(g)        Vesting.  All Deferred Base Salary and Deferred Annual Bonus shall be fully vested and non-forfeitable at all times.

SECTION 6.  Timing and Form of Distribution.

(a)        Subject to this Section 6, distribution with respect to a Participant’s Deferred Base Salary or Deferred Annual Bonus shall be made to such Participant in a single installment of Shares at the time specified on the applicable Election Form and in accordance with Section 7.

(b)        The Committee, in its sole discretion, may accelerate the

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distribution of a Participant’s Deferred Base Salary or Deferred Annual Bonus if such Participant experiences an unforeseeable emergency or hardship, provided that such distribution complies with Code Section 409A.

(c)        All of a Participant’s Deferred Base Salary and Deferred Annual Bonus shall be distributed to such Participant upon such Participant’s death or Disability or upon the occurrence of a Change in Control; provided that the occurrence of a Change in Control also meets the definition of a “change in ownership or effective control” under Code Section 409A.

(d)        If the Committee reasonably anticipates that if a payment were made as scheduled under the Plan it would result in a loss of the Company’s tax deduction due to the application of Code Section 162(m), such payment may be delayed and paid (i) during the Company’s first taxable year in which the Committee reasonably anticipates that the Company’s tax deduction will not be limited or eliminated by the application of Code Section 162(m) or (b) during the period beginning with the Participant’s Separation from Service and ending on the later of the last day of the Company’s taxable year in which such Separation from Service occurs or the 15th day of the third month following the Participant’s Separation from Service.

(e)        If the Committee considers a Participant to be one of the Company’s “specified employees” under Code Section 409A at the time of such Participant’s Separation from Service, any distribution that otherwise would be made to such Participant as a result of such Separation from Service shall not be made until the date that is six months after such Separation from Service, except to the extent that earlier distribution would not result in such Participant’s incurring interest or additional tax under Code Section 409A.

SECTION 7.  Amount of Distribution.

(a)        All Deferred Base Salary and Deferred Annual Bonus shall be notionally invested in Shares from the applicable Base Salary Deferral Date or Annual Bonus Deferral Date through the applicable distribution date.  The initial number of such notional Shares shall be determined by dividing the amount of the Deferred Base Salary or Deferred Annual Bonus, as applicable, by the closing price of a Share on the Base Salary Deferral Date or Annual Bonus Deferral Date, as applicable.  Each Participant’s Deferred Base Salary and Deferred Annual Bonus shall be allocated to a separate bookkeeping account (a “Share Account”) established and maintained by the Committee to record the number of Shares in which such Deferred Base Salary and Deferred Annual Bonus are notionally invested.

(b)        A Participant’s Share Account shall be credited with any dividend (a “Dividend Equivalent”) that would have been paid on a number of outstanding Shares equal to the number of notional Shares credited to such account as of the

5

dividend record date.  Any such Dividend Equivalent so credited shall be converted into that number of notional Shares equal to (x) in the case of a share dividend, the number of Shares that otherwise would have been paid to such Participant and (y) in the case of a cash dividend, the amount of the cash dividend that otherwise would have been paid to such Participant divided by the closing price of a Share on the dividend payment date.

(c)        On the distribution date applicable to a Participant’s Deferred Base Salary or Deferred Annual Bonus, such Participant shall receive a number of Shares equal to the number of notional Shares credited to the applicable Share Account as of such distribution date.

SECTION 8.  General Provisions Applicable to Deferrals.

(a)        Except as may be permitted by the Committee, (i) no deferral and no right under such deferral shall be assignable, alienable, saleable or transferable by a Participant otherwise than by will or pursuant to Section 8(b) and (ii) during a Participant’s lifetime, each deferral, and each right under such deferral, shall be exercisable only by such Participant or, if permissible under applicable law, by such Participant’s guardian or legal representative.  The provisions of this Section 8(a) shall not apply to any deferral that has been distributed to a Participant.

(b)        A Participant may designate a Beneficiary or change a previous Beneficiary designation at such times prescribed by the Committee by using forms and following procedures approved or accepted by the Committee for that purpose.

(c)        All certificates for Shares delivered upon the distribution of such Shares under the Plan shall be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the Plan or the rules, regulations and other requirements of the Securities and Exchange Commission, any stock market or exchange upon which such Shares or other securities are then quoted, traded or listed, and any applicable securities laws, and the Committee may cause a legend or legends to be put on any such certificates to make appropriate reference to such restrictions.

SECTION 9.  Amendments and Termination.

(a)        The Committee, in its sole discretion, may amend, suspend or discontinue the Plan or any deferral at any time; provided that no such amendment, suspension or discontinuance shall reduce the accrued benefit of any Participant except to the extent necessary to comply with any provision of federal, state or other applicable law.  The Committee further has the right, without a Participant’s consent, to amend or modify the terms of the Plan and such Participant’s deferral to the extent that the Committee deems it necessary to avoid adverse or unintended tax consequences to such Participant under Code Section

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409A.

(b)        The Committee, in its sole discretion, may terminate the Plan at any time, as long as such termination complies with then applicable tax and other requirements.  Distributions of amounts deferred under the Plan as of the date on which the Plan is terminated will be made in a lump sum payment 12 months after such termination, unless the right to receive a distribution in accordance with the terms of the Plan would occur before the end of such 12-month period, in which case distribution will be made in accordance with the terms of the Plan.

(c)        Such other changes to deferrals shall be permitted and honored under the Plan to the extent authorized by the Committee and consistent with Code Section 409A.

SECTION 10.  Miscellaneous.

(a)        No Participant or other person shall have any claim to be entitled to make a deferral under the Plan, and there is no obligation for uniformity of treatment of Participants or Beneficiaries under the Plan.  The terms and conditions of deferrals under the Plan need not be the same with respect to each Participant.

(b)        The opportunity to make a deferral under the Plan shall not be construed as giving a Participant the right to be retained in the service of the Company.  A Participant’s deferral under the Plan is not intended to confer any rights on such Participant except as set forth in the Plan and the applicable Election Form.

(c)        Nothing contained in the Plan shall prevent the Company from adopting or continuing in effect other or additional compensation arrangements, and such arrangements may be either generally applicable or applicable only in specific cases.

(d)        The Company shall be authorized to withhold from any distribution under the Plan or from any compensation or other amount owing to a Participant the amount (in cash, Shares, other property, net settlement, or any combination thereof) of applicable withholding taxes due in respect of such distribution and to take such other action (including providing for elective payment of such amounts in cash or Shares by such Participant) as may be necessary in the opinion of the Company to satisfy all obligations for the payment of such taxes.

(e)        If any provision of the Plan or any Election Form is or becomes or is deemed to be invalid, illegal or unenforceable in any jurisdiction, or as to any person or deferral, or would disqualify the Plan or any deferral under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to applicable laws, or if it cannot be so construed or deemed amended without, in the determination of the Committee, materially

7

altering the intent of the Plan or such Election Form, such provision shall be stricken as to such jurisdiction, person or deferral, and the remainder of the Plan and such Election Form shall remain in full force and effect.

SECTION 11. Claims Procedure.

(a)        Filing a Claim.  Any Participant or other person claiming an interest in the Plan (the “Claimant”) may file a claim in writing with the Committee.  The Committee shall review the claim itself or appoint an individual or entity to review the claim.

(b)        Claim Decision.  The Claimant shall be notified within ninety (90) days after the claim is filed whether the claim is approved or denied, unless the Committee determines that special circumstances beyond the control of the Plan require an extension of time, in which case the Committee may have up to an additional ninety (90) days to process the claim.  If the Committee determines that an extension of time for processing is required, the Committee shall furnish written or electronic notice of the extension to the Claimant before the end of the initial ninety (90) day period.  Any notice of extension shall describe the special circumstances necessitating the additional time and the date by which the Committee expects to render its decision.

(c)        Notice of Denial.  If the Committee denies the claim, it must provide to the Claimant, in writing or by electronic communication, a notice which includes:

(i)            the specific reason or reasons for the denial;

(ii)           specific reference to pertinent Plan provisions on which the denial is based;

(iii)          a description of any additional material or information necessary for the Claimant to perfect the claim and an explanation of why such material or information is necessary; and

(iv)          appropriate information as to the steps to be taken in order to submit a claim for review.

(d)        Appeal Procedures.  A request for appeal of a denied claim must be made in writing to the Committee within sixty (60) days after receiving notice of denial.  The decision on appeal will be made within sixty (60) days after the Committee’s receipt of a request for appeal, unless special circumstances require an extension of time for processing, in which case a decision will be rendered not later than one hundred twenty (120) days after receipt of a request for appeal.  A notice of such an extension must be provided to the Claimant within the initial sixty (60) day period and must explain the special circumstances and provide an expected date of decision.  The reviewer shall afford the Claimant an opportunity

8

to review and receive, without charge, all relevant documents, information and records and to submit issues and comments in writing to the Committee.  The reviewer shall take into account all comments, documents, records and other information submitted by the Claimant relating to the claim regardless of whether the information was submitted or considered in the initial benefit determination.

(e)        Notice of Decision on Appeal.  If the Committee denies the appeal, it must provide to the Claimant, in writing or by electronic communication, a notice which includes:

(i)            the specific reason(s) for the denial;

(ii)           specific references to the pertinent Plan provisions on which such denial is based;

(iii)          a statement that the Claimant may receive on request all relevant records at no charge;

(iv)          a description of the Plan’s voluntary procedures and deadlines, if any; and

(v)           a statement of the Claimant’s right to bring an action under Section 502(a) of ERISA.

SECTION 12.  Effective Date of the Plan.  The Plan shall be effective as of the date on which the Plan is adopted by the Committee.

SECTION 13.  Unfunded Status of the Plan.  The Plan is unfunded.  The Plan, together with the applicable Election Form, shall represent at all times an unfunded and unsecured contractual obligation of the Company.  Each Participant and Beneficiary will be an unsecured creditor of the Company with respect to all obligations owed to them under the Plan.  Amounts payable under the Plan will be satisfied solely out of the general assets of the Company subject to the claims of its creditors.  No Participant or Beneficiary will have any interest in any fund or in any specific asset of the Company of any kind, nor shall such Participant or Beneficiary or any other person have any right to receive any payment or distribution under the Plan except as, and to the extent, expressly provided in the Plan and the applicable Election Form.  The Company will not segregate any funds or assets to provide for any distribution under the Plan.  Any reserve or other asset that the Company may establish or acquire to assure itself of the funds to provide payments required under the Plan shall not serve in any way as security to any Participant or Beneficiary for the Company’s performance under the Plan.

SECTION 14.  Code Section 409A.  With respect to deferrals that are subject to Code Section 409A, the Plan is intended to comply with the requirements of Code Section 409A, and the provisions of the Plan and any Election Form shall be interpreted in a manner that satisfies the requirements of

9

Code Section 409A, and the Plan shall be operated accordingly.  If any provision of the Plan or any term or condition of any Election Form would otherwise frustrate or conflict with this intent, the provision, term or condition will be interpreted and deemed amended so as to avoid this conflict.

SECTION 15.  Governing Law.  The Plan and each Election Form shall be governed by the laws of the State of Delaware, without application of the conflicts of law principles thereof.

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EX-10.36

Exhibit 10.36

AMENDED AND RESTATED STOCKHOLDERS AGREEMENT

by and among

COBALT INTERNATIONAL ENERGY, INC.

and

THE STOCKHOLDERS THAT ARE SIGNATORIES HERETO

Dated as of February 21, 2013

TABLE OF CONTENTS

		Page
ARTICLE I. DEFINITIONS		1
Section 1.1.	Definitions	1
Section 1.2.	Other Interpretive Provisions	4
ARTICLE II. REPRESENTATIONS AND WARRANTIES		4
Section 2.1.	Existence; Authority; Enforceability	4
Section 2.2.	Absence of Conflicts	4
Section 2.3.	Consents	4
ARTICLE III. GOVERNANCE		5
Section 3.1.	Information; Duties	5
Section 3.2.	Freedom to Pursue Opportunities	5
ARTICLE IV. GENERAL PROVISIONS		6
Section 4.1.	Further Assurances	6
Section 4.2.	Assignment; Benefit	6
Section 4.3.	Termination	6
Section 4.4.	Other Activities	6
Section 4.5.	Severability	6
Section 4.6.	Entire Agreement	6
Section 4.7.	Amendment	6
Section 4.8.	Waiver	7
Section 4.9.	Counterparts	7
Section 4.10.	Notices	7
Section 4.11.	Governing Law	8
Section 4.12.	Jurisdiction	8
Section 4.13.	Waiver of Jury Trial	8
Section 4.14.	Specific Performance	8
Section 4.15.	Marketing Materials	8
Section 4.16.	Notice of Events	8
Section 4.17.	Adjustments	9
Section 4.18.	No Third Party Beneficiaries	9

AMENDED AND RESTATED STOCKHOLDERS AGREEMENT

THIS AMENDED AND RESTATED STOCKHOLDERS AGREEMENT (as it may be amended from time to time in accordance with the terms hereof, this “Agreement”), dated as of February 21, 2013, is made by and among Cobalt International Energy, Inc., a Delaware corporation (the “Company”), and the stockholders that are signatories hereto (each a “Stockholder” and collectively, the “Stockholders”).

RECITALS

WHEREAS, the Company and the Stockholders (or their respective Affiliates) are parties to that certain Stockholders Agreement, dated as of December 15, 2009 (the “Original Stockholders Agreement”), entered in connection with the Company’s initial public offering;

WHEREAS, as a result of the Stockholders’ sale of certain Company Shares (as defined below) pursuant to a registered underwritten offering which closed on January 18, 2013, as of the date hereof the Stockholders beneficially own in the aggregate less than a majority of the outstanding Company Shares; and

WHEREAS, subject to the terms and conditions herein, the Stockholders and the Company desire to enter into this Agreement to amend and restate the Original Stockholders Agreement to provide for the rights and obligations of the Stockholders and the Company stated herein.

NOW, THEREFORE, in consideration of the foregoing and the mutual promises, covenants and agreements of the Parties, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree as follows:

ARTICLE I.
DEFINITIONS

Section 1.1.Definitions.  As used in this Agreement, the following terms shall have the following meanings:

“Affected Stockholder” has the meaning set forth in Section 4.7.

“Affiliate” means (a) with respect to any GSCP Party, any C/R Party and any FR Party, any Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person, and includes any private equity investment fund the primary investment advisor to which is the primary investment advisor (or an Affiliate thereof) to such specified Person, (b) with respect to any of the KERN Parties, any Person directly or indirectly controlling or controlled by or under direct or indirect common control with KERN Partners Ltd. and (c) with respect to any other Person, any Person directly or indirectly controlling or controlled by or under direct or indirect common control with such Person.  It being understood and agreed that, for purposes hereof, (i) each GSCP Party shall be deemed to be an Affiliate of every other GSCP Party, (ii) each C/R Party shall be deemed to be an Affiliate of every other C/R Party, (iii) each FR Party shall be deemed to be an Affiliate of every other FR Party, (iv)

neither the Company nor any subsidiary of the Company shall be deemed to be an Affiliate of any Stockholder, (v) except as set forth in clauses (i) through (iii) above, no Stockholder shall be deemed to be an Affiliate of any other Stockholder and (vi) neither the Board of Trustees of Leland Stanford Junior University nor Caisse de Depot et Placement du Quebec or any of their Affiliates shall be deemed to be Affiliates of KERN Cobalt Co-Invest Partners AP LP, KERN Partners Ltd. or any KERN Party.

“Agreement” has the meaning set forth in the preamble.

“Board of Directors” means the board of directors of the Company.

“Company” has the meaning set forth in the preamble.

“Company Shares” means common stock of the Company, par value $0.01 per share, and any and all securities of any kind whatsoever of the Company that may be issued by the Company after the date hereof in respect of, in exchange for, or in substitution of, Company Shares, pursuant to any stock dividends, splits, reverse splits, combinations, reclassifications, recapitalizations, reorganizations and the like occurring after the date hereof.

“C/R Parties” means, collectively, C/R Cobalt Investment Partnership, L.P., C/R Energy Coinvestment II, L.P., Riverstone Energy Coinvestment III, L.P., Carlyle Energy Coinvestment III, L.P., C/R Energy III Cobalt Partnership, L.P. and Carlyle/Riverstone Global Energy and Power Fund III, L.P.

“Directed Opportunity” has the meaning set forth in Section 3.2.

“Director” means a member of the Board of Directors.

“FR Parties” means, collectively, First Reserve Fund XI, L.P. and FR XI Onshore AIV, L.P.

“Governing Documents” means the certificate of incorporation of the Company, as amended or modified from time to time, and the by-laws of the Company, as amended or modified from time to time.

“GSCP Parties” means, collectively, GSCP V Cobalt Holdings, LLC, GSCP V Offshore Cobalt Holdings, LLC, GSCP V GMBH Cobalt Holdings, LLC, GSCP VI Cobalt Holdings, LLC, GSCP VI Offshore Cobalt Holdings, LLC, GSCP VI GMBH Cobalt Holdings, LLC, GS Capital Partners V Institutional, L.P. and GS Capital Partners VI Parallel, L.P.

“independent director” means a Director who qualifies, as of the date of such Director’s election or appointment to the Board of Directors and as of any other date on which the determination is being made, as an “independent director” pursuant to SEC rules and applicable listing standards, as amended from time to time, as determined by the Board of Directors without the vote of such Director.

“Investor Director” means any Director employed by or affiliated with an Investor or any of its Affiliates.

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“Investor Party” means any Investor and any of their respective officers, directors, agents, stockholders, members, partners, Affiliates and subsidiaries (other than the Company and its subsidiaries), and any Investor Director.

“Investors” means the GSCP Parties, the C/R Parties, the FR Parties and the KERN Parties.

“KERN Parties” means KERN Cobalt Co-Invest Partners AP LP.

“Management Rights Agreements” means the management rights agreements between the Company and each of First Reserve Fund XI, L.P., FR XI Onshore AIV, L.P., C/R Cobalt Investment Partnership, L.P., Carlyle/Riverstone Global Energy and Power Fund III, L.P., GS Capital Partners V Institutional, L.P. and GS Capital Partners VI Parallel, L.P. as such agreements may be amended from time to time in accordance therewith.

“Party” means the Company and the Stockholders party to this Agreement.

“Person” means an individual, partnership, limited liability company, corporation, trust, other entity, association, estate, unincorporated organization or a government or any agency or political subdivision thereof.

“Registration Rights Agreement” means that certain Registration Rights Agreement, dated as of the date of the Original Stockholders Agreement, by and among the Company, the Stockholders and the other parties that are signatories thereto, as such agreement may be amended from time to time in accordance therewith.

“Reorganization Agreement” means that certain Reorganization Agreement, dated as of the date of the Original Stockholders Agreement, by and among the Company, the Stockholders and the other parties that are signatories thereto, as such agreement may be amended from time to time in accordance therewith.

“SEC” means the Securities and Exchange Commission.

“Securities Act” means the United States Securities Act of 1933, as amended, and any successor thereto, and any rules and regulations promulgated thereunder, all as the same shall be in effect from time to time.

“Stockholder” and “Stockholders” have the meaning set forth in the preamble.

“Stockholder Majority” means the consent or approval of the Stockholders (including, if applicable, the Stockholder(s) requesting a consent or approval) then owning a majority of the Company Shares then owned by all of the Stockholders.

“Tag-Along Agreement” means that certain Tag-Along Agreement, dated as of the Original Stockholders Agreement, by and among the Stockholders and the other parties that are signatories thereto, as such agreement may be amended from time to time in accordance therewith.

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Section 1.2.Other Interpretive Provisions.

(a)The meanings of defined terms are equally applicable to the singular and plural forms of the defined terms.

(b)The words “hereof,” “herein,” “hereunder” and similar words refer to this Agreement as a whole and not to any particular provision of this Agreement; and any subsection and Section references are to this Agreement unless otherwise specified.

(c)The term “including” is not limiting and means “including without limitation.”

(d)The captions and headings of this Agreement are for convenience of reference only and shall not affect the interpretation of this Agreement.

(e)Whenever the context requires, any pronouns used herein shall include the corresponding masculine, feminine or neuter forms.

ARTICLE II.
REPRESENTATIONS AND WARRANTIES

Each of the Parties hereby represents and warrants, solely with respect to itself, to each other Party that:

Section 2.1.Existence; Authority; Enforceability.  Such Party has the power and authority to enter into this Agreement and to carry out its obligations hereunder.  Such Party is duly organized and validly existing under the laws of its jurisdiction of organization, and the execution of this Agreement, and the performance of its obligations hereunder, have been authorized by all necessary action, and no other act or proceeding on its part is necessary to authorize the execution of this Agreement or the performance of its obligations hereunder.  This Agreement has been duly executed by it and constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms except as the same may be affected by bankruptcy, insolvency, moratorium or similar laws, or by legal or equitable principles relating to or limiting the rights of contracting parties generally.

Section 2.2.Absence of Conflicts.  The execution and delivery by such Party of this Agreement and the performance of its obligations hereunder does not (a) conflict with, or result in the breach of any provision of the constitutive documents of such Party; (b) result in any violation, breach, conflict, default or event of default (or an event which with notice, lapse of time, or both, would constitute a default or event of default), or give rise to any right of acceleration or termination or any additional payment obligation, under the terms of any contract, agreement or permit to which such Party is a party or by which such Party’s assets or operations are bound or affected; or (c) violate any law applicable to such Party, except, in the case of clause (b), as would not have a material adverse effect on such Party’s ability to perform its obligations hereunder.

Section 2.3.Consents.  Other than as has already been obtained, no consent, waiver, approval, authorization, exemption, registration, license or declaration is required to be made or

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obtained by such Party in connection with the execution, delivery or performance of this Agreement, except in each case, as would not have a material adverse effect on such Party’s ability to perform its obligations hereunder.

ARTICLE III.
GOVERNANCE

Section 3.1.Information; Duties.

(a)The Company and the Stockholders agree that any Investor Director may share confidential, non-public information about the Company with his or her respective Investor Parties, in each case only to the extent reasonably necessary in connection with their investment in the Company, provided that such Investor Parties, as the case may be, agree to keep such information confidential (except as may be required by law or applicable listing standards then in effect) and agree to comply with all applicable securities laws in connection therewith.

(b)The Company and the Stockholders agree that, notwithstanding anything to the contrary in any other agreement or at law or in equity, when any of the Stockholders (in their capacity as Stockholders) takes any action under this Agreement to give or withhold its consent, such Person shall, to the fullest extent permitted by law, have no duty to consider the interests of the Company or the other Stockholders or any other stockholders of the Company and may act exclusively in its and its Affiliates own interests; provided, however, that the foregoing shall in no way affect the obligations of the Parties to comply with the provisions of this Agreement.

Section 3.2.Freedom to Pursue Opportunities.  To the fullest extent permitted by applicable law, the Company hereby, on behalf of itself and its subsidiaries, renounces any interest, duty or expectancy of the Company and its subsidiaries in, or in being offered an opportunity to participate in, business opportunities that are from time to time presented to any Investor Party even if the opportunity is one that the Company or its subsidiaries might reasonably be deemed to have pursued or had the ability or desire to pursue if granted the opportunity to do so and each Investor Party shall have no duty to communicate or offer such business opportunity to the Company and to the fullest extent permitted by applicable law, shall not be liable to the Company or any of its subsidiaries for breach of any fiduciary or other duty, as a Director or otherwise, by reason of the fact that such Investor Party pursues or acquires such business opportunity, directs such business opportunity to another Person or fails to present such business opportunity, or information regarding such business opportunity, to the Company or its subsidiaries.  Notwithstanding the foregoing, an Investor Director who is offered a business opportunity in his or her capacity as a Director (a “Directed Opportunity”) shall be obligated to communicate such Directed Opportunity to the Company, provided, however, that all of the protections of this Section 3.2 shall otherwise apply to the Investor Party with respect to such Directed Opportunity, including, without limitation, the ability of the Investor Party to pursue or acquire such Directed Opportunity or to direct such Directed Opportunity to another Person.

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ARTICLE IV.
GENERAL PROVISIONS

Section 4.1.Further Assurances.  The Parties shall take all necessary action in order to give full effect to this Agreement and every provision hereof.  Each Party shall do and perform or cause to be done and performed all such further acts and things and shall execute and deliver all such other agreements, certificates, instruments, and documents as any other Party reasonably may request in order to carry out the intent and accomplish the purposes of this Agreement.

Section 4.2.Assignment; Benefit.  The rights and obligations hereunder shall not be assigned without the prior written consent of the Company and the Stockholder Majority.  Any assignment of rights or obligations in violation of this Section 4.2 shall be null and void.  This Agreement shall be binding upon and shall inure to the benefit of the Parties, and their respective successors and permitted assigns.

Section 4.3.Termination.  This Agreement shall terminate (i) with respect to each Stockholder, on the first day that such Stockholder’s respective Investor holds less than five percent of the outstanding Company Shares, and (ii) with respect to the Company, on the first date that no Investor holds five percent or more of the outstanding Company Shares; provided that termination of this Agreement shall not relieve any Party for liability for any breach of this Agreement prior to such termination.

Section 4.4.Other Activities.  Notwithstanding anything in this Agreement to the contrary, none of the provisions of this Agreement shall in any way limit Goldman, Sachs & Co. or any of its Affiliates (other than any Stockholder, as expressly set forth in this Agreement) from engaging in any brokerage, investment advisory, financial advisory, anti-raid advisory, principaling, merger advisory, financing, asset management, trading, market making, arbitrage, investment activity and other similar activities conducted in the ordinary course of their business.

Section 4.5.Severability.  In the event that any provision of this Agreement shall be invalid, illegal or unenforceable, such provision shall be construed by limiting it so as to be valid, legal and enforceable to the maximum extent provided by law and the validity, legality and enforceability of the remaining provisions of this Agreement shall not in any way be affected or impaired thereby.

Section 4.6.Entire Agreement.  This Agreement, the Registration Rights Agreement, the Reorganization Agreement, the Tag-Along Agreement, the Management Rights Agreement and the other agreements referenced herein and therein constitute the entire agreement among the Parties with respect to the subject matter hereof, and supersede any prior agreement or understanding among them with respect to the matters referred to herein.

Section 4.7.Amendment.  This Agreement may not be amended, modified, supplemented, waived or terminated (other than pursuant to Section 4.3) except with the written consent of the Stockholder Majority; provided that, any amendment, modification, supplement, waiver or termination that (a) materially and adversely affects the rights of any Stockholder under this Agreement disproportionately vis-à-vis any other Stockholder (each an “Affected Stockholder”) will require both (i) the written consent of the Stockholder Majority and (ii) the

6

written consent of Affected Stockholders holding a majority of the then outstanding Company Shares then held by all Affected Stockholders and (b) adversely affects the rights of the Company under this Agreement, imposes additional obligations on the Company, or amends or modifies Article IV, and any corresponding definitions in Article I, will require both (i) the written consent of the Stockholder Majority and (ii) the written consent of the Company with the approval of the “independent directors” of the Company who are not Investor Directors.

Section 4.8.Waiver.  Except as set forth in Section 4.7, no waiver of any breach of any of the terms of this Agreement shall be effective unless such waiver is expressly made in writing and executed and delivered by the Party against whom such waiver is claimed.  Waiver by any Party of any breach or default by any other Party of any of the terms of this Agreement shall not operate as a waiver of any other breach or default, whether similar to or different from the breach or default waived.  No waiver of any provision of this Agreement shall be implied from any course of dealing between the Parties or from any failure by any Party to assert its or his or her rights hereunder on any occasion or series of occasions.

Section 4.9.Counterparts.  This Agreement may be executed in any number of separate counterparts each of which when so executed shall be deemed to be an original and all of which together shall constitute one and the same agreement.

Section 4.10.Notices.  Unless otherwise specified herein, all notices, consents, approvals, reports, designations, requests, waivers, elections and other communications authorized or required to be given pursuant to this Agreement shall be in writing and shall be given, made or delivered (and shall be deemed to have been duly given, made or delivered upon receipt) by personal hand-delivery, by facsimile transmission, by electronic mail, by mailing the same in a sealed envelope, registered first-class mail, postage prepaid, return receipt requested, or by air courier guaranteeing overnight delivery, addressed to the Company at the address set forth below or to the applicable Stockholder at the address indicated on Annex A hereto (or at such other address for a Stockholder as shall be specified by like notice):

(a)if to the Company, to:

Cobalt International Energy, Inc.

Cobalt Center

920 Memorial City Way, Suite 100

Houston TX 77024
Attention: Joseph H. Bryant
Facsimile No.: (713) 579-9184
E-mail: joe.bryant@cobaltintl.com

with a copy to:

Davis Polk & Wardwell LLP
450 Lexington Avenue
New York, New York 10017
Attention:       Richard D. Truesdell, Jr.

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Facsimile No.:	(212) 701-5674
E-mail:	richard.truesdell@davispolk.com

Section 4.11.Governing Law.  This Agreement is governed by and will be construed in accordance with the laws of the State of Delaware, excluding any conflict-of-laws rule or principle (whether of Delaware or any other jurisdiction) that might refer the governance or the construction of this Agreement to the law of another jurisdiction.

Section 4.12.Jurisdiction.  Each of the Parties (a) consents to submit itself to the personal jurisdiction of the Court of Chancery of the State of Delaware in the event any dispute arises out of this Agreement, (b) agrees that it will not attempt to deny or defeat such personal jurisdiction by motion or other request for leave from such court and (c) agrees that it will not bring any action relating to this Agreement or any of the transactions contemplated by this Agreement in any court other than the Court of Chancery of the State of Delaware.  Each Party hereby agrees that, to the fullest extent permitted by law, service of any process, summons, notice or document by U.S. registered mail to the respective addresses set forth in Section 4.10 shall be effective service of process for any suit or proceeding in connection with this Agreement.

Section 4.13.Waiver of Jury Trial.  EACH OF THE PARTIES HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE ACTIONS OF THE PARTIES IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE AND ENFORCEMENT THEREOF.  The Company or any Stockholder may file an original counterpart or a copy of this Section 4.13 with any court as written evidence of the consent of any of the Parties to the waiver of their rights to trial by jury.

Section 4.14.Specific Performance.  It is hereby agreed and acknowledged that it will be impossible to measure the money damages that would be suffered if the Parties fail to comply with any of the obligations imposed on them by this Agreement and that, in the event of any such failure, an aggrieved Party will be irreparably damaged and will not have an adequate remedy at law.  Each Party shall, therefore, be entitled (in addition to any other remedy to which such Party may be entitled at law or in equity) to seek injunctive relief, including specific performance, to enforce such obligations, without the posting of any bond, and if any action should be brought in equity to enforce any of the provisions of this Agreement, none of the Parties shall raise the defense that there is an adequate remedy at law.

Section 4.15.Marketing Materials.  The Company grants each of the Investors and their respective Affiliates permission to use the Company’s name and logo in marketing materials of such Investor or any of its Affiliates.  The Investors and their respective Affiliates, as applicable, shall include a trademark attribution notice giving notice of the Company’s ownership of its trademarks in the marketing materials in which the Company’s name and logo appear.

Section 4.16.Notice of Events.  Except as otherwise would require early disclosure under applicable law or regulation, unless the applicable Investor notifies the Company that it does not want to receive information pursuant to this Section 4.16, the Company shall notify

8

each of the Investor on a reasonably current basis, of any events, discussions, notices or changes with respect to any criminal or regulatory investigation or action involving the Company or any of its subsidiaries, and shall reasonably cooperate with such Investor and its Affiliates in efforts to mitigate any adverse consequences to such Investor or its Affiliates which may arise (including by coordinating and providing assistance in meeting with regulators).

Section 4.17.Adjustments.  All references in this Agreement to Company Shares shall be appropriately adjusted for any stock dividends, splits, reverse splits, combinations, reclassifications, recapitalizations, reorganizations and the like occurring after the date hereof.

Section 4.18.No Third Party Beneficiaries.  Except as specifically provided in Section 4.2 and as otherwise provided herein, this Agreement is not intended to confer upon any Person, except for the Parties, any rights or remedies hereunder.

*   *   *

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IN WITNESS WHEREOF, the parties set forth below have duly executed this Agreement as of the day and year first above written.

COBALT INTERNATIONAL ENERGY, INC.
By:	/s/ Joseph H. Bryant
	Name:	Joseph H. Bryant
	Title:	Chairman of the Board and Chief Executive Officer

C/R COBALT INVESTMENT PARTNERSHIP, L.P.
By:	CARLYLE/RIVERSTONE ENERGY PARTNERS II, L.P.,
	its general partner
By:	C/R ENERGY GP II, LLC,
	its general partner
By:	/s/ Pierre F. Lapeyre, Jr.
	Name:	Pierre F. Lapeyre, Jr.
	Title:	Authorized Person
C/R ENERGY COINVESTMENT II, L.P.
By:	CARLYLE/RIVERSTONE ENERGY PARTNERS II, L.P.,
	its general partner
By:	C/R ENERGY GP II, LLC,
	its general partner
By:	/s/ Pierre F. Lapeyre, Jr.
	Name:	Pierre F. Lapeyre, Jr.
	Title:	Authorized Person
RIVERSTONE ENERGY COINVESTMENT III, L.P.
By:	RIVERSTONE COINVESTMENT GP, LLC
By:	RIVERSTONE HOLDINGS, LLC
By:	/s/ Pierre F. Lapeyre, Jr.
	Name:	Pierre F. Lapeyre, Jr.
	Title:	Authorized Person

CARLYLE ENERGY COINVESTMENT III, L.P.
By:	CARLYLE ENERGY COINVESTMENT III GP, L.L.C.,
	its general partner
By:	TCG HOLDINGS, L.L.C.
	its sole member
By:	/s/ Daniel A. D’Aniello
	Name:	Daniel A. D’Aniello
	Title:	Managing Director
C/R ENERGY III COBALT PARTNERSHIP, L.P.
By:	CARLYLE/RIVERSTONE ENERGY PARTNERS III, L.P.,
	its general partner
By:	C/R ENERGY GP III, LLC,
	its general partner
By:	/s/ Pierre F. Lapeyre, Jr.
	Name:	Pierre F. Lapeyre, Jr.
	Title:	Authorized Person
CARLYLE/RIVERSTONE GLOBAL ENERGY AND POWER FUND III, L.P.
By:	CARLYLE/RIVERSTONE ENERGY PARTNERS III, L.P.,
	its general partner
By:	C/R ENERGY GP III, LLC,
	its general partner
By:	/s/ Pierre F. Lapeyre, Jr.
	Name:	Pierre F. Lapeyre, Jr.
	Title:	Authorized Person

GSCP V COBALT HOLDINGS, LLC
By:	GS CAPITAL PARTNERS V FUND, L.P.,
	its sole member
By:	GSCP V ADVISORS, L.L.C.,
	its general partner
By:	/s/ Kenneth A. Pontarelli
	Name:	Kenneth A. Pontarelli
	Title:	Authorized Person
GSCP V OFFSHORE COBALT HOLDINGS, LLC
By:	GSCP V OFFSHORE COBALT HOLDINGS, L.P.,
	its sole member
By:	GS CAPITAL PARTNERS V OFFSHORE FUND, L.P.,
	its general partner
By:	GSCP V OFFSHORE ADVISORS, L.L.C.,
	its general partner
By:	/s/ Kenneth A. Pontarelli
	Name:	Kenneth A. Pontarelli
	Title:	Authorized Person

GS CAPITAL PARTNERS V INSTITUTIONAL, L.P.
By:	GS ADVISORS V, L.L.C.,
	its general partner
By:	/s/ Kenneth A. Pontarelli
	Name:	Kenneth A. Pontarelli
	Title:	Authorized Person
GSCP V GMBH COBALT HOLDINGS, LLC
By:	GSCP V GmbH Cobalt Holdings, L.P.,
	its sole member
By:	GSCP V GmbH Cobalt Holdings,
	its general partner
By:	/s/ Kenneth A. Pontarelli
	Name:	Kenneth A. Pontarelli
	Title:	Authorized Person
GSCP VI COBALT HOLDINGS, LLC
By:	GS CAPITAL PARTNERS VI FUND, L.P.,
	its sole member
By:	GSCP VI ADVISORS, L.L.C.,
	its general partner
By:	/s/ Kenneth A. Pontarelli
	Name:	Kenneth A. Pontarelli
	Title:	Authorized Person

GSCP VI OFFSHORE COBALT HOLDINGS, LLC
By:	GSCP VI OFFSHORE COBALT HOLDINGS, L.P.,
	its sole member
By:	GS CAPITAL PARTNERS VI OFFSHORE FUND, L.P.,
	its general partner
By:	GSCP VI OFFSHORE ADVISORS, L.L.C.,
	its general partner
By:	/s/ Kenneth A. Pontarelli
	Name:	Kenneth A. Pontarelli
	Title:	Authorized Person
GS CAPITAL PARTNERS VI PARALLEL, L.P.
By:	GS ADVISORS VI, L.L.C.,
	its general partner
By:	/s/ Kenneth A. Pontarelli
	Name:	Kenneth A. Pontarelli
	Title:	Authorized Person
GSCP VI GMBH COBALT HOLDINGS, LLC
By:	GSCP VI GmbH Cobalt Holdings, L.P.,
	its sole member
By:	GSCP VI GmbH Cobalt Holdings,
	its general partner
By:	/s/ Kenneth A. Pontarelli
	Name:	Kenneth A. Pontarelli
	Title:	Authorized Person

KERN COBALT CO-INVEST PARTNERS AP LP
By:	KERN Cobalt Group Management Ltd.,
	its general partner
By:	/s/ D. Jeff van Steenbergen
	Name:	D. Jeff van Steenbergen
	Title:	Director

FIRST RESERVE FUND XI, L.P.
By:	First Reserve GP XI, L.P.,
	its general partner
By:	First Reserve GP XI, Inc.,
	its general partner
By:	/s/ Michael France
	Name:	Michael France
	Title:	Managing Director
FR XI ONSHORE AIV, L.P.
By:	First Reserve GP XI, L.P.,
	its manager
By:	First Reserve GP XI, Inc.,
	its general partner
By:	/s/ Michael France
	Name:	Michael France
	Title:	Managing Director

ANNEX A

If to the GSCP Parties, to:

Goldman Sachs Capital Partners

c/o Goldman Sachs & Co.

85 Broad Street

New York, NY 10004

Attention:        Ken Pontarelli

David Thomas

Tel: 212-902-0353

Fax: 212-357-5505

Email:  Ken.Pontarelli@gs.com

David.Thomas@gs.com

with a copy (which shall not constitute notice) to:

Fried, Frank, Harris, Shriver & Jacobson

One New York Plaza

New York, NY 10004

Attention:        Robert C. Schwenkel

David L. Shaw

Tel: 212-859-8000

Fax: 212-859-4000

Email:  Robert.Schwenkel@friedfrank.com

David.Shaw@friedfrank.com

If to the C/R Parties, to:

Riverstone Holdings LLC

712 Fifth Avenue, 51st Floor

New York, NY 10019

Attn:  N. John Lancaster

Email:  john@riverstone.com

with a copy (which shall not constitute notice) to:

Fried, Frank, Harris, Shriver & Jacobson

One New York Plaza

New York, NY 10004

Attention:        Robert C. Schwenkel

David L. Shaw

Tel: 212-859-8000

Fax: 212-859-4000

Email:  Robert.Schwenkel@friedfrank.com

David.Shaw@friedfrank.com

If to the F/R Parties, to:

c/o First Reserve Corporation

One Lafayette Place

Greenwich, CT  06830

Attn:  Alan G. Schwartz

Email:  aschwartz@firstreserve.com

with a copy (which shall not constitute notice) to:

Simpson Thacher & Bartlett LLP

425 Lexington Avenue

New York, NY 10017-3954

Attention:        Barrie B. Covit

Tel: 212- 455-3141

Fax: 212- 455-2502

Email:  bcovit@stblaw.com

If to the KERN Parties, to:

c/o KERN Partners Ltd.

200 Doll Block

116-8th Avenue

Calgary, Alberta, Canada T26 0K4

Attn:  Jeff van Steenbergen

Email:  jvs@kernpartners.com

with a copy (which shall not constitute notice) to:

Fried, Frank, Harris, Shriver & Jacobson

One New York Plaza

New York, NY 10004

Attention:        Robert C. Schwenkel

David L. Shaw

Tel: 212-859-8000

Fax: 212-859-4000

Email:  Robert.Schwenkel@friedfrank.com

David.Shaw@friedfrank.com

and

Ropes & Gray LLP

One International Place

Boston, MA 02110-2624

Attention:        Richard E. Gordet

Tel: 617-951-7491

Fax: 617-235-0480

Email:  Rich.Gordet@ropesgray.com

and

Kaye Scholer LLP

425 Park Avenue

New York, NY  10022-3598

Attention:        Steven G. Canner

Tel: 212-836-8136

Fax:  212-836-8689

Email:  scanner@kayescholer.com

EX-21.1

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Exhibit 21.1

Cobalt International Energy, Inc. Subsidiary List

Subsidiary	Jurisdiction of Formation
Cobalt International Energy GP, LLC	Delaware
Cobalt International Energy, L.P.	Delaware
Cobalt GOM LLC	Delaware
Cobalt GOM #1 LLC	Delaware
Cobalt GOM #2 LLC	Delaware
Cobalt International Energy Overseas Ltd.	Cayman Islands
Cobalt International Energy Angola Ltd.	Cayman Islands
CIE Angola Block 9 Ltd.	Cayman Islands
CIE Angola Block 20 Ltd.	Cayman Islands
CIE Angola Block 21 Ltd.	Cayman Islands
Cobalt International Energy Gabon Ltd.	Cayman Islands
CIE Gabon Diaba Ltd.	Cayman Islands

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Exhibit 21.1

Cobalt International Energy, Inc. Subsidiary List

EX-23.1

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

        We consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-164624) pertaining to the Cobalt International Energy, Inc. Non-Employee Directors Compensation Plan and the Cobalt International Energy, Inc. Non-Employee Directors Deferral Plan, Form S-8 (No. 333-163883) pertaining to the Cobalt International Energy, Inc. Long Term Incentive Plan, and Form S-3 (No. 333-171536) related to the Prospectus of Cobalt International Energy, Inc. for the registration of common stock, preferred stock, debt securities, warrants, purchase contracts and units, respectively, of our reports dated February 26, 2013, with respect to the consolidated financial statements of Cobalt International Energy, Inc. (a development stage enterprise), and the effectiveness of internal control over financial reporting of Cobalt International Energy, Inc., included in this Annual Report (Form 10-K) for the year ended December 31, 2012.

/s/ Ernst & Young LLP
Houston, Texas
February 26, 2013

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

EX-31.1

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EXHIBIT 31.1

Certification by Joseph H. Bryant
Pursuant to Securities Exchange Act Rule 13a-14(a)

I, Joseph H. Bryant, certify that:

1.

I have reviewed this annual report on Form 10-K 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;

(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: February 26, 2013

/s/ JOSEPH H. BRYANT
Joseph H. Bryant
Chairman of the Board and Chief Executive Officer

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EXHIBIT 31.1

Certification by Joseph H. Bryant Pursuant to Securities Exchange Act Rule 13a-14(a)

EX-31.2

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EXHIBIT 31.2

Certification by John P. Wilkirson
Pursuant to Securities Exchange Act Rule 13a-14(a)

I, John P. Wilkirson, certify that:

1.

I have reviewed this annual report on Form 10-K 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;

(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: February 26, 2013

/s/ JOHN P. WILKIRSON
John P. Wilkirson
Chief Financial Officer and Executive Vice President

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EXHIBIT 31.2

Certification by John P. Wilkirson Pursuant to Securities Exchange Act Rule 13a-14(a)

EX-32.1

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EXHIBIT 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the Annual Report on Form 10-K of Cobalt International Energy, Inc. (the "Company") for the year ended December 31, 2012 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:

          (i)  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

         (ii)  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 26, 2013

/s/ JOSEPH H. BRYANT
Joseph H. Bryant
Chairman of the Board of Directors and Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to Cobalt International Energy, Inc. and will be retained by Cobalt International Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

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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

EX-32.2

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EXHIBIT 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the Annual Report on Form 10-K of Cobalt International Energy, Inc. (the "Company") for the year ended December 31, 2012 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:

          (i)  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

         (ii)  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 26, 2013

/s/ JOHN P. WILKIRSON
John P. Wilkirson
Chief Financial Officer and Executive Vice President

A signed original of this written statement required by Section 906 has been provided to Cobalt International Energy, Inc. and will be retained by Cobalt International Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

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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

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Seismic and Exploration Expenses (Tables)

12 Months Ended

Dec. 31, 2012

Seismic and Exploration Expenses

Schedule of seismic and exploration expenses

								For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Seismic costs	$	42,447	$	20,443	$	39,748		$	342,048
Seismic cost recovery(1)		—		—		(15,126	)		(25,126	)
Leasehold delay rentals		6,383		6,075		5,989			32,903
Force Majeure expense(2)		—		—		13,549			13,549
Drilling rig expense		12,753		5,721		870			26,799
	$	61,583	$	32,239	$	45,030		$	390,173

(1)

These amounts represent reimbursement from partners of past seismic costs incurred by the Company.

(2)

These amounts represent 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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Property, Plant, and Equipment (Details) (USD $)	12 Months Ended			86 Months Ended				12 Months Ended			86 Months Ended	0 Months Ended		12 Months Ended		12 Months Ended			12 Months Ended				12 Months Ended						12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012	Dec. 31, 2012 Block 20 offshore Angola	Mar. 31, 2012 Block 20 offshore Angola	Dec. 31, 2012 Diaba block offshore Gabon	Dec. 31, 2012 Unproved oil and gas properties, net	Dec. 31, 2011 Unproved oil and gas properties, net	Dec. 31, 2010 Unproved oil and gas properties, net	Dec. 31, 2012 Unproved oil and gas properties, net	Dec. 20, 2011 Unproved oil and gas properties, net Block 20 offshore Angola	Dec. 31, 2012 Unproved oil and gas properties, net Block 20 offshore Angola	Dec. 31, 2012 Unproved oil and gas properties, net Blocks 9 and 21 offshore Angola and Gabon	Dec. 20, 2011 Unproved oil and gas properties, net Blocks 9 and 21 offshore Angola and Gabon	Dec. 31, 2012 Unproved oil and gas properties, net U.S. Gulf of Mexico	Dec. 31, 2012 Exploratory wells in process	Dec. 31, 2011 Exploratory wells in process	Dec. 31, 2012 Computer equipment and software	Dec. 31, 2011 Computer equipment and software	Dec. 31, 2012 Office equipment and furniture	Dec. 31, 2011 Office equipment and furniture	Dec. 31, 2012 Office equipment and furniture Minimum	Dec. 31, 2012 Office equipment and furniture Maximum	Dec. 31, 2012 Vehicles	Dec. 31, 2011 Vehicles	Dec. 31, 2012 Leasehold improvements	Dec. 31, 2011 Leasehold improvements	Dec. 31, 2012 Leasehold improvements Minimum	Dec. 31, 2012 Leasehold improvements Maximum
Property, Plant, and Equipment
Estimated Useful Life																			3 years				3 years	5 years	3 years				3 years	10 years
Unproved oil and gas properties	$ 721,853,000	$ 701,892,000		$ 721,853,000
Less: accumulated valuation allowance	(78,413,000)	(18,275,000)		(78,413,000)
Total oil and gas properties, net	1,094,464,000	861,955,000		1,094,464,000				643,440,000	683,617,000		643,440,000						451,024,000	178,338,000
Property, plant, and equipment, gross	7,825,000	4,926,000		7,825,000															3,166,000	2,847,000	2,093,000	1,114,000			268,000	129,000	2,298,000	836,000
Less: accumulated depreciation and amortization	(2,533,000)	(3,555,000)		(2,533,000)
Total other property and equipment	5,292,000	1,371,000		5,292,000
Total property, plant, and equipment, net	1,099,756,000	863,326,000		1,099,756,000
Old computer equipment and leasehold improvements written off during the period	2,200,000
Depreciation and amortization expense	1,197,000	735,000	787,000	4,751,000
Percentage of working interest acquired							21.25%					40.00%	40.00%	40.00%	40.00%
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						122,800,000
Short-term and long-term contractual obligations					214,300,000
Unproved	19,961,000	337,126,000	1,746,000											10,800,000		20,000,000
Unproved property acquisition costs, net of valuation allowance, relating to properties offshore																285,600,000
Lower limit of unproved leasehold costs assessed individually for impairment								1,000,000			1,000,000
Upper limit of unproved leasehold costs on individual properties included in group amortization								1,000,000			1,000,000
Carrying amount of unproved leaseholds subject to amortization before impairment provision								69,100,000	65,100,000		69,100,000
Amortization expense								$ 60,200,000	$ 9,100,000	$ 9,100,000	$ 78,400,000

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Cash and Cash Equivalents (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash and Cash Equivalents
Cash at banks	$ 65,935	$ 2,992
Money market funds	1,105,148	104,805
Held-to-maturity securities	254,732	184,749
Total	$ 1,425,815	$ 292,546	$ 302,720	$ 1,093,100

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended				86 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012 Segment	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2012
Segment Information
Number of geographic operating segments									2
Segment Information
Operating costs and expense	$ 64,405	$ 40,553	$ 142,155	$ 37,715	$ 52,303	$ 48,242	$ 20,536	$ 16,755	$ 284,828	$ 137,836	$ 138,058		$ 939,599
Interest (income) expense									(1,829)	(4,199)	(1,582)
Net income (loss)	(66,531)	(39,214)	(140,723)	(36,531)	(51,114)	(46,987)	(19,478)	(16,058)	(282,999)	(133,637)	(136,476)	(81,257)	(927,835)
Additions to Property and Equipment, net									236,430	399,558	7,844
United States
Segment Information
Operating costs and expense									231,196	80,425	94,619
Interest (income) expense									(1,824)	(4,194)	(1,582)
Net income (loss)									(229,372)	(76,231)	(93,037)
Additions to Property and Equipment, net									67,068	(12,324)	(7,844)
West Africa
Segment Information
Operating costs and expense									53,632	57,411	43,439
Interest (income) expense									(5)	(5)
Net income (loss)									(53,627)	(57,406)	(43,439)
Additions to Property and Equipment, net									$ 169,362	$ 411,882

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Property, Plant, and Equipment (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	$ 178,338	$ 106,881
Amounts charged to expense	(73,918)	(36,606)
End of period	451,024	178,338
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	451,024	178,338
Exploratory Well costs capitalized for a period greater than one year after completion of drilling	194,853	97,861
Shenandoah #2 Appraisal Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense	12,700
Heidelberg #3 Appraisal Well Side Track
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense	4,100
Ligurian #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense	8,100
Ligurian #2 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Amounts charged to expense	49,000
U.S. Gulf of Mexico | Shenandoah #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	69,468
Addition to capitalized exploratory well cost pending determination of proved reserves	200	(53)
End of period	69,668	69,468
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	69,668	69,468
U.S. Gulf of Mexico | Shenandoah #2 Appraisal Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	12,716
U.S. Gulf of Mexico | Shenandoah #2 Replacement Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	18,271
End of period	18,272
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	18,272
U.S. Gulf of Mexico | Heidelberg #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	20,240
Addition to capitalized exploratory well cost pending determination of proved reserves	(419)
End of period	19,822
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	19,822
U.S. Gulf of Mexico | Heidelberg #2 Appraisal Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves		5,999
U.S. Gulf of Mexico | Heidelberg #3 Appraisal Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	4,056
Addition to capitalized exploratory well cost pending determination of proved reserves	8,628	4,056
End of period	12,683	4,056
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	12,683	4,056
U.S. Gulf of Mexico | Heidelberg #3 Appraisal Well Side Track
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	4,108
U.S. Gulf of Mexico | Heidelberg Early Development
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	5,941
End of period	5,941
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	5,941
U.S. Gulf of Mexico | Ligurian #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
End of period		8,100
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs		8,100
U.S. Gulf of Mexico | Ligurian #2 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	2,034
Addition to capitalized exploratory well cost pending determination of proved reserves	46,961	2,034
End of period		2,034
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs		2,034
U.S. Gulf of Mexico | Criollo #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves		(822)
U.S. Gulf of Mexico | North Platte #1 Exploratory Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	72,559
End of period	72,559
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	72,559
U.S. Gulf of Mexico | North Platte #1 By Pass Core
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	7,229
End of period	7,229
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	7,229
U.S. Gulf of Mexico | North Platte Early Development
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	2,042
Amounts charged to expense	(2,042)
End of period	2,042
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	2,042
U.S. Gulf of Mexico | Other Pre-Spud Costs
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	59
End of period	59
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	59
West Africa
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Total number of exploratory wells initially scheduled to be drilled offshore Angola	2
West Africa | Bicuar #1 Exploratory Well costs
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	3,035
Addition to capitalized exploratory well cost pending determination of proved reserves	(3,035)	25,444
End of period		3,035
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs		3,035
West Africa | Cameia #1 Exploratory Well costs
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Beginning of period	71,405
Addition to capitalized exploratory well cost pending determination of proved reserves	33,958	71,405
End of period	105,363	71,405
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	105,363	71,405
West Africa | Cameia #2 Appraisal Well
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	133,328
End of period	133,328
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	133,328
West Africa | Cameia Early Development
Net changes in capitalized exploratory well costs (excluding any related leasehold costs)
Addition to capitalized exploratory well cost pending determination of proved reserves	4,058
End of period	4,058
Cumulative costs of capitalized exploratory well costs (excluding any related leasehold costs)
Cumulative costs	$ 4,058

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Organization and Operations (Details) (USD $)	1 Months Ended		12 Months Ended
	Jan. 31, 2010	Dec. 31, 2009	Dec. 31, 2012 Segment
Organization and Operations
Number of shares issued in exchange for Partnership interests		283,200,000
Number of shares issued in public offerings and pursuant to overallotment option	7,978,000	63,000,000
Common stock issued in a private placement (in shares)		3,125,000
Issuance price of shares issued in public offerings and pursuant to overallotment option (in dollars per share)	$ 13.50	$ 13.50
Number of geographic segments			2
Organization and Operations
Sale of additional shares of common stock at the closing of the over-allotment portion of initial public offering	7,978,000	63,000,000

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Joint Interests and Other Receivables (Tables)

12 Months Ended

Dec. 31, 2012

Joint Interests and Other Receivables

Schedule of joint interest and other receivables

	December 31,
	2012		2011
	(in thousands)
Partners in the U.S. Gulf of Mexico	$	52,439	$	12,377
Partners in West Africa		2,185		34,311
Accrued interest on investment securities		3,647		7,094
Vendor's receivable		1,526		1,502
Other		1,795		1,699
	$	61,592	$	56,983

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Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended			86 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012
Property acquisition
Unproved	$ 19,961	$ 337,126	$ 1,746
Exploration
Capitalized	272,685	108,062	34,596
Expensed	61,583	32,239	45,030	390,173
Total Costs Incurred	354,229	477,427	81,372
U.S. Gulf of Mexico
Property acquisition
Unproved	19,961		1,746
Exploration
Capitalized	104,376	11,213	34,596
Expensed	32,874	10,707	15,984
Total Costs Incurred	157,211	21,920	52,326
West Africa
Property acquisition
Unproved		337,126
Exploration
Capitalized	168,309	96,849
Expensed	28,709	21,532	29,046
Total Costs Incurred	$ 197,018	$ 455,507	$ 29,046

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Long-term Debt (Details) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	0 Months Ended	12 Months Ended
	Dec. 17, 2012	Dec. 31, 2012
Debt instrument
Interest rate (as a percent)		2.625%
Carrying amounts of the liability components
Carrying amount of the liability components		$ 991,191,000
Notes
Debt instrument
Aggregate principal amount of notes issued	1,380,000,000
Interest rate (as a percent)	2.625%	2.625%
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
Principal amount used for repurchase of debt instrument	1,000
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 debt discount (as a percent)	8.01%
Effective interest rate used to amortize liability component of debt issue costs (as a percent)	8.40%
Debt issue cost	32,200,000	23,000,000
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
Carrying amounts of the liability components
Principal Amount		1,380,000,000
Unamortized discount		(388,809,000)
Carrying amount of the liability components		991,191,000
Remaining term of debt		7 years
Carrying amounts of the equity components
Debt discount relating to value of conversion option		390,540,000
Debt issue costs	(9,100,000)	(9,124,000)
Carrying amount of the equity components		381,416,000
Fair value of the notes excluding conversion feature		$ 989,500,000

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Selected Quarterly Financial Data-Unaudited (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended				86 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2012
Selected Quarterly Financial Data Unaudited
Operating costs and expenses	$ 64,405	$ 40,553	$ 142,155	$ 37,715	$ 52,303	$ 48,242	$ 20,536	$ 16,755	$ 284,828	$ 137,836	$ 138,058		$ 939,599
Operating income (loss)	(64,405)	(40,553)	(142,155)	(37,715)	(52,303)	(48,242)	(20,536)	(16,755)	(284,828)	(137,836)	(138,058)		(939,599)
Net income (loss)	$ (66,531)	$ (39,214)	$ (140,723)	$ (36,531)	$ (51,114)	$ (46,987)	$ (19,478)	$ (16,058)	$ (282,999)	$ (133,637)	$ (136,476)	$ (81,257)	$ (927,835)
Basic and diluted income (loss) per common share (in dollars per share)	$ (0.16)	$ (0.10)	$ (0.35)	$ (0.09)	$ (0.13)	$ (0.12)	$ (0.05)	$ (0.05)	$ (0.70)	$ (0.35)	$ (0.39)

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Commitments

12 Months Ended

Dec. 31, 2012

Commitments

Commitments

18. Commitments

        The following table summarizes by period the payments due for our estimated commitments, excluding long-term debt, as of December 31, 2012:

	Payments Due By Year
	2013		2014		2015		2016		2017		Thereafter
	($ in thousands)
Drilling Rig and Related Contracts	$	594,374	$	342,321	$	154,920	$	60,025	$	—	$	—
Operating Leases		11,200		9,860		9,515		6,063		3,571		10,402
Lease Rentals(1)		6,413		5,736		5,502		3,610		3,157		1,071
Social Payment Obligations(2)		49,019		51,101		48,569		62,854		5,714		—
Total	$	661,006	$	409,018	$	218,506	$	132,552	$	12,442	$	11,473

(1)

Relates to the annual delay rental payments payable to the Office of Natural Resources Revenue within the U.S. Department of the Interior with respect to the Company's U.S. Gulf of Mexico leases. These annual payments are required to maintain the leases from year to year.

(2)

Includes the Company's contractual payment obligations for social projects such as the Sonangol Research and Technology Center and academic scholarships for Angolan students that the Company was and is contractually obligated to pay in consideration for the Angolan government granting it the licenses to explore for and develop hydrocarbons offshore Angola. Pursuant to the terms of the Risk Services Agreements for Blocks 9 and 21 and the Production Sharing Agreement for Block 20, the Company is not required to pay annual rental payments to maintain the licenses from year to year.

        The Company recorded $12.1 million, $7.7 million and $6.9 million of office and delay rental expense for years ended December 31, 2012, 2011 and 2010, respectively, and a cumulative of $42.4 million for the period November 10, 2005 (Inception) through December 31, 2012.

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Joint Interests and Other Receivables (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Joint Interests Receivables
Accrued interest on investment securities	$ 3,647	$ 7,094
Vendor's receivable	1,526	1,502
Other	1,795	1,699
Total joint interest and other receivables	61,592	56,983
Partners in the U.S. Gulf of Mexico
Joint Interests Receivables
Receivable attributable to joint interest partners	52,439	12,377
Partners in West Africa
Joint Interests Receivables
Receivable attributable to joint interest partners	$ 2,185	$ 34,311

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Commitments (Tables)

12 Months Ended

Dec. 31, 2012

Commitments

Schedule of payments due for the estimated commitments, excluding long-term debt

	Payments Due By Year
	2013		2014		2015		2016		2017		Thereafter
	($ in thousands)
Drilling Rig and Related Contracts	$	594,374	$	342,321	$	154,920	$	60,025	$	—	$	—
Operating Leases		11,200		9,860		9,515		6,063		3,571		10,402
Lease Rentals(1)		6,413		5,736		5,502		3,610		3,157		1,071
Social Payment Obligations(2)		49,019		51,101		48,569		62,854		5,714		—
Total	$	661,006	$	409,018	$	218,506	$	132,552	$	12,442	$	11,473

(1)

Relates to the annual delay rental payments payable to the Office of Natural Resources Revenue within the U.S. Department of the Interior with respect to the Company's U.S. Gulf of Mexico leases. These annual payments are required to maintain the leases from year to year.

(2)

Includes the Company's contractual payment obligations for social projects such as the Sonangol Research and Technology Center and academic scholarships for Angolan students that the Company was and is contractually obligated to pay in consideration for the Angolan government granting it the licenses to explore for and develop hydrocarbons offshore Angola. Pursuant to the terms of the Risk Services Agreements for Blocks 9 and 21 and the Production Sharing Agreement for Block 20, the Company is not required to pay annual rental payments to maintain the licenses from year to year.

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Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Long-term Debt

Schedule of the carrying amounts of the liability components of the Notes

	December 31,
	2012							2011
	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	$	(388,809	)	$	991,191	$	—	$	—	$	—

(1)

Unamortized discount will be amortized over the remaining life of the Notes which is 7 years.

Schedule of carrying amounts of the equity components of the Notes

	December 31,
	2012			2011
Carrying amount of equity component of 2.625% convertible senior notes
Debt discount relating to value of conversion option	$	390,540		$	—
Debt issue costs		(9,124	)		—
Total	$	381,416		$	—

Schedule of interest expense, excluding amortization of debt issue costs

							For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Interest expense associate with accrued interest	$	1,409	$	—	$	—	$	1,409
Interest expense associated with accretion of debt discount		1,731		—		—		1,731
Total	$	3,140	$	—	$	—	$	3,140

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Investments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Investments
Fair market value	$ 1,564,441	$ 1,411,445
Held-to-maturities, Amortized Cost
Within 1 year	1,528,174	1,364,213
After 1 year	36,267	47,232
Total	1,564,441	1,411,445
Held-to-maturity securities, Estimated fair value
Within 1 year	1,528,174	1,364,213
After 1 year	36,267	47,232
Total	1,564,441	1,411,445
Cash and cash equivalents
Investments
Fair market value	254,732	184,749
Short-term investments
Investments
Fair market value	789,668	858,293
Short-term restricted funds
Investments
Fair market value	90,440	53,322
Long-term restricted funds
Investments
Fair market value	393,334	267,849
Long-term investments
Investments
Fair market value	36,267	47,232
U.S. Treasury securities
Investments
Fair market value	483,775	379,618
Corporate securities
Investments
Fair market value	510,691	535,846
Commercial paper
Investments
Fair market value	562,975	369,432
U.S. government agency securities
Investments
Fair market value		71,856
Municipal bonds
Investments
Fair market value		42,193
Certificates of deposit
Investments
Fair market value	$ 7,000	$ 12,500

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Income Taxes (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company's income tax expense (benefit)
Income tax expense (benefit) at the federal statutory rate	$ (99,050,000)	$ (46,773,000)	$ (47,767,000)
State income taxes, net of federal income tax benefit	(512,000)	(2,579,000)	(339,000)
Foreign NOL and deferred adjustments	4,447,000	(30,407,000)
Deferred income taxes established at date of corporate reorganization			(8,735,000)
Other	2,678,000	117,000	176,000
Valuation allowance	92,437,000	79,642,000	56,665,000
Reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company's income tax expense (benefit)
Income tax expense (benefit) at the federal statutory rate (as a percent)	35.00%	35.00%	35.00%
State income taxes, net of federal income tax benefit (as a percent)	0.20%	1.90%	0.30%
Foreign NOL (as a percent)	(1.60%)	22.80%
Deferred income taxes established at date of corporate reorganization (as a percent)			6.30%
Other (as a percent)	(0.90%)	0.10%	0.10%
Valuation allowance (as a percent)	(32.70%)	59.60%	41.50%
Deferred income tax attributable to true-up adjustment of affiliate company acquired			8,700,000
Tax benefits associated with equity based compensation	$ 2,700,000

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Seismic and Exploration Expenses (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended			86 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012
Seismic and Exploration Expenses
Seismic costs	$ 42,447	$ 20,443	$ 39,748	$ 342,048
Seismic cost recovery			(15,126)	(25,126)
Leasehold delay rentals	6,383	6,075	5,989	32,903
Force Majeure expense			13,549	13,549
Drilling rig expense	12,753	5,721	870	26,799
Total seismic and exploration expenses	$ 61,583	$ 32,239	$ 45,030	$ 390,173

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2012
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
Joint Interests and Other Receivables
Settlement period of receivables, maximum	30 days

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

2. Summary of Significant Accounting Policies

Basis of Presentation

        The accompanying 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 relating to "Development Stage Entities."

        At December 31, 2012, the accompanying consolidated financial statements include the accounts of Cobalt and its wholly owned subsidiary, Cobalt International Energy, L.P. ("Partnership"). Prior to the effective date of the corporate reorganization, both entities were under common control arising from common direct or indirect ownership of each. The transfer of the Partnership interests to Cobalt represented a reorganization of entities under common control and was accounted for at historical cost. See Note 1.

Reclassifications

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

Use of Estimates

        The preparation of financial statements in conformity with United States generally accepted accounting principles ("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 the Company makes include (a) accruals related to expenses, (b) assumptions used in estimating fair value of equity based awards and the fair value of the liability component of the convertible senior notes and (c) assumptions used in impairment testing. Although the Company believes these estimates are reasonable, actual results could differ from these estimates.

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.

Revenue Recognition

        The Company will follow the "sales" (or cash) method of accounting for oil and gas revenues. Under this method, the Company will recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which the Company is entitled based on its ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. For the years ended December 31, 2012, 2011, 2010 and for the period November 10, 2005 (Inception) through December 31, 2012, no revenues have been recognized in these consolidated financial statements.

Cash and Cash Equivalents

        Cash and cash equivalents consist of demand deposits and funds invested in highly liquid instruments with maturities of three months or less from the date of purchase. Demand deposits typically exceed federally insured limits; however, the Company periodically assesses the financial condition of the institutions where these funds are held as well as the credit ratings of the issuers of the highly liquid instruments and believes that the credit risk is minimal.

Restricted Funds

        Restricted funds primarily consists of funds held in escrow accounts and collateral for letters of credit relating to our operations in the U.S. Gulf of Mexico and offshore Angola.

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 cost 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 and approximate fair market value as of December 31, 2012 and 2011. Income related to these securities is reported as a component of interest income in the Company's consolidated statements of operations. See Note 7—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. For the years ended December 31, 2012, 2011, 2010 and for the period November 10, 2005 (Inception) through December 31, 2012, the Company has not incurred OTTI of its debt securities.

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 receivables are usually settled within 30 days of the invoice date.

Property, Plant, and Equipment

        The Company uses the "successful efforts" method of accounting for its oil and gas properties. Acquisition costs for unproved leasehold properties and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the areas as a result of drilling those wells. Under the successful efforts method of accounting, proved leasehold costs are capitalized and amortized over the proved developed and undeveloped reserves on a units-of-production basis. Successful drilling costs and developmental dry holes are capitalized and amortized over the proved developed reserves on a units-of-production basis. Significant unproved leasehold costs are capitalized and are not amortized, pending an evaluation of their exploration potential. Unproved leasehold costs are assessed periodically to determine if an impairment of the cost of individual properties has occurred. Factors taken into account for impairment analysis include results of the technical studies conducted, lease terms and management's future exploration plans. The cost of impairment is charged to expense in the period in which it occurs. Costs incurred for exploratory dry holes, geological and geophysical work (including the cost of seismic data), and delay rentals are charged to expense as incurred. Costs of other property and equipment are depreciated on a straight-line based on their respective useful lives.

Asset Retirement Obligations

        The Company currently does not have any oil and natural gas production or any legal obligations to incur decommissioning in costs. Should such production occur in the future, the Company expects to have significant obligations under its lease agreements and federal regulation to remove its equipment and restore land or seabed at the end of oil and natural gas production operations. These asset retirement obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and natural gas platforms. Estimating the future restoration and removal cost is difficult and requires the Company to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulation often have vague descriptions of what constitutes removal. Asset removal technologies and cost are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Pursuant to the accounting guidance relating to "Assets Retirement Obligations." The Company is required to record a separate liability for the estimated fair value of its asset retirement obligations, with an offsetting increase to the related oil and natural gas properties representing asset retirement costs on its balance sheet. The cost of the related oil and natural gas asset, including the asset retirement cost, is depreciated over the useful life of the asset. The estimated fair value of asset retirement obligations is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

        Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, the Company will make corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. Increases in the discounted abandonment liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the consolidated statements of operations.

Inventory

        Inventories consist of various tubular products that are used in the Company's drilling programs. The products are stated at the average cost. Cost is determined using a weighted average method comprised of purchase price and other directly attributable costs.

Income Taxes

        The Company applied the liability method of accounting for income taxes in accordance with accounting guidance related to "Income Taxes" as clarified by "Accounting for Uncertainty in Income Taxes." Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Since the Company is in development stage and there can be no assurance that the Company will generate any earnings or any specific level of earnings in future years, the Company has established a valuation allowance that equals its net deferred tax assets. See Note 17.

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, on a straight-line basis 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. See Note 15.

Earnings (Loss) Per Share

        Basic earnings (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. Diluted earnings (loss) per share incorporate the potential dilutive impact of options and unvested stock outstanding during the periods presented, unless their effect is anti-dilutive. In addition, the Company applies the if-converted method to our convertible debt instruments, the effect of which is that conversion will not be assumed for purposes of computing diluted earnings (loss) per share if the effect would be anti-dilutive.

Operating Costs and Expenses

        Expenses consist primarily of the costs of acquiring and processing of geological and geophysical data, exploration and appraisal drilling expenses, consultants, telecommunications, payroll and benefit costs, information system and legal costs, office rent, contract costs, and bookkeeping and audit fees.

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Equity Based Compensation (Details) (USD $)	12 Months Ended			86 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012
Weighted Average Grant Date Fair Value Per Share
Equity based compensation	$ 22,410,000	$ 15,505,000	$ 12,672,000	$ 60,707,000
Incentive Plan
Equity based Compensation
Shares available for grant under the plan	9,000,000			9,000,000
NED Plan
Equity based Compensation
Shares available for grant under the plan	555,294			555,294
Restricted Stock
Restricted stock activity
Non-vested shares at beginning of the period	4,599,783	5,570,895	8,015,041
Granted (in shares)	487,710	214,792	442,156
Vested (in shares)	(738,628)	(1,185,904)	(2,213,277)
Forfeited or expired (in shares)	(308,040)		(673,025)
Non-vested shares at end of the period	4,040,825	4,599,783	5,570,895	4,040,825
Weighted Average Grant Date Fair Value Per Share
Non-vested shares at beginning of the period (in dollars per share)	$ 11.27	$ 9.77	$ 7.67
Granted (in dollars per share)	$ 26.01	$ 8.54	$ 9.96
Vested (in dollars per share)	$ 13.05	$ 3.75	$ 0.51
Forfeited or expired (in dollars per share)	$ 12.17		$ 15.35
Non-vested shares at end of the period (in dollars per share)	$ 13.05	$ 11.27	$ 9.77	$ 13.05
Weighted-average period remaining	1 year 10 months 13 days	2 years 6 months	3 years 3 months 18 days
Unrecognized compensation	23,827,000	29,559,000	41,599,000	23,827,000
Restricted Stock | Former employee
Restricted stock activity
Vested (in shares)			(45,000)
Weighted Average Grant Date Fair Value Per Share
Non-vested restricted shares forfeited pursuant to the terms of the separation agreement			585,778
Equity based compensation			500,000
Reduction to the stock compensation expense for the forfeited shares			$ 2,400,000
Restricted Stock | Non-employee directors
Weighted Average Grant Date Fair Value Per Share
Awards granted (in shares)	33,204
Retainer awards | Non-employee directors | Common Stock
Weighted Average Grant Date Fair Value Per Share
Awards granted (in shares)	12,221	23,595
Restricted stock units (performance-based)
Restricted stock activity
Non-vested shares at beginning of the period	198,838,000	198,838	198,838
Vested (in shares)	(74,537,000)
Forfeited or expired (in shares)	(15,026,000)
Non-vested shares at end of the period	109,275,000	198,838,000	198,838	109,275,000
Weighted Average Grant Date Fair Value Per Share
Non-vested shares at beginning of the period (in dollars per share)	$ 12.45	$ 12.45	$ 12.45
Vested (in dollars per share)	$ 30.50
Forfeited or expired (in dollars per share)	$ 30.50
Non-vested shares at end of the period (in dollars per share)	$ 30.50	$ 12.45	$ 12.45	$ 30.50
Weighted-average period remaining	1 year	2 years	3 years
Weighted average fair value of shares at grant date (in dollars per share)	$ 12.45
Restricted stock units (performance-based) | Non-employee directors
Weighted Average Grant Date Fair Value Per Share
Awards granted (in shares)	137,945
Awards granted as on period end (in shares)	137,495			137,495
Weighted average fair value of shares at grant date (in dollars per share)	$ 21.35

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Segment Information

Schedule of segment information by geographic operating segment

	U.S. Gulf of Mexico			West Africa			Total
	($ in thousands)
Year ended December 31, 2012
Operating costs and expense	$	231,196		$	53,632		$	284,828
Interest (income) expense		(1,824	)		(5	)		(1,829	)
Net income (loss)	$	(229,372	)	$	(53,627	)	$	(282,999	)
Additions to Property and Equipment, net(1)	$	67,068		$	169,362		$	236,430
Year ended December 31, 2011
Operating costs and expense	$	80,425		$	57,411		$	137,836
Interest (income) expense		(4,194	)		(5	)		(4,199	)
Net income (loss)	$	(76,231	)	$	(57,406	)	$	(133,637	)
Additions to Property and Equipment, net(1)	$	(12,324	)	$	411,882		$	399,558
Year ended December 31, 2010
Operating costs and expense	$	94,619		$	43,439		$	138,058
Interest (income) expense		(1,582	)		—			(1,582	)
Net income (loss)	$	(93,037	)	$	(43,439	)	$	(136,476	)
Additions to Property and Equipment, net(1)	$	(7,844	)	$	—		$	(7,844	)

(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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Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

12 Months Ended

Dec. 31, 2012

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

22. Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

        The supplementary oil and gas data that follows is presented in accordance with supplemental disclosure requirements under ASC No. 932, "Extractive Activities—Oil and Gas" and includes (1) capitalized costs, costs incurred and results of operations related to oil and gas producing activities, (2) net proved oil and gas reserves producing activities, (3) net proved oil and gas reserves, and (4) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Since the Company did not have any proved reserves as of December 31, 2012 and 2011, there will be no disclosures on (2), (3) and (4) above.

Capitalized Costs Related to Oil and Gas Activities

	U.S. Gulf of Mexico			West Africa		Total
	($ in thousands)
As of December 31, 2012
Unproved properties(1)	$	572,257		$	600,620	$	1,172,877
Accumulated valuation allowance		(78,413	)		—		(78,413	)
		493,844			600,620		1,094,464
Proved properties		—			—		—
Net capitalized costs	$	493,844		$	600,620	$	1,094,464
As of December 31, 2011
Unproved properties	$	447,919		$	432,311	$	880,230
Accumulated valuation allowance		(18,275	)		—		(18,275	)
		429,644			432,311		861,955
Proved properties		—			—		—
Net capitalized costs	$	429,644		$	432,311	$	861,955

(1)

Unproved properties includes capitalized costs net of sale/like-kind exchange of leasehold interests transactions that occurred in 2012 of approximately $0.8 million for U.S. Gulf of Mexico. No gain or loss was recognized for these transactions for the year ended December 31, 2012.

Costs Incurred in Oil and Gas Activities

        The following table reflects total costs incurred, both capitalized and expensed, for oil and gas property acquisition, exploration and development activities.

	U.S. Gulf of Mexico		West Africa		Total
	($ in thousands)
Year ended December 31, 2012
Property acquisition
Unproved	$	19,961	$	—	$	19,961
Proved		—		—		—
Exploration
Capitalized		104,376		168,309		272,685
Expensed		32,874		28,709		61,583
Development		—		—		—
Total Costs Incurred	$	157,211	$	197,018	$	354,229
Year ended December 31, 2011
Property acquisition
Unproved	$	—	$	337,126	$	337,126
Proved		—		—		—
Exploration
Capitalized		11,213		96,849		108,062
Expensed		10,707		21,532		32,239
Development		—		—		—
Total Costs Incurred	$	21,920	$	455,507	$	477,427
Year ended December 31, 2010
Property acquisition
Unproved	$	1,746	$	—	$	1,746
Proved		—		—		—
Exploration
Capitalized		34,596		—		34,596
Expensed		15,984		29,046		45,030
Development		—		—		—
Total Costs Incurred	$	52,326	$	29,046	$	81,372

        The following table reflects the total acreage of the Company's existing oil and gas properties:

	Thousands of Acres
	Developed				Undeveloped
	Gross		Net		Gross		Net
Acreage at December 31, 2012
U.S. Gulf of Mexico		—		—		1,409		696
West Africa		—		—		5,653		1,841
Total		—		—		7,062		2,537
Acreage at December 31, 2011
U.S. Gulf of Mexico		—		—		1,323		644
West Africa		—		—		5,653		1,841
Total		—		—		6,976		2,485

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Selected Quarterly Financial Data-Unaudited

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Data-Unaudited

Selected Quarterly Financial Data-Unaudited

21. Selected Quarterly Financial Data—Unaudited

        Unaudited quarterly financial data for the years ended December 31, 2012 and 2011 are as follows:

	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
	($ in thousands)
Year ended December 31, 2012
Operating costs and expenses	$	37,715		$	142,155		$	40,553		$	64,405
Operating income (loss)		(37,715	)		(142,155	)		(40,553	)		(64,405	)
Net income (loss)		(36,531	)		(140,723	)		(39,214	)		(66,531	)
Basic and diluted income (loss) per common share(1)	$	(0.09	)	$	(0.35	)	$	(0.10	)	$	(0.16	)
Year ended December 31, 2011
Operating costs and expenses	$	16,755		$	20,536		$	48,242		$	52,303
Operating income (loss)		(16,755	)		(20,536	)		(48,242	)		(52,303	)
Net income (loss)		(16,058	)		(19,478	)		(46,987	)		(51,114	)
Basic and diluted income (loss) per common share(1)	$	(0.05	)	$	(0.05	)	$	(0.12	)	$	(0.13	)

(1)

Totals may not add due to rounding.

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Other Assets (Details) (USD $) In Millions, unless otherwise specified			0 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 17, 2012 Notes	Dec. 31, 2012 Notes
Other Assets
Debt issue cost			$ 32.2	$ 23.0
Interest rate (as a percent)	2.625%		2.625%	2.625%
Accumulated cost associated with the Ensco 8503 drilling rig included in other assets		$ 12.1

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Selected Quarterly Financial Data-Unaudited (Tables)

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Data-Unaudited

Schedule of Selected Quarterly Financial Data Unaudited

	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
	($ in thousands)
Year ended December 31, 2012
Operating costs and expenses	$	37,715		$	142,155		$	40,553		$	64,405
Operating income (loss)		(37,715	)		(142,155	)		(40,553	)		(64,405	)
Net income (loss)		(36,531	)		(140,723	)		(39,214	)		(66,531	)
Basic and diluted income (loss) per common share(1)	$	(0.09	)	$	(0.35	)	$	(0.10	)	$	(0.16	)
Year ended December 31, 2011
Operating costs and expenses	$	16,755		$	20,536		$	48,242		$	52,303
Operating income (loss)		(16,755	)		(20,536	)		(48,242	)		(52,303	)
Net income (loss)		(16,058	)		(19,478	)		(46,987	)		(51,114	)
Basic and diluted income (loss) per common share(1)	$	(0.05	)	$	(0.05	)	$	(0.12	)	$	(0.13	)

(1)

Totals may not add due to rounding.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Summary of Significant Accounting Policies

Basis of Presentation

Basis of Presentation

        The accompanying 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 relating to "Development Stage Entities."

        At December 31, 2012, the accompanying consolidated financial statements include the accounts of Cobalt and its wholly owned subsidiary, Cobalt International Energy, L.P. ("Partnership"). Prior to the effective date of the corporate reorganization, both entities were under common control arising from common direct or indirect ownership of each. The transfer of the Partnership interests to Cobalt represented a reorganization of entities under common control and was accounted for at historical cost. See Note 1.

Reclassifications

Reclassifications

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

Use of Estimates

Use of Estimates

        The preparation of financial statements in conformity with United States generally accepted accounting principles ("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 the Company makes include (a) accruals related to expenses, (b) assumptions used in estimating fair value of equity based awards and the fair value of the liability component of the convertible senior notes and (c) assumptions used in impairment testing. Although the Company believes these estimates are reasonable, actual results could differ from these estimates.

Fair Value Measurements

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.

Revenue Recognition

Revenue Recognition

        The Company will follow the "sales" (or cash) method of accounting for oil and gas revenues. Under this method, the Company will recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which the Company is entitled based on its ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. For the years ended December 31, 2012, 2011, 2010 and for the period November 10, 2005 (Inception) through December 31, 2012, no revenues have been recognized in these consolidated financial statements.

Cash and Cash Equivalents

Cash and Cash Equivalents

        Cash and cash equivalents consist of demand deposits and funds invested in highly liquid instruments with maturities of three months or less from the date of purchase. Demand deposits typically exceed federally insured limits; however, the Company periodically assesses the financial condition of the institutions where these funds are held as well as the credit ratings of the issuers of the highly liquid instruments and believes that the credit risk is minimal.

Restricted Funds

Restricted Funds

        Restricted funds primarily consists of funds held in escrow accounts and collateral for letters of credit relating to our operations in the U.S. Gulf of Mexico and offshore Angola.

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 cost 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 and approximate fair market value as of December 31, 2012 and 2011. Income related to these securities is reported as a component of interest income in the Company's consolidated statements of operations. See Note 7—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. For the years ended December 31, 2012, 2011, 2010 and for the period November 10, 2005 (Inception) through December 31, 2012, the Company has not incurred OTTI of its debt securities.

Joint Interest and Other Receivables

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 receivables are usually settled within 30 days of the invoice date.

Property, Plant, and Equipment

Property, Plant, and Equipment

        The Company uses the "successful efforts" method of accounting for its oil and gas properties. Acquisition costs for unproved leasehold properties and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the areas as a result of drilling those wells. Under the successful efforts method of accounting, proved leasehold costs are capitalized and amortized over the proved developed and undeveloped reserves on a units-of-production basis. Successful drilling costs and developmental dry holes are capitalized and amortized over the proved developed reserves on a units-of-production basis. Significant unproved leasehold costs are capitalized and are not amortized, pending an evaluation of their exploration potential. Unproved leasehold costs are assessed periodically to determine if an impairment of the cost of individual properties has occurred. Factors taken into account for impairment analysis include results of the technical studies conducted, lease terms and management's future exploration plans. The cost of impairment is charged to expense in the period in which it occurs. Costs incurred for exploratory dry holes, geological and geophysical work (including the cost of seismic data), and delay rentals are charged to expense as incurred. Costs of other property and equipment are depreciated on a straight-line based on their respective useful lives.

Asset Retirement Obligations

Asset Retirement Obligations

        The Company currently does not have any oil and natural gas production or any legal obligations to incur decommissioning in costs. Should such production occur in the future, the Company expects to have significant obligations under its lease agreements and federal regulation to remove its equipment and restore land or seabed at the end of oil and natural gas production operations. These asset retirement obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and natural gas platforms. Estimating the future restoration and removal cost is difficult and requires the Company to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulation often have vague descriptions of what constitutes removal. Asset removal technologies and cost are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Pursuant to the accounting guidance relating to "Assets Retirement Obligations." The Company is required to record a separate liability for the estimated fair value of its asset retirement obligations, with an offsetting increase to the related oil and natural gas properties representing asset retirement costs on its balance sheet. The cost of the related oil and natural gas asset, including the asset retirement cost, is depreciated over the useful life of the asset. The estimated fair value of asset retirement obligations is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

        Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, the Company will make corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. Increases in the discounted abandonment liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the consolidated statements of operations.

Inventory

Inventory

        Inventories consist of various tubular products that are used in the Company's drilling programs. The products are stated at the average cost. Cost is determined using a weighted average method comprised of purchase price and other directly attributable costs.

Income Taxes

Income Taxes

        The Company applied the liability method of accounting for income taxes in accordance with accounting guidance related to "Income Taxes" as clarified by "Accounting for Uncertainty in Income Taxes." Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Since the Company is in development stage and there can be no assurance that the Company will generate any earnings or any specific level of earnings in future years, the Company has established a valuation allowance that equals its net deferred tax assets. See Note 17.

Equity-Based Compensation

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, on a straight-line basis 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. See Note 15.

Earnings (loss) Per Share

Earnings (Loss) Per Share

        Basic earnings (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. Diluted earnings (loss) per share incorporate the potential dilutive impact of options and unvested stock outstanding during the periods presented, unless their effect is anti-dilutive. In addition, the Company applies the if-converted method to our convertible debt instruments, the effect of which is that conversion will not be assumed for purposes of computing diluted earnings (loss) per share if the effect would be anti-dilutive.

Operating Costs and Expenses

Operating Costs and Expenses

        Expenses consist primarily of the costs of acquiring and processing of geological and geophysical data, exploration and appraisal drilling expenses, consultants, telecommunications, payroll and benefit costs, information system and legal costs, office rent, contract costs, and bookkeeping and audit fees.

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Cash and Cash Equivalents (Tables)

12 Months Ended

Dec. 31, 2012

Cash and Cash Equivalents

Cash and Cash Equivalents

	December 31,
	2012		2011
	(in thousands)
Cash at banks	$	65,935	$	2,992
Money market funds		1,105,148		104,805
Held-to-maturity securities(1)		254,732		184,749
	$	1,425,815	$	292,546

(1)

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

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Organization and Operations

12 Months Ended

Dec. 31, 2012

Organization and Operations

Organization and Operations

1. Organization and Operations

Organization

        Cobalt International Energy, Inc. (the "Company") was incorporated pursuant to the laws of the State of Delaware in August 2009 to become a holding company for Cobalt International Energy, L.P. (the "Partnership"). The Partnership is a Delaware limited partnership formed on November 10, 2005, by funds affiliated with Goldman, Sachs & Co., Riverstone Holdings LLC and The Carlyle Group as well as members of the Partnership's management team, collectively constituting Class A limited partners. In 2006, funds affiliated with KERN Partners Ltd. and certain limited partners in such funds affiliated with KERN Partners Ltd, were admitted as Class A limited partners. In 2007, First Reserve Corporation and Four Winds Consulting were admitted as Class A limited partners.

        A corporate reorganization occurred concurrently with the completion of the initial public offering ("IPO") on December 21, 2009. All the outstanding interests of the Partnership were exchanged for 283,200,000 shares of the Company's common stock and as a result the Partnership became wholly-owned by the Company. The shares of CIP GP Corp., the general partner of the Partnership were contributed by certain of the Class A limited partners holding such shares to the Company for no consideration. In December 2011, GIP GP Corp. merged into a Delaware limited liability company, Cobalt International Energy, GP LLC. Prior to reorganization, the Company was not subject to federal or state income taxes. Upon completion of the corporate reorganization, the Company became subject to federal and state income taxes.

        On December 21, 2009 the Company closed its IPO with the issuance of 63,000,000 shares of common stock from the public offering and 3,125,000 of shares issued in a private placement at a price of $13.50 per share. On January 7, 2010, the Company closed the sale of an additional 7,978,000 shares of its common stock at the public offering price of $13.50 per share pursuant to the exercise of the over-allotment option by the underwriters of the IPO.

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

Operations

        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 both the U.S. Gulf of Mexico at North Platte, Heidelberg and Shenandoah and offshore Angola at Cameia. The Company's plan is to continue to mature and drill what it believes are its most promising prospects in the deepwater of the U.S. Gulf of Mexico and the deepwater offshore Angola and Gabon as it further appraises, evaluates and progresses its existing discoveries toward potential sanction and development. The Company operates its business in two geographic segments: the U.S. Gulf of Mexico and West Africa.

        As of December 31, 2012, the Company had no proved oil and gas reserves.

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Restricted Funds (Tables)

12 Months Ended

Dec. 31, 2012

Restricted Funds

Schedule of restricted funds

	December 31,
	2012		2011
	(in thousands)
Short-term:
Ocean Confidence escrow account	$	—	$	10,804
Collateral on Letters of Credit for Angola(1)		—		53,322
Ensco 8503 escrow account(2)		90,440		4,883
	$	90,440	$	69,009
Long-term:
Ensco 8503 escrow account(2)	$	90,440	$	181,159
Collateral on Letters of Credit for Angola(1)		304,492		88,358
Other vendor restricted deposits		720		718
	$	395,652	$	270,235

(1)

As of December 31, 2012, $304.5 million was held in a collateral account established for letters of credit issued in support of the Company's contractually agreed work program obligations on Blocks 9, 20 and 21 offshore Angola. The collateral in this account was invested in U.S. Treasury bills and Treasury notes purchased at discounts and at premiums, respectively, resulting in a net carrying value of $302.9 million and in money market funds with total net carrying value of $1.6 million as of December 31, 2012. The contractual maturities of these securities are within one year.

(2)

$180.9 million was held in an escrow account established since December 2009 as a guarantee of performance to Ensco Offshore Company for the Ensco 8503 drilling rig contract. As of December 31, 2012, the Company reclassified $90.4 million from long-term restricted funds to short-term restricted funds as this amount represents 50% reduction of the escrow account upon completion of the first year of the drilling contract from the term commencement date which was January 1, 2012. The Company received the $90.4 million in January 2013. As of December 31, 2012, the short-term and long-term funds in the escrow account were invested in U.S. Treasury bills, purchased at a discount, resulting in a net carrying value of $180.9 million. The contractual maturities of the U.S. Treasury bills are within six months.

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Equity based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Equity based Compensation

Schedule of restricted stock awarded to employees

	Years Ended December 31,
	2012					2011					2010
	Restricted Shares			Weighted Average Grant Date Fair Value Per Share		Restricted Shares			Weighted Average Grant Date Fair Value Per Share		Restricted Shares			Weighted Average Grant Date Fair Value Per Share
Non-vested shares at beginning of year		4,599,783		$	11.27		5,570,895		$	9.77		8,015,041		$	7.67
Granted		487,710		$	26.01		214,792		$	8.54		442,156		$	9.96
Vested		(738,628	)	$	13.05		(1,185,904	)	$	3.75		(2,213,277	)	$	0.51
Forfeited or expired		(308,040	)	$	12.17		—			—		(673,025	)	$	15.35
Non-vested shares at end of year		4,040,825		$	13.05		4,599,783		$	11.27		5,570,895		$	9.77
Weighted-average period remaining		1.87 years					2.5 years					3.3 years
Unrecognized compensation ($ in thousands)	$	23,827				$	29,559				$	41,599

Schedule of assumptions used to determine the fair value of each stock option granted using the Black-Scholes-Merton option-pricing model

	2012
Expected Term in Years		6.50
Expected Volatility		54.92	%
Expected Dividends		0	%
Risk-Free Interest Rate		0.46	%

Schedule of stock options activity

	Shares			Weighted Average Exercise Price		Weighted-Average Remaining Contractual Term (years)		Aggregate Intrinsic Value (thousands)
Outstanding at January 1, 2012		1,133,960		$	12.45		8.9	$	7,688
Granted		457,704		$	30.50		9.1
Exercised		(27,147	)	$	12.45		7.9	$	425
Forfeited or expired		(130,124	)	$	16.24
Outstanding at December 31, 2012		1,434,393		$	17.87		8.29	$	12,158
Vested or expected to vest at December 31, 2012		891,665		$	20.81		8.49	$	5,795
Exercisable at December 31, 2012		505,578		$	12.45		7.92	$	6,123

	Years Ended December 31,
	2012					2011				2010
	Number of shares relating Restricted Stock Units			Weighted Average Grant Date Fair Value Per Unit		Number of shares relating Restricted Stock Units		Weighted Average Grant Date Fair Value Per Unit		Number of shares relating Restricted Stock Units		Weighted Average Grant Date Fair Value Per Unit
Non-vested at December 31, 2011		198,838		$	12.45		198,838	$	12.45		198,838	$	12.45
Granted		—			—		—		—		—		—
Vested		(74,537	)	$	30.50		—		—		—		—
Forfeited or expired		(15,026	)	$	30.50		—		—		—		—
Non-vested at December 31, 2012		109,275		$	30.50		198,838	$	12.45		198,838	$	12.45
Weighted-average period remaining		1 year					2 years				3 years

Schedule of recognized equity-based compensation costs

							For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Restricted stock:
Employees	$	13,378	$	12,860	$	12,064	$	46,594
Non-employee directors		970		804		507		2,281
Stock options:
Employees		3,790		1,841		101		5,732
Restricted stock units (performance-based)		4,272		—		—		4,272
Deferred stock compensation(1)		—		—		—		1,828
	$	22,410	$	15,505	$	12,672	$	60,707

(1)

In December 2008, the Company adopted a deferred compensation plan and provided certain executive officers the opportunity to defer under the Plan all or a portion of their salary and/or annual bonus for 2009. Amounts deferred under the Plan generally are deemed to be invested in a money market account prior to the IPO and shares of the Company's common stock following the IPO. Subject to accelerated payment under specified circumstances, the deferred amounts were distributed to these executives in January 2012 in the form of shares of the Company's common stock. As of December 31, 2012, there were 121,637 shares under the Plan were distributed to these executives.

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Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	$ 1,564,441	$ 1,411,445
Fair Value	1,564,441	1,411,445
Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	2,737,842	1,537,315
Cash and cash equivalents
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	254,732	184,749
Cash and cash equivalents | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	1,425,815	292,546
Cash and cash equivalents | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	65,935	2,992
Cash and cash equivalents | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	1,105,148	104,805
Cash and cash equivalents | Commercial paper | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	247,206	172,249
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 deposit | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		12,500
Short-term restricted funds
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	90,440	53,322
Short-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	90,440	69,009
Short-term restricted funds | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		4,883
Short-term restricted funds | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		10,804
Short-term restricted funds | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	90,440	53,322
Short-term investments
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	789,668	858,293
Short-term investments | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	789,668	858,293
Short-term investments | Commercial paper | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	315,769	197,182
Short-term investments | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	466,898	466,411
Short-term investments | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		112,507
Short-term investments | U.S. government agency securities | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		40,000
Short-term investments | Municipal bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		42,193
Short-term investments | Certificates of deposit | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	7,001
Long-term restricted funds
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	393,334	267,849
Long-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	395,652	270,235
Long-term restricted funds | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		718
Long-term restricted funds | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	2,318	1,668
Long-term restricted funds | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		54,060
Long-term restricted funds | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	178,216	40,597
Long-term restricted funds | U.S. Treasury notes | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	215,118	173,192
Long-term investments
Significant financial instruments as categorized by the fair value measurement hierarchy
Fair Value	36,267	47,232
Long-term investments | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	36,267	47,232
Long-term investments | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total	36,267	15,376
Long-term investments | U.S. government agency securities | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Total		31,856
Level 1 | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	1,173,401	125,870
Fair Value	1,173,401	125,870
Level 1 | Cash and cash equivalents | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	1,171,083	107,797
Fair Value	1,171,083	107,797
Level 1 | Cash and cash equivalents | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	65,935	2,992
Fair Value	65,935	2,992
Level 1 | Cash and cash equivalents | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	1,105,148	104,805
Fair Value	1,105,148	104,805
Level 1 | Short-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		15,687
Fair Value		15,687
Level 1 | Short-term restricted funds | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		4,883
Fair Value		4,883
Level 1 | Short-term restricted funds | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		10,804
Fair Value		10,804
Level 1 | Long-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	2,318	2,386
Fair Value	2,318	2,386
Level 1 | Long-term restricted funds | Cash | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		718
Fair Value		718
Level 1 | Long-term restricted funds | Money market funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	2,318	1,668
Fair Value	2,318	1,668
Level 2 | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	1,564,441	1,411,445
Fair Value	1,564,441	1,411,445
Level 2 | Cash and cash equivalents | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	254,732	184,749
Fair Value	254,732	184,749
Level 2 | Cash and cash equivalents | Commercial paper | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	247,206	172,249
Fair Value	247,206	172,249
Level 2 | Cash and cash equivalents | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	7,526
Fair Value	7,526
Level 2 | Cash and cash equivalents | Certificates of deposit | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		12,500
Fair Value		12,500
Level 2 | Short-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	90,440	53,322
Fair Value	90,440	53,322
Level 2 | Short-term restricted funds | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	90,440	53,322
Fair Value	90,440	53,322
Level 2 | Short-term investments | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	789,668	858,293
Fair Value	789,668	858,293
Level 2 | Short-term investments | Commercial paper | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	315,769	197,182
Fair Value	315,769	197,182
Level 2 | Short-term investments | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	466,898	466,411
Fair Value	466,898	466,411
Level 2 | Short-term investments | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		112,507
Fair Value		112,507
Level 2 | Short-term investments | U.S. government agency securities | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		40,000
Fair Value		40,000
Level 2 | Short-term investments | Municipal bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		42,193
Fair Value		42,193
Level 2 | Short-term investments | Certificates of deposit | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	7,001
Fair Value	7,001
Level 2 | Long-term restricted funds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	393,334	267,849
Fair Value	393,334	267,849
Level 2 | Long-term restricted funds | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		54,060
Fair Value		54,060
Level 2 | Long-term restricted funds | U.S. Treasury bills | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	178,216	40,597
Fair Value	178,216	40,597
Level 2 | Long-term restricted funds | U.S. Treasury notes | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	215,118	173,192
Fair Value	215,118	173,192
Level 2 | Long-term investments | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	36,267	47,232
Fair Value	36,267	47,232
Level 2 | Long-term investments | Corporate bonds | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost	36,267	15,376
Fair Value	36,267	15,376
Level 2 | Long-term investments | U.S. government agency securities | Recurring basis
Significant financial instruments as categorized by the fair value measurement hierarchy
Amortized Cost		31,856
Fair Value		$ 31,856

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Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Capitalized Costs Related to Oil and Gas Activities
Unproved properties	$ 1,172,877,000	$ 880,230,000
Accumulated valuation allowance	(78,413,000)	(18,275,000)
Capitalized costs, gross	1,094,464,000	861,955,000
Net capitalized costs	1,094,464,000	861,955,000
U.S. Gulf of Mexico
Capitalized Costs Related to Oil and Gas Activities
Unproved properties	572,257,000	447,919,000
Accumulated valuation allowance	(78,413,000)	(18,275,000)
Capitalized costs, gross	493,844,000	429,644,000
Net capitalized costs	493,844,000	429,644,000
Proceeds from sale and exchange of leasehold interests transactions	800,000
West Africa
Capitalized Costs Related to Oil and Gas Activities
Unproved properties	600,620,000	432,311,000
Capitalized costs, gross	600,620,000	432,311,000
Net capitalized costs	$ 600,620,000	$ 432,311,000

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 1,425,815	$ 292,546
Joint interest and other receivables	61,592	56,983
Prepaid expenses and other current assets	23,941	22,214
Inventory	65,286	36,049
Short-term restricted funds	90,440	69,009
Short-term investments	789,668	858,293
Total current assets	2,456,742	1,335,094
Property, plant, and equipment:
Oil and gas properties, successful efforts method of accounting, net of accumulated depletion of $0	1,094,464	861,955
Other property and equipment, net of accumulated depreciation and amortization of $4,751 and $3,555, as of December 31, 2012 and 2011, respectively	5,292	1,371
Total property, plant, and equipment, net	1,099,756	863,326
Long-term restricted funds	395,652	270,235
Long-term investments	36,267	47,232
Other assets	23,042	12,057
Total assets	4,011,459	2,527,944
Current liabilities:
Trade and other accounts payable	67,876	71,186
Accrued liabilities	44,061	34,418
Short-term contractual obligations	49,019	132,465
Total current liabilities	160,956	238,069
Long-term debt	991,191
Long-term contractual obligations	168,238	210,961
Other long-term liabilities	1,856
Total long-term liabilities	1,161,285	210,961
Stockholders' equity:
Common stock, $0.01 par value per share; 2,000,000,000 shares authorized; 406,596,884 and 387,531,630 issued and outstanding as of December 31, 2012 and 2011, respectively	4,066	3,875
Additional paid-in capital	3,612,987	2,719,875
Accumulated deficit during the development stage	(927,835)	(644,836)
Total stockholders' equity	2,689,218	2,078,914
Total liabilities and stockholders' equity	$ 4,011,459	$ 2,527,944

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Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

Schedule of Capitalized Costs Related to Oil and Gas Activities

	U.S. Gulf of Mexico			West Africa		Total
	($ in thousands)
As of December 31, 2012
Unproved properties(1)	$	572,257		$	600,620	$	1,172,877
Accumulated valuation allowance		(78,413	)		—		(78,413	)
		493,844			600,620		1,094,464
Proved properties		—			—		—
Net capitalized costs	$	493,844		$	600,620	$	1,094,464
As of December 31, 2011
Unproved properties	$	447,919		$	432,311	$	880,230
Accumulated valuation allowance		(18,275	)		—		(18,275	)
		429,644			432,311		861,955
Proved properties		—			—		—
Net capitalized costs	$	429,644		$	432,311	$	861,955

(1)

Unproved properties includes capitalized costs net of sale/like-kind exchange of leasehold interests transactions that occurred in 2012 of approximately $0.8 million for U.S. Gulf of Mexico. No gain or loss was recognized for these transactions for the year ended December 31, 2012.

Schedule of Costs Incurred in Oil and Gas Activities

	U.S. Gulf of Mexico		West Africa		Total
	($ in thousands)
Year ended December 31, 2012
Property acquisition
Unproved	$	19,961	$	—	$	19,961
Proved		—		—		—
Exploration
Capitalized		104,376		168,309		272,685
Expensed		32,874		28,709		61,583
Development		—		—		—
Total Costs Incurred	$	157,211	$	197,018	$	354,229
Year ended December 31, 2011
Property acquisition
Unproved	$	—	$	337,126	$	337,126
Proved		—		—		—
Exploration
Capitalized		11,213		96,849		108,062
Expensed		10,707		21,532		32,239
Development		—		—		—
Total Costs Incurred	$	21,920	$	455,507	$	477,427
Year ended December 31, 2010
Property acquisition
Unproved	$	1,746	$	—	$	1,746
Proved		—		—		—
Exploration
Capitalized		34,596		—		34,596
Expensed		15,984		29,046		45,030
Development		—		—		—
Total Costs Incurred	$	52,326	$	29,046	$	81,372

Schedule of total acreage of the Company's existing oil and gas properties

	Thousands of Acres
	Developed				Undeveloped
	Gross		Net		Gross		Net
Acreage at December 31, 2012
U.S. Gulf of Mexico		—		—		1,409		696
West Africa		—		—		5,653		1,841
Total		—		—		7,062		2,537
Acreage at December 31, 2011
U.S. Gulf of Mexico		—		—		1,323		644
West Africa		—		—		5,653		1,841
Total		—		—		6,976		2,485

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Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity (Parenthetical)	Dec. 31, 2012
Consolidated Statements of Changes in Partners' Capital and Stockholders' Equity
Interest rate (as a percent)	2.625%

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Contractual Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Contractual obligations
Short-term Contractual Obligations: Social obligation payments	$ 49,019,000	$ 132,465,000
Long-term Contractual Obligations: Social obligation payments	168,238,000	210,961,000
Block 9, offshore Angola
Contractual obligations
Short-term Contractual Obligations: Social obligation payments	150,000	1,300,000
Long-term Contractual Obligations: Social obligation payments	848,000	800,000
Block 21, offshore Angola
Contractual obligations
Short-term Contractual Obligations: Social obligation payments	300,000	2,600,000
Long-term Contractual Obligations: Social obligation payments	1,684,000	1,600,000
Block 20, offshore Angola
Contractual obligations
Short-term Contractual Obligations: Social obligation payments	48,569,000	128,565,000
Long-term Contractual Obligations: Social obligation payments	165,706,000	208,561,000
Payment of short-term contractual obligation	$ 42,900,000

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Measurements

Significant financial instruments as categorized by the fair value measurement hierarchy

	Level 1				Level 2
	Amortized Cost		Fair Value(1)		Amortized Cost		Fair Value(1)		Balance as of December 31, 2012
	($ 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
Certificate 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

	Level 1				Level 2
	Amortized Cost		Fair Value(1)		Amortized Cost		Fair Value(1)		Balance as of December 31, 2011
	($ in Thousands)
Cash and cash equivalents:
Cash	$	2,992	$	2,992	$	—	$	—	$	2,992
Money market funds		104,805		104,805		—		—		104,805
Commercial paper		—		—		172,249		172,249		172,249
Certificate of deposits		—		—		12,500		12,500		12,500
Subtotal		107,797		107,797		184,749		184,749		292,546
Short-term restricted funds:
Cash		4,883		4,883		—		—		4,883
Money market funds		10,804		10,804		—		—		10,804
U.S. Treasury bills		—		—		53,322		53,322		53,322
Subtotal		15,687		15,687		53,322		53,322		69,009
Short-term investments:
U.S. Treasury bills		—		—		112,507		112,507		112,507
U.S. Government agency securities		—		—		40,000		40,000		40,000
Corporate bonds		—		—		466,411		466,411		466,411
Municipal bonds		—		—		42,193		42,193		42,193
Commercial paper		—		—		197,182		197,182		197,182
Subtotal		—		—		858,293		858,293		858,293
Long-term restricted funds:
Cash		718		718		—		—		718
Money market funds		1,668		1,668		—		—		1,668
U.S. Treasury bills		—		—		40,597		40,597		40,597
U.S. Treasury notes		—		—		173,192		173,192		173,192
Corporate bonds		—		—		54,060		54,060		54,060
Subtotal		2,386		2,386		267,849		267,849		270,235
Long-term investments:
U.S. Government agency securities		—		—		31,856		31,856		31,856
Corporate bonds		—		—		15,376		15,376		15,376
Subtotal		—		—		47,232		47,232		47,232
Total	$	125,870	$	125,870	$	1,411,445	$	1,411,445	$	1,537,315

(1)

As of December 31, 2012 and 2011, the Company did not record any OTTI on these assets.

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Employee Benefit Plan (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended				86 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2006	Dec. 31, 2012
Employee Benefit Plan
Minimum period following date of hire after which employees become eligible to participate in the Plan				3 months
Employee contribution match in plan (as a percent)				6.00%
Expenses recorded in benefit contributions to the Plan	$ 0.5	$ 0	$ 0		$ 2.0

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Equity based Compensation

12 Months Ended

Dec. 31, 2012

Equity based Compensation

Equity based Compensation

15. Equity based Compensation

        Overview.    Under the Company's Long Term Incentive Plan (the "Incentive Plan"), the Company may issue stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other stock-based awards to employees. At December 31, 2012, approximately 9.0 million shares remain available for grant under the Incentive Plan.

        On January 28, 2010, the Company adopted the Non-Employee Directors Compensation Plan (the "NED Plan"). Under the NED Plan, the Company may issue options, restricted stock units, other stock-based award or retainers to non-employee directors. At December 31, 2012, 555,294 shares remain available for grant under the NED Plan.

        In accordance with ASC No. 718, Compensation—Stock Compensation, the Company recognizes compensation cost for equity-based compensation to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant, net of estimated forfeitures. If actual forfeitures differ from the Company's estimates, additional adjustments to compensation expense will be required in future periods.

        Restricted Stock.    The Company accounted for the restricted stock based on ASC Topic 718 as described above. 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.

        The following table summarizes the information about the restricted stock awarded to employees for each of the three years in the period ended December 31, 2012:

	Years Ended December 31,
	2012					2011					2010
	Restricted Shares			Weighted Average Grant Date Fair Value Per Share		Restricted Shares			Weighted Average Grant Date Fair Value Per Share		Restricted Shares			Weighted Average Grant Date Fair Value Per Share
Non-vested shares at beginning of year		4,599,783		$	11.27		5,570,895		$	9.77		8,015,041		$	7.67
Granted		487,710		$	26.01		214,792		$	8.54		442,156		$	9.96
Vested		(738,628	)	$	13.05		(1,185,904	)	$	3.75		(2,213,277	)	$	0.51
Forfeited or expired		(308,040	)	$	12.17		—			—		(673,025	)	$	15.35
Non-vested shares at end of year		4,040,825		$	13.05		4,599,783		$	11.27		5,570,895		$	9.77
Weighted-average period remaining		1.87 years					2.5 years					3.3 years
Unrecognized compensation ($ in thousands)	$	23,827				$	29,559				$	41,599

        For the year ended December 31, 2010, 45,000 nonvested restricted shares held by a former officer of the Company were accounted for as vested and 585,778 nonvested restricted shares were forfeited pursuant to the terms of the Separation Agreement between the officer and the Company. The terms of the Separation Agreement were accounted for in accordance with ASC No. 718, Compensation—Stock Compensation and resulted in $0.5 million recognized in stock compensation expense for the vested shares and $2.4 million recognized as a reduction to the stock compensation expense for the forfeited shares during the year ended December 31, 2010.

        A total of 33,204 restricted stock units awards were granted to non-employee directors during the year ended December 31, 2012 for annual retainers. As of December 31, 2012, the Company has granted a cumulative total of 137,945 restricted stock units to non-employee directors. For the year ended December 31, 2012 and 2011, the Company also granted 12,221 and 23,595 shares of common stock as retainer awards to non-employee directors who elected to be compensated by stock in lieu of cash payments. The weighted average fair value of these shares at grant date was $21.35.

        Non-Qualified Stock Options.    The Company grants non-qualified stock options to employees at an exercise price equal to the market value of the Company's common stock on the grant date. The non-qualified stock option awards have contractual terms of 10 years. The options granted in December 2010 vest ratably over a four-year period from date of grant and the options granted in February 2012 cliff vest on December 31, 2014.

        The fair value of each stock option granted is determined using the Black-Scholes-Merton option-pricing model based on several assumptions. These assumptions are based on management's best estimate at the time of grant. The Company used the following the weighted average of each assumption based on the grants in each fiscal year (there were no new stock options granted in 2011):

	2012
Expected Term in Years		6.50
Expected Volatility		54.92	%
Expected Dividends		0	%
Risk-Free Interest Rate		0.46	%

        The Company estimates expected volatility based on an analysis of its stock price since the IPO and comparing the stock price volatility for the period from IPO date through December 31, 2012 with the historical stock price volatility of a similar exploration and production company. The Company estimates the expected term of its option awards based on the vesting period and average remaining contractual term, referred to as the "simplified method". The Company uses this method to provide a reasonable basis for estimating its expected term based on a lack of sufficient historical employee exercise data on stock option awards.

        A summary of the stock options activities for the year ended December 31, 2012 is presented below:

	Shares			Weighted Average Exercise Price		Weighted-Average Remaining Contractual Term (years)		Aggregate Intrinsic Value (thousands)
Outstanding at January 1, 2012		1,133,960		$	12.45		8.9	$	7,688
Granted		457,704		$	30.50		9.1
Exercised		(27,147	)	$	12.45		7.9	$	425
Forfeited or expired		(130,124	)	$	16.24
Outstanding at December 31, 2012		1,434,393		$	17.87		8.29	$	12,158
Vested or expected to vest at December 31, 2012		891,665		$	20.81		8.49	$	5,795
Exercisable at December 31, 2012		505,578		$	12.45		7.92	$	6,123

        The weighted-average grant-date fair value of stock options granted during 2012 and 2011 was $17.92 and $0 per option, respectively, using the Black-Scholes option-pricing model. 27,147 stock options were exercised during the year ended December 31, 2012. As of December 31, 2012, there were 1,434,393 shares of common stock underlying outstanding stock options. As of December 31, 2012, $8.3 million of total unrecognized compensation cost related to stock option is expected to be recognized over a weighted-average period of 1.95 years.

        Restricted Stock Units.    On December 3, 2010, the Company granted 198,838 restricted stock units to employees based on the Restricted Stock Unit (RSU) Award Agreement. Under the RSU Award Agreement the share-based payment is earned based on the number of successful wells drilled during the three year period ending December 31, 2013. The RSU award will vest within a range of 0% to 200% of the number of RSU shares awarded on scheduled vesting dates contingent upon the recipient's continued service at each vesting date and based on the achievement of successful wells drilled as defined in the RSU Award Agreement. In no event shall the recipients vest in an amount greater than 200% of the Award or in aggregate 397,676 RSU shares. The percentage of the RSU awards vested at each of the three year periods ending December 31, 2013 is calculated by the number of successful wells drilled during the respective years multiplied by vesting percentage ranging from 25% to 37.5%. The RSU Award Agreement therefore has multiple implicit service periods which are determined by and when the Company drills a successful well. The fair value of the RSUs at grant date was $12.45 per share. However, on February 24, 2012, the Company amended certain terms and conditions of its RSU award agreement which resulted in the Company using the fair value of $30.50 per share at modification date to recognize the equity based compensation expense for the RSUs that vested during 2012. For the year ended December 31, 2012, the Company recognized $4.3 million of stock compensation for the RSUs based on performance targets achieved from the success of the Cameia #1 and North Platte #1 exploratory well, among other considerations. As of December 31, 2012 and 2011, unrecognized compensation cost related to restricted stock units ranged from approximately $2.0 million to $12.1 million.

        A summary of the restricted stock units activities for the year ended December 31, 2012 is presented below:

	Years Ended December 31,
	2012					2011				2010
	Number of shares relating Restricted Stock Units			Weighted Average Grant Date Fair Value Per Unit		Number of shares relating Restricted Stock Units		Weighted Average Grant Date Fair Value Per Unit		Number of shares relating Restricted Stock Units		Weighted Average Grant Date Fair Value Per Unit
Non-vested at December 31, 2011		198,838		$	12.45		198,838	$	12.45		198,838	$	12.45
Granted		—			—		—		—		—		—
Vested		(74,537	)	$	30.50		—		—		—		—
Forfeited or expired		(15,026	)	$	30.50		—		—		—		—
Non-vested at December 31, 2012		109,275		$	30.50		198,838	$	12.45		198,838	$	12.45
Weighted-average period remaining		1 year					2 years				3 years

        The table below summarizes the equity-based compensation costs recognized for each of the three years in the period ended December 31, 2012, and for the period November 10, 2005 (inception) through December 31, 2012:

							For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Restricted stock:
Employees	$	13,378	$	12,860	$	12,064	$	46,594
Non-employee directors		970		804		507		2,281
Stock options:
Employees		3,790		1,841		101		5,732
Restricted stock units (performance-based)		4,272		—		—		4,272
Deferred stock compensation(1)		—		—		—		1,828
	$	22,410	$	15,505	$	12,672	$	60,707

(1)

In December 2008, the Company adopted a deferred compensation plan and provided certain executive officers the opportunity to defer under the Plan all or a portion of their salary and/or annual bonus for 2009. Amounts deferred under the Plan generally are deemed to be invested in a money market account prior to the IPO and shares of the Company's common stock following the IPO. Subject to accelerated payment under specified circumstances, the deferred amounts were distributed to these executives in January 2012 in the form of shares of the Company's common stock. As of December 31, 2012, there were 121,637 shares under the Plan were distributed to these executives.

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Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant, and Equipment

Schedule of Property, Plant, and Equipment

		December 31,
	Estimated Useful Life (Years)
		2012			2011
		($ in thousands)
Oil and Gas Properties:
Unproved oil and gas properties		$	721,853		$	701,892
Less: accumulated valuation allowance			(78,413	)		(18,275	)
			643,440			683,617
Exploratory wells in process			451,024			178,338
Total oil and gas properties, net			1,094,464			861,955
Other Property and Equipment:
Computer equipment and software	3		3,166			2,847
Office equipment and furniture	3 - 5		2,093			1,114
Vehicles	3		268			129
Leasehold improvements	3 - 10		2,298			836
			7,825			4,926
Less: accumulated depreciation and amortization(1)			(2,533	)		(3,555	)
Total other property and equipment, net			5,292			1,371
Property, plant, and equipment, net		$	1,099,756		$	863,326

(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 therefore had no impact on the consolidated statements of operations and consolidated statements of cash flow.

Schedule of net changes in capitalized exploratory well costs

	December 31, 2012			December 31, 2011
	($ in thousands)
Beginning of period	$	178,338		$	106,881
Addition to capitalized exploratory well cost pending determination of proved reserves
U.S. Gulf of Mexico:
Shenandoah #1 Exploratory Well		200			(53	)
Shenandoah #2 Appraisal Well		12,716			—
Shenandoah #2 Replacement Well		18,271			—
Heidelberg #1 Exploratory Well		(419	)		—
Heidelberg #2 Appraisal Well		—			5,999
Heidelberg #3 Appraisal Well		8,628			4,056
Heidelberg #3 Appraisal Well Side Track		4,108			—
Heidelberg Early Development		5,941			—
Ligurian #2 Exploratory Well		46,961			2,034
Criollo #1 Exploratory Well		—			(822	)
North Platte #1 Exploratory Well		72,559			—
North Platte #1 By-Pass Core		7,229			—
North Platte Early Development		2,042			—
Other Pre-Spud Costs		59			—
West Africa:
Bicuar #1 Exploratory Well pre-spud costs(1)		(3,035	)		25,444
Cameia #1 Exploratory Well		33,958			71,405
Cameia #2 Appraisal Well		133,328			—
Cameia Early Development		4,058			—
Reclassifications to wells, facilities, and equipment based on determination of proved reserves		—			—
Amounts charged to expense(2)		(73,918	)		(36,606	)
End of period	$	451,024		$	178,338

(1)

The amount of $3,035 represents pre-spud mobilization and insurance costs allocated to the Bicuar #1 pre-salt exploratory well planned as one of two exploratory wells initially scheduled to be drilled offshore Angola. With the success of the Cameia #1 exploratory well, the drilling of the Cameia #2 appraisal well was substituted for the Bicuar #1 pre-salt exploratory well. Hence these costs were reallocated to the Cameia #2 appraisal well.

(2)

The amount of $73,918 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 for the year ended December 31, 2012.

Schedule of cumulative costs of capitalized exploratory well costs

	Spud Year		December 31, 2012		December 31, 2011
			($ in thousands)
Cumulative costs:
U.S. Gulf of Mexico
Shenandoah #1 Exploratory Well		2008	$	69,668	$	69,468
Shenandoah #2 Appraisal Well		2012		—		—
Shenandoah #2 Replacement Well		2012		18,272		—
Heidelberg #1 Exploratory Well		2008		19,822		20,240
Heidelberg #3 Appraisal Well		2011		12,683		4,056
Heidelberg Early Development		2012		5,941		—
Ligurian #1 Exploratory Well		2009		—		8,100
Ligurian #2 Exploratory Well		2011		—		2,034
North Platte #1 Exploratory Well		2012		72,559		—
North Platte #1 By Pass Core		2012		7,229		—
North Platte Early Development		2012		2,042		—
Other Pre-Spud Costs		2012		59		—
West Africa:
Bicuar #1 Exploratory Well		2011		—		3,035
Cameia #1 Exploratory Well		2011		105,363		71,405
Cameia #2 Appraisal Well		2012		133,328		—
Cameia Early Development		2012		4,058		—
			$	451,024	$	178,338
Exploratory Well costs capitalized for a period greater than one year after completion of drilling (included in table above)			$	194,853	$	97,861

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Taxes

Income Taxes

17. Income Taxes

        For the years ended December 31, 2012, 2011 and 2010, the Company recorded a net deferred tax asset of $269.6 million, $177.2 million and $97.6 million, respectively with a corresponding full valuation allowance of $269.6 million $177.2 million and $97.6 million, respectively, for the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

        The components of the income tax provision (benefit) are as follows:

	Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Current taxes:
U.S. federal	$	—	$	—	$	—
Foreign		—		—		—
Deferred taxes:
U.S. federal		—		—		—
Foreign		—		—		—
Total	$	—	$	—	$	—

        The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company's income tax expense (benefit) for each of the three years in the period ended December 31, 2012 are as follows:

	Year Ended December 31,
	2012			2011			2010
	($ in thousands)
U.S.:
Net income (loss) as reported	$	(229,372	)	$	(76,231	)	$	(93,037	)
Less: net income (loss) applicable to period before corporate reorganization		—			—			—
Foreign:
Net income (loss) as reported	$	(53,627	)		(57,406	)		(43,439	)
Less: net income (loss) applicable to period before corporate reorganization		—			—			—
Net income (loss) applicable to period after corporate reorganization	$	(282,999	)	$	(133,637	)	$	(136,476	)

	Year Ended December 31,
	2012					2011					2010
	($ in thousands)
Income tax expense (benefit) at the federal statutory rate		(99,050	)	35.0	%	$	(46,773	)	35.0	%	$	(47,767	)	35.0	%
State income taxes, net of federal income tax benefit(1)		(512	)	0.2	%		(2,579	)	1.9	%		(339	)	0.3	%
Foreign NOL and deferred adjustments(2)		4,447		-1.6	%		(30,407	)	22.8	%		—		—
Deferred income taxes established at date of corporate reorganization(3)		—		—			—		—			(8,735	)	6.3	%
Other(4)		2,678		-0.9	%		117		0.1	%		176		0.1	%
Valuation allowance		92,437		-32.7	%		79,642		59.6	%		56,665		41.5	%
	$	—		—		$	—		—		$	—		—

(1)

The 2012 state income tax reflects lower franchise apportionment factor in Louisiana resulting from the dissolution of Cobalt's blocker entities in December 2011.

(2)

Prior to 2011, the Company did not have any registered presence for reporting foreign NOLs.

(3)

The $8.7 million in 2010 relates to an adjustment to include the 2009 NOL of an affiliate company acquired during the 2009 pre-IPO corporate reorganization.

(4)

The $2.7 million relates to the excess tax benefits associated with equity based compensation.

        Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The significant components of the Company's deferred tax assets and liabilities were as follows:

	As of December 31,
	2012			2011
	($ in thousands)
Deferred tax liabilities:
Oil and gas properties	$	23,867		$	4,555
Other		—			452
Total deferred tax liabilities		23,867			5,007
Deferred tax assets:
Seismic and exploration costs		100,414			54,005
Stock-based compensation		12,340			9,329
Domestic NOL carry forwards		158,310			86,599
Foreign NOL carry forwards		20,624			30,407
Other		1,818			1,869
Valuation allowance		(269,639	)		(177,202	)
Total deferred assets, net		23,867			5,007
Net deferred tax assets	$	—		$	—

        The Company has established a full valuation allowance against the deferred tax assets where the Company has determined that it is more likely than not that all of the deferred tax assets will not be realized. Because of the full valuation allowance, no income tax expense or benefit is reflected on the consolidated statement of operations for each of the three years in the period ended December 31, 2012.

        The NOL carryforward for federal and state income tax purposes of approximately $542.2 million and $43.1 million, respectively, and as of December 31, 2012 begins to expire in 2025 and 2024, respectively. The utilization of the NOL carryforwards is dependent upon generating sufficient future taxable income in the appropriate jurisdictions within the carryforward period.

        As of December 31, 2012, we had NOL carryforward for foreign income tax purposes of approximately $39.8 million which begins to expire in 2014. The company has determined that it is more likely than not, that the foreign NOLs will not be fully realized. Therefore, a full valuation allowance was established for these net deferred tax assets.

        There were no unrecognized tax benefits or accrued interest or penalties associated with unrecognized tax benefits as of December 31, 2012 and 2011.

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Income Taxes (Details 3) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Deferred tax liabilities:
Oil and gas properties	$ 23,867,000	$ 4,555,000
Other		452,000
Total deferred liabilities	23,867,000	5,007,000
Deferred tax assets:
Seismic and exploration costs	100,414,000	54,005,000
Stock-based compensation	12,340,000	9,329,000
Domestic NOL carry forwards	158,310,000	86,599,000
Foreign NOL carry forwards	20,624,000	30,407,000
Other	1,818,000	1,869,000
Valuation allowance	(269,639,000)	(177,202,000)	(97,600,000)
Total deferred assets, net	23,867,000	5,007,000
NOL carryforward for foreign income tax purposes begins to expire in 2014	39,800,000
Federal
Income Taxes
Net operating loss carryforwards	542,200,000
State
Income Taxes
Net operating loss carryforwards	$ 43,100,000

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended			86 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012
Cash flows provided from operating activities
Net income (loss)	$ (282,999)	$ (133,637)	$ (136,476)	$ (927,835)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization	1,197	735	787	4,751
Dry hole expense and impairment of unproved properties	134,085	45,732	44,178	238,733
Equity based compensation	22,410	15,505	12,672	60,707
Amortization of premium (accretion of discount)	15,091	22,082	1,608	32,811
Other				558
Changes in operating assets and liabilities:
Joint interest and other receivables	(1,518)	(59,515)	31,266	(60,118)
Inventory	(29,237)	(1,621)	(28,047)	(65,286)
Prepaid expense and other current assets	(1,726)	(13,209)	398	(23,941)
Deferred charges	(10,985)	2,467	(14,524)	(23,042)
Trade and other accounts payable	(3,309)	59,196	(22,977)	67,877
Accrued liabilities and other	16,594	4,470	(22,149)	57,314
Net cash provided by (used in) operating activities	(140,397)	(57,795)	(133,264)	(637,471)
Cash flows from investing activities
Capital expenditures for oil and gas properties	(142,841)		(1,746)	(846,948)
Capital expenditures for other property and equipment	(5,139)	(782)	(1,185)	(10,065)
Exploratory wells drilling in process	(329,534)	(86,979)	(32,585)	(593,905)
Proceeds from sale of oil and gas properties			5,656	339,001
Change in restricted cash	29,573	(541)	(151,527)	(312,087)
Proceeds from maturity of investment securities	1,082,876	1,288,067	224,985	2,597,706
Purchase of investment securities	(1,199,696)	(1,630,156)	(801,970)	(3,633,737)
Net cash provided by (used in) investing activities	(564,761)	(430,391)	(758,372)	(2,460,035)
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			101,256	950,703
Proceeds from public offering, net of costs	489,309	478,203		967,511
Proceeds from debt offering, net of costs	1,348,950			1,348,950
Proceed from exercise of stock options	338			338
Payments for common stock withheld for taxes on equity based compensation	(170)	(191)		(361)
Net cash provided by (used in) financing activities	1,838,427	478,012	101,256	4,523,321
Net increase (decrease) in cash and cash equivalents	1,133,269	(10,174)	(790,380)	1,425,815
Cash and cash equivalents, beginning of period	292,546	302,720	1,093,100
Cash and cash equivalents, end of period	1,425,815	292,546	302,720	1,425,815
Non-Cash Disclosures
Change in accrued capital expenditures	(105,802)	357,900	2,011	17,048
Transfer of investment securities to and from restricted funds	$ 178,830			$ 178,830

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
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)	$ 4,751	$ 3,555
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	406,596,884	387,531,630
Common stock, shares outstanding	406,596,884	387,531,630

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Other Assets

12 Months Ended

Dec. 31, 2012

Other Assets

Other Assets

10. Other Assets

        As of December 31, 2012, the $23.0 million in other assets includes the debt issue costs associated with the issuance of the 2.625% convertible senior notes, as described in Note 11, and which are amortized over the life of the Notes using the effective interest method. As of December 31, 2011, the $12.1 million in other assets includes costs associated with the mobilization and equipment upgrades of the Ensco 8503 drilling rig and subsea containment were amortized over the terms of the drilling rig contract. These costs were fully expensed or capitalized to oil and gas properties as exploratory drilling costs, depending on the drilling results as of December 31, 2012.

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Jun. 30, 2012
Document and Entity Information
Entity Registrant Name	Cobalt International Energy, Inc.
Entity Central Index Key	0001471261
Document Type	10-K
Document Period End Date	Dec. 31, 2012
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 4.3
Entity Common Stock, Shares Outstanding	410,635,097
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY

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Long-term Debt

12 Months Ended

Dec. 31, 2012

Long-term Debt

Long-term Debt

11. 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 will be payable semi-annually in arrears on June 1 and December 1 of each year, beginning on June 1, 2013. The Notes will mature on December 1, 2019, unless earlier repurchased or converted in accordance 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 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 rates used to amortize the debt discount and the liability component of the debt issue costs were approximately 8.01% and 8.40%, respectively, 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:

	December 31,
	2012							2011
	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	$	(388,809	)	$	991,191	$	—	$	—	$	—

(1)

Unamortized discount will be amortized over the remaining life of the Notes which is 7 years.

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

	December 31,
	2012			2011
Carrying amount of equity component of 2.625% convertible senior notes
Debt discount relating to value of conversion option	$	390,540		$	—
Debt issue costs		(9,124	)		—
Total	$	381,416		$	—

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

        Interest expense, excluding amortization of debt issue costs, was as follows:

							For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Interest expense associate with accrued interest	$	1,409	$	—	$	—	$	1,409
Interest expense associated with accretion of debt discount		1,731		—		—		1,731
Total	$	3,140	$	—	$	—	$	3,140

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Consolidated Statements of Operations (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended			86 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012
Operating costs and expenses:
Seismic and exploration	$ 61,583	$ 32,239	$ 45,030	$ 390,173
Dry hole expense and impairment	134,085	45,732	44,178	238,733
General and administrative	87,963	59,130	48,063	305,942
Depreciation and amortization	1,197	735	787	4,751
Total operating costs and expenses	284,828	137,836	138,058	939,599
Operating income (loss)	(284,828)	(137,836)	(138,058)	(939,599)
Other income (expense):
Interest income	5,041	4,199	1,582	15,044
Interest expense	(3,212)			(3,280)
Total other income (expense)	1,829	4,199	1,582	11,764
Net income (loss) before income tax	(282,999)	(133,637)	(136,476)	(927,835)
Net income (loss)	$ (282,999)	$ (133,637)	$ (136,476)	$ (927,835)
Basic and diluted income (loss) per common share (in dollars per share)	$ (0.70)	$ (0.35)	$ (0.39)
Weighted average common shares outstanding (in shares)	403,356,174	376,603,520	349,342,050

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Joint Interests and Other Receivables

12 Months Ended

Dec. 31, 2012

Joint Interests and Other Receivables

Joint Interests and Other Receivables

5. Joint Interests and Other Receivables

        As of December 31, 2012 and 2011, the balance in joint interest and other receivables consisted of the following:

	December 31,
	2012		2011
	(in thousands)
Partners in the U.S. Gulf of Mexico	$	52,439	$	12,377
Partners in West Africa		2,185		34,311
Accrued interest on investment securities		3,647		7,094
Vendor's receivable		1,526		1,502
Other		1,795		1,699
	$	61,592	$	56,983

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Restricted Funds

12 Months Ended

Dec. 31, 2012

Restricted Funds

Restricted Funds

4. Restricted Funds

        Restricted funds consisted of the following:

	December 31,
	2012		2011
	(in thousands)
Short-term:
Ocean Confidence escrow account	$	—	$	10,804
Collateral on Letters of Credit for Angola(1)		—		53,322
Ensco 8503 escrow account(2)		90,440		4,883
	$	90,440	$	69,009
Long-term:
Ensco 8503 escrow account(2)	$	90,440	$	181,159
Collateral on Letters of Credit for Angola(1)		304,492		88,358
Other vendor restricted deposits		720		718
	$	395,652	$	270,235

(1)

As of December 31, 2012, $304.5 million was held in a collateral account established for letters of credit issued in support of the Company's contractually agreed work program obligations on Blocks 9, 20 and 21 offshore Angola. The collateral in this account was invested in U.S. Treasury bills and Treasury notes purchased at discounts and at premiums, respectively, resulting in a net carrying value of $302.9 million and in money market funds with total net carrying value of $1.6 million as of December 31, 2012. The contractual maturities of these securities are within one year.

(2)

$180.9 million was held in an escrow account established since December 2009 as a guarantee of performance to Ensco Offshore Company for the Ensco 8503 drilling rig contract. As of December 31, 2012, the Company reclassified $90.4 million from long-term restricted funds to short-term restricted funds as this amount represents 50% reduction of the escrow account upon completion of the first year of the drilling contract from the term commencement date which was January 1, 2012. The Company received the $90.4 million in January 2013. As of December 31, 2012, the short-term and long-term funds in the escrow account were invested in U.S. Treasury bills, purchased at a discount, resulting in a net carrying value of $180.9 million. The contractual maturities of the U.S. Treasury bills are within six months.

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Employee Benefit Plan

12 Months Ended

Dec. 31, 2012

Employee Benefit Plan

Employee Benefit Plan

16. Employee Benefit Plan

        In 2006, the Company established the Cobalt International Energy, L.P., defined contribution 401(k) plan (the Plan). All employees of the Company after three months of continuous employment are eligible to participate in the Plan. The plan is discretionary and provides a 6% employee contribution match as determined by the Company's Board of Directors. Effective December 31, 2009, the Plan was amended to discontinue the employer's matching contributions. Effective January 1, 2012, the Company reinstituted the 6% employee contribution match. For each of the years ended December 31, 2012, 2011 and 2010, the Company recorded $0.5 million, $0 million and $0 million, respectively, in benefits contributions to the Plan, which are included in the general and administrative expenses. For the period November 10, 2005 (inception) through December 31, 2012, the Company recorded a cumulative of $2.0 million in benefits contributions to the Plan.

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Contractual Obligations

12 Months Ended

Dec. 31, 2012

Contractual Obligations

Contractual Obligations

12. Contractual Obligations

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

	December 31,
	2012		2011
	($ in thousands)
Short-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	150	$	1,300
Social obligation payments for Block 21, offshore Angola		300		2,600
Social obligation and bonus payments for Block 20, offshore Angola(1)(2)		48,569		128,565
	$	49,019	$	132,465
Long-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	848	$	800
Social obligation payments for Block 21, offshore Angola		1,684		1,600
Social obligation and bonus payments for Block 20, offshore Angola(2)		165,706		208,561
	$	168,238	$	210,961

(1)

$42.9 million of this amount was paid in January 2013.

(2)

The total amount of social obligation payments for Block 20 has been capitalized. See Note 9.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Measurements

Fair Value Measurements

8. Fair Value Measurements

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

	Level 1				Level 2
	Amortized Cost		Fair Value(1)		Amortized Cost		Fair Value(1)		Balance as of December 31, 2012
	($ 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
Certificate 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

	Level 1				Level 2
	Amortized Cost		Fair Value(1)		Amortized Cost		Fair Value(1)		Balance as of December 31, 2011
	($ in Thousands)
Cash and cash equivalents:
Cash	$	2,992	$	2,992	$	—	$	—	$	2,992
Money market funds		104,805		104,805		—		—		104,805
Commercial paper		—		—		172,249		172,249		172,249
Certificate of deposits		—		—		12,500		12,500		12,500
Subtotal		107,797		107,797		184,749		184,749		292,546
Short-term restricted funds:
Cash		4,883		4,883		—		—		4,883
Money market funds		10,804		10,804		—		—		10,804
U.S. Treasury bills		—		—		53,322		53,322		53,322
Subtotal		15,687		15,687		53,322		53,322		69,009
Short-term investments:
U.S. Treasury bills		—		—		112,507		112,507		112,507
U.S. Government agency securities		—		—		40,000		40,000		40,000
Corporate bonds		—		—		466,411		466,411		466,411
Municipal bonds		—		—		42,193		42,193		42,193
Commercial paper		—		—		197,182		197,182		197,182
Subtotal		—		—		858,293		858,293		858,293
Long-term restricted funds:
Cash		718		718		—		—		718
Money market funds		1,668		1,668		—		—		1,668
U.S. Treasury bills		—		—		40,597		40,597		40,597
U.S. Treasury notes		—		—		173,192		173,192		173,192
Corporate bonds		—		—		54,060		54,060		54,060
Subtotal		2,386		2,386		267,849		267,849		270,235
Long-term investments:
U.S. Government agency securities		—		—		31,856		31,856		31,856
Corporate bonds		—		—		15,376		15,376		15,376
Subtotal		—		—		47,232		47,232		47,232
Total	$	125,870	$	125,870	$	1,411,445	$	1,411,445	$	1,537,315

(1)

As of December 31, 2012 and 2011, the Company did not record any OTTI on these assets.

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Stockholders' Equity (Details) (USD $)	1 Months Ended						0 Months Ended		1 Months Ended
	Jan. 31, 2010	Dec. 31, 2009	Dec. 31, 2012	Feb. 29, 2012	Dec. 31, 2011	Apr. 15, 2011	Dec. 17, 2012 Notes	Dec. 31, 2012 Notes	Jan. 31, 2012 Deferred Compensation Plan	Dec. 31, 2011 Restricted Stock
Stockholders' Equity
Common stock, shares issued			406,596,884	18,050,000	387,531,630	35,650,000
Common stock, par value (in dollars per share)			$ 0.01	$ 28.00	$ 0.01	$ 14.00
Sale of additional shares of common stock at the closing of the over-allotment portion of initial public offering	7,978,000	63,000,000
Equity based Compensation
Aggregate number of shares withheld to satisfy tax withholding obligations of employees relating to equity based compensation									9,127	13,763
Stock price of shares withheld to satisfy tax withholding obligations of employees relating to equity based compensation (in dollars per share)									$ 18.74	$ 13.85
Aggregate principal amount of notes issued							$ 1,380,000,000
Interest rate (as a percent)			2.625%				2.625%	2.625%
Carrying amount of the equity components								$ 381,416,000

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Prepaid Expenses and Other Current Assets

12 Months Ended

Dec. 31, 2012

Prepaid Expenses and Other Current Assets

Prepaid Expenses and Other Current Assets

6. Prepaid Expenses and Other Current Assets

        Prepaid expenses include the prepaid and unamortized portion of payments made for software licenses, related maintenance fees, and insurance. Other current assets include short-term deposits and current portion of the costs associated with the mobilization and equipment upgrades of the Ensco 8503 drilling rig and subsea containment. As of December 31, 2012 and 2011, prepaid expenses and other current assets were $23.9 million and $22.2 million, respectively.

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Investments

12 Months Ended

Dec. 31, 2012

Investments

Investments

7. Investments

        The Company's investments in held-to-maturity securities which are recorded at amortized cost and approximate fair market value were as follows at December 31, 2012 and 2011:

	December 31,
	2012		2011
	(in thousands)
U.S. Treasury securities	$	483,775	$	379,618
Corporate securities		510,691		535,846
Commercial paper		562,975		369,432
U.S. government agency securities		—		71,856
Municipal bonds		—		42,193
Certificates of deposit		7,000		12,500
Total	$	1,564,441	$	1,411,445

        The Company's held-to-maturity securities were included in the following captions in the Company's balance sheets:

	December 31,
	2012		2011
	(in thousands)
Cash and cash equivalents	$	254,732	$	184,749
Short-term investments		789,668		858,293
Short-term restricted funds		90,440		53,322
Long-term restricted funds		393,334		267,849
Long-term investments		36,267		47,232
	$	1,564,441	$	1,411,445

        The contractual maturities of these held-to-maturity securities at December 31, 2012 and 2011 were as follows:

	December 31,
	2012				2011
	Amortized Cost		Estimated Fair Value		Amortized Cost		Estimated Fair Value
	($ in thousands)
Within 1 year	$	1,528,174	$	1,528,174	$	1,364,213	$	1,364,213
After 1 year		36,267		36,267		47,232		47,232
	$	1,564,441	$	1,564,441	$	1,411,445	$	1,411,445

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Property, Plant, and Equipment

12 Months Ended

Dec. 31, 2012

Property, Plant, and Equipment

Property, Plant, and Equipment

9. Property, Plant, and Equipment

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

		December 31,
	Estimated Useful Life (Years)
		2012			2011
		($ in thousands)
Oil and Gas Properties:
Unproved oil and gas properties		$	721,853		$	701,892
Less: accumulated valuation allowance			(78,413	)		(18,275	)
			643,440			683,617
Exploratory wells in process			451,024			178,338
Total oil and gas properties, net			1,094,464			861,955
Other Property and Equipment:
Computer equipment and software	3		3,166			2,847
Office equipment and furniture	3 - 5		2,093			1,114
Vehicles	3		268			129
Leasehold improvements	3 - 10		2,298			836
			7,825			4,926
Less: accumulated depreciation and amortization(1)			(2,533	)		(3,555	)
Total other property and equipment, net			5,292			1,371
Property, plant, and equipment, net		$	1,099,756		$	863,326

(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 therefore had no impact on the consolidated statements of operations and consolidated statements of cash flow.

        The Company recorded $1.2 million, $0.7 million and $0.8 million of depreciation and amortization expense for the years ended December 31, 2012, 2011 and 2010, respectively, and $4.8 million for the period November 10, 2005 (inception) through December 31, 2012, 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 December 31, 2012, $122.8 million was paid during the first quarter of 2012 and the remaining $214.3 million was accrued in short-term and long-term contractual obligations—see Note 12. In addition to the Block 20 interests, the Company has $10.8 million of unproved property acquisition costs relating to its 40% working interests in Blocks 9 and 21 offshore Angola and its 21.25% working interest in the Diaba block offshore Gabon. As of December 31, 2012, the Company also has $285.6 million of unproved property acquisition costs, net of allowance for impairment, relating to its U.S. Gulf of Mexico properties. The $285.6 million includes $20.0 million of acquisition costs incurred on various working interests in unproved properties located in the U.S. Gulf of Mexico acquired by the Company in 2012. As of December 31, 2012 and 2011, the Company has a net total of $643.4 million and $683.6 million, respectively, of unproved property acquisition costs on the consolidated balance sheets.

        Acquisition costs of unproved leasehold 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. Unproved oil and gas leases for properties in the U.S. Gulf of Mexico with carrying value greater than $1 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 2012 through 2020. As of December 31, 2012 and 2011, the balance for unproved leaseholds that were subject to amortization before impairment provision was $69.1 million and $65.1 million, respectively. The Company recorded lease impairment allowance of $60.2 million, $9.1 million and $9.1 million for years ended December 31, 2012, 2011, 2010, respectively and $78.4 million for the period November 10, 2005 (inception) through December 31, 2012.

Capitalized Exploratory Well 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 location before proceeding with development activities.

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

	December 31, 2012			December 31, 2011
	($ in thousands)
Beginning of period	$	178,338		$	106,881
Addition to capitalized exploratory well cost pending determination of proved reserves
U.S. Gulf of Mexico:
Shenandoah #1 Exploratory Well		200			(53	)
Shenandoah #2 Appraisal Well		12,716			—
Shenandoah #2 Replacement Well		18,271			—
Heidelberg #1 Exploratory Well		(419	)		—
Heidelberg #2 Appraisal Well		—			5,999
Heidelberg #3 Appraisal Well		8,628			4,056
Heidelberg #3 Appraisal Well Side Track		4,108			—
Heidelberg Early Development		5,941			—
Ligurian #2 Exploratory Well		46,961			2,034
Criollo #1 Exploratory Well		—			(822	)
North Platte #1 Exploratory Well		72,559			—
North Platte #1 By-Pass Core		7,229			—
North Platte Early Development		2,042			—
Other Pre-Spud Costs		59			—
West Africa:
Bicuar #1 Exploratory Well pre-spud costs(1)		(3,035	)		25,444
Cameia #1 Exploratory Well		33,958			71,405
Cameia #2 Appraisal Well		133,328			—
Cameia Early Development		4,058			—
Reclassifications to wells, facilities, and equipment based on determination of proved reserves		—			—
Amounts charged to expense(2)		(73,918	)		(36,606	)
End of period	$	451,024		$	178,338

(1)

The amount of $3,035 represents pre-spud mobilization and insurance costs allocated to the Bicuar #1 pre-salt exploratory well planned as one of two exploratory wells initially scheduled to be drilled offshore Angola. With the success of the Cameia #1 exploratory well, the drilling of the Cameia #2 appraisal well was substituted for the Bicuar #1 pre-salt exploratory well. Hence these costs were reallocated to the Cameia #2 appraisal well.

(2)

The amount of $73,918 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 for the year ended December 31, 2012.

	Spud Year		December 31, 2012		December 31, 2011
			($ in thousands)
Cumulative costs:
U.S. Gulf of Mexico
Shenandoah #1 Exploratory Well		2008	$	69,668	$	69,468
Shenandoah #2 Appraisal Well		2012		—		—
Shenandoah #2 Replacement Well		2012		18,272		—
Heidelberg #1 Exploratory Well		2008		19,822		20,240
Heidelberg #3 Appraisal Well		2011		12,683		4,056
Heidelberg Early Development		2012		5,941		—
Ligurian #1 Exploratory Well		2009		—		8,100
Ligurian #2 Exploratory Well		2011		—		2,034
North Platte #1 Exploratory Well		2012		72,559		—
North Platte #1 By Pass Core		2012		7,229		—
North Platte Early Development		2012		2,042		—
Other Pre-Spud Costs		2012		59		—
West Africa:
Bicuar #1 Exploratory Well		2011		—		3,035
Cameia #1 Exploratory Well		2011		105,363		71,405
Cameia #2 Appraisal Well		2012		133,328		—
Cameia Early Development		2012		4,058		—
			$	451,024	$	178,338
Exploratory Well costs capitalized for a period greater than one year after completion of drilling (included in table above)			$	194,853	$	97,861

        As of December 31, 2012, capitalized exploratory well costs that have been suspended longer than one year are associated with the Shenandoah #1, Heidelberg #1 and Cameia #1 projects. These exploratory well costs 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 projects 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 projects, the associated costs will be expensed at that time.

        As of December 31, 2012, no exploratory wells have been drilled by the Company offshore Gabon.

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Equity Based Compensation (Details 3) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended			86 Months Ended			12 Months Ended				86 Months Ended	12 Months Ended	86 Months Ended	0 Months Ended	12 Months Ended						12 Months Ended			86 Months Ended	12 Months Ended			86 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012	Dec. 31, 2012 Deferred stock compensation	Dec. 31, 2012 Executive officers Deferred stock compensation	Dec. 31, 2012 Stock options	Dec. 31, 2012 Stock options Employees	Dec. 31, 2011 Stock options Employees	Dec. 31, 2010 Stock options Employees	Dec. 31, 2012 Stock options Employees	Dec. 31, 2012 Restricted stock units (performance-based)	Dec. 31, 2012 Restricted stock units (performance-based)	Dec. 03, 2010 Restricted stock units (performance-based) Employees	Dec. 31, 2012 Restricted stock units (performance-based) Non-employee directors	Dec. 31, 2012 Restricted stock units (performance-based) Minimum	Dec. 31, 2012 Restricted stock units (performance-based) Maximum	Dec. 31, 2012 Restricted Stock	Dec. 31, 2011 Restricted Stock	Dec. 31, 2010 Restricted Stock	Dec. 31, 2012 Restricted Stock Employees	Dec. 31, 2011 Restricted Stock Employees	Dec. 31, 2010 Restricted Stock Employees	Dec. 31, 2012 Restricted Stock Employees	Dec. 31, 2012 Restricted Stock Non-employee directors	Dec. 31, 2011 Restricted Stock Non-employee directors	Dec. 31, 2010 Restricted Stock Non-employee directors	Dec. 31, 2012 Restricted Stock Non-employee directors	Dec. 31, 2012 Restricted Stock Minimum	Dec. 31, 2011 Restricted Stock Minimum	Dec. 31, 2012 Restricted Stock Maximum	Dec. 31, 2011 Restricted Stock Maximum
Equity based Compensation
Granted during the period (in shares)														198,838	137,945										33,204
Vesting period							4 years					3 years
Vesting percentage																0.00%	200.00%
Shares authorized under the plan												397,676	397,676
Multiplier to determine awards vested (as a percent)																25.00%	37.50%
Closing price of the entity's common stock at the date of grant (in dollars per share)												$ 12.45			$ 21.35
Unrecognized compensation cost							$ 8,300											$ 23,827	$ 29,559	$ 41,599									$ 2,000	$ 2,000	$ 12,100	$ 12,100
Equity-based compensation costs	$ 22,410	$ 15,505	$ 12,672	$ 60,707	$ 1,828			$ 3,790	$ 1,841	$ 101	$ 5,732	$ 4,272	$ 4,272								$ 13,378	$ 12,860	$ 12,064	$ 46,594	$ 970	$ 804	$ 507	$ 2,281
Shares distributed to these executives						121,637

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Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes
Net deferred tax asset	$ 269,600,000	$ 177,200,000	$ 97,600,000
Valuation allowance	(269,639,000)	(177,202,000)	(97,600,000)
U.S.:
Net income (loss) as reported	(229,372,000)	(76,231,000)	(93,037,000)
Foreign:
Net income (loss) as reported	(53,627,000)	(57,406,000)	(43,439,000)
Net income (loss) applicable to period after corporate reorganization	$ (282,999,000)	$ (133,637,000)	$ (136,476,000)

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Equity Based Compensation (Details 2) (Non-Qualified Stock Options, USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Non-Qualified Stock Options
Equity based Compensation
Contractual term for options granted	10 years
Vesting period	4 years
Assumptions used to determine the fair value of each stock option granted using the Black-Scholes-Merton option-pricing model
Expected Term in Years	6 years 6 months
Expected Volatility (as a percent)	54.92%
Expected Dividends (as a percent)	0.00%
Risk-Free Interest Rate (as a percent)	0.46%
Number of Stock Options
Outstanding at the beginning of the period (in shares)	1,133,960
Granted (in shares)	457,704
Exercised (in shares)	(27,147)
Forfeited or expired (in shares)	(130,124)
Outstanding at the end of the period (in shares)	1,434,393	1,133,960
Vested or expected to vest at the end of the period (in shares)	891,665
Exercisable at the end of the period (in shares)	505,578
Weighted Average Exercise Price
Outstanding at the beginning of the period (in dollars per share)	$ 12.45
Granted (in dollars per share)	$ 30.50
Exercised (in dollars per share)	$ 12.45
Forfeited or expired (in dollars per share)	$ 16.24
Outstanding at the end of the period (in dollars per share)	$ 17.87	$ 12.45
Vested or expected to vest at the end of the period (in dollars per share)	$ 20.81
Exercisable at the end of the period (in dollars per share)	$ 12.45
Weighted-Average Remaining Contractual Term (in years)
Outstanding at the beginning of the period	8 years 3 months 14 days	8 years 10 months 24 days
Granted	9 years 1 month 6 days
Exercised	7 years 10 months 24 days
Outstanding at the end of the period	8 years 3 months 14 days	8 years 10 months 24 days
Vested or expected to vest at the end of the period	8 years 5 months 26 days
Exercisable at the end of the period	7 years 11 months 1 day
Weighted-average grant-date fair value of stock options granted (in dollars per share) using the Black-Scholes option-pricing model	$ 17.92	$ 0.00
Unrecognized compensation cost	$ 8,300
Period for recognition of unrecognized compensation cost	1 year 11 months 12 days
Aggregate Intrinsic Value
Outstanding at the beginning of the period	7,688
Exercised	425
Outstanding at the end of the period	12,158	7,688
Vested or expected to vest at the end of the period	5,795
Exercisable at the end of the period	$ 6,123

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Investments (Tables)

12 Months Ended

Dec. 31, 2012

Investments

Schedule of fair value of held-to-maturity securities recorded at amortized cost

	December 31,
	2012		2011
	(in thousands)
U.S. Treasury securities	$	483,775	$	379,618
Corporate securities		510,691		535,846
Commercial paper		562,975		369,432
U.S. government agency securities		—		71,856
Municipal bonds		—		42,193
Certificates of deposit		7,000		12,500
Total	$	1,564,441	$	1,411,445

Schedule of held-to-maturity securities included in the company's balance sheets

	December 31,
	2012		2011
	(in thousands)
Cash and cash equivalents	$	254,732	$	184,749
Short-term investments		789,668		858,293
Short-term restricted funds		90,440		53,322
Long-term restricted funds		393,334		267,849
Long-term investments		36,267		47,232
	$	1,564,441	$	1,411,445

Schedule of contractual maturities of held-to-maturity securities

	December 31,
	2012				2011
	Amortized Cost		Estimated Fair Value		Amortized Cost		Estimated Fair Value
	($ in thousands)
Within 1 year	$	1,528,174	$	1,528,174	$	1,364,213	$	1,364,213
After 1 year		36,267		36,267		47,232		47,232
	$	1,564,441	$	1,564,441	$	1,411,445	$	1,411,445

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Prepaid Expenses and Other Current Assets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets	$ 23,941	$ 22,214

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Seismic and Exploration Expenses

12 Months Ended

Dec. 31, 2012

Seismic and Exploration Expenses

Seismic and Exploration Expenses

14. Seismic and Exploration Expenses

        Seismic and exploration expenses consisted of the following:

								For the Period November 10, 2005 (Inception) through December 31, 2012
	For Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Seismic costs	$	42,447	$	20,443	$	39,748		$	342,048
Seismic cost recovery(1)		—		—		(15,126	)		(25,126	)
Leasehold delay rentals		6,383		6,075		5,989			32,903
Force Majeure expense(2)		—		—		13,549			13,549
Drilling rig expense		12,753		5,721		870			26,799
	$	61,583	$	32,239	$	45,030		$	390,173

(1)

These amounts represent reimbursement from partners of past seismic costs incurred by the Company.

(2)

These amounts represent 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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Segment Information

12 Months Ended

Dec. 31, 2012

Segment Information

Segment Information

19. Segment Information

        As described in Note 1, "Organization and Operations", 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 each of the three years in the period ended December 31, 2012:

	U.S. Gulf of Mexico			West Africa			Total
	($ in thousands)
Year ended December 31, 2012
Operating costs and expense	$	231,196		$	53,632		$	284,828
Interest (income) expense		(1,824	)		(5	)		(1,829	)
Net income (loss)	$	(229,372	)	$	(53,627	)	$	(282,999	)
Additions to Property and Equipment, net(1)	$	67,068		$	169,362		$	236,430
Year ended December 31, 2011
Operating costs and expense	$	80,425		$	57,411		$	137,836
Interest (income) expense		(4,194	)		(5	)		(4,199	)
Net income (loss)	$	(76,231	)	$	(57,406	)	$	(133,637	)
Additions to Property and Equipment, net(1)	$	(12,324	)	$	411,882		$	399,558
Year ended December 31, 2010
Operating costs and expense	$	94,619		$	43,439		$	138,058
Interest (income) expense		(1,582	)		—			(1,582	)
Net income (loss)	$	(93,037	)	$	(43,439	)	$	(136,476	)
Additions to Property and Equipment, net(1)	$	(7,844	)	$	—		$	(7,844	)

(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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Restricted Funds (Details) (USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2009
Restricted Funds
Short-term restricted funds		$ 90,440,000	$ 69,009,000
Long-term restricted funds		395,652,000	270,235,000
Ocean Confidence escrow account
Restricted Funds
Short-term restricted funds			10,804,000
Collateral on letters of credit for Angola
Restricted Funds
Short-term restricted funds			53,322,000
Long-term restricted funds		304,492,000	88,358,000
Collateral held		304,500,000
Maturity period of investments		1 year
Collateral on letters of credit for Angola | U.S. Treasury bills
Restricted Funds
Net carrying value of investments invested through the funds		302,900,000
Collateral on letters of credit for Angola | Money market funds
Restricted Funds
Net carrying value of investments invested through the funds		1,600,000
Ensco 8503 escrow account
Restricted Funds
Short-term restricted funds		90,440,000	4,883,000
Long-term restricted funds		90,440,000	181,159,000	180,900,000
Amount reclassified from long-term restricted cash to short-term restricted cash		90,400,000
Reduction of the escrow account upon completion of the first year of the drilling contract (as a percent)		50.00%
Proceeds from sale of restricted investments	90,400,000
Ensco 8503 escrow account | U.S. Treasury bills
Restricted Funds
Net carrying value of investments invested through the funds		180,900,000
Maturity period of investments		6 months
Other vendor restricted funds
Restricted Funds
Long-term restricted funds		$ 720,000	$ 718,000

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Taxes

Schedule of components of the income tax provision (benefit)

	Year Ended December 31,
	2012		2011		2010
	($ in thousands)
Current taxes:
U.S. federal	$	—	$	—	$	—
Foreign		—		—		—
Deferred taxes:
U.S. federal		—		—		—
Foreign		—		—		—
Total	$	—	$	—	$	—

Schedule of net income pre or post of corporate reorganization

	Year Ended December 31,
	2012			2011			2010
	($ in thousands)
U.S.:
Net income (loss) as reported	$	(229,372	)	$	(76,231	)	$	(93,037	)
Less: net income (loss) applicable to period before corporate reorganization		—			—			—
Foreign:
Net income (loss) as reported	$	(53,627	)		(57,406	)		(43,439	)
Less: net income (loss) applicable to period before corporate reorganization		—			—			—
Net income (loss) applicable to period after corporate reorganization	$	(282,999	)	$	(133,637	)	$	(136,476	)

Schedule of effective income tax reconciliation

	Year Ended December 31,
	2012					2011					2010
	($ in thousands)
Income tax expense (benefit) at the federal statutory rate		(99,050	)	35.0	%	$	(46,773	)	35.0	%	$	(47,767	)	35.0	%
State income taxes, net of federal income tax benefit(1)		(512	)	0.2	%		(2,579	)	1.9	%		(339	)	0.3	%
Foreign NOL and deferred adjustments(2)		4,447		-1.6	%		(30,407	)	22.8	%		—		—
Deferred income taxes established at date of corporate reorganization(3)		—		—			—		—			(8,735	)	6.3	%
Other(4)		2,678		-0.9	%		117		0.1	%		176		0.1	%
Valuation allowance		92,437		-32.7	%		79,642		59.6	%		56,665		41.5	%
	$	—		—		$	—		—		$	—		—

(1)

The 2012 state income tax reflects lower franchise apportionment factor in Louisiana resulting from the dissolution of Cobalt's blocker entities in December 2011.

(2)

Prior to 2011, the Company did not have any registered presence for reporting foreign NOLs.

(3)

The $8.7 million in 2010 relates to an adjustment to include the 2009 NOL of an affiliate company acquired during the 2009 pre-IPO corporate reorganization.

(4)

The $2.7 million relates to the excess tax benefits associated with equity based compensation.

Schedule of Company's deferred tax assets and liabilities

	As of December 31,
	2012			2011
	($ in thousands)
Deferred tax liabilities:
Oil and gas properties	$	23,867		$	4,555
Other		—			452
Total deferred tax liabilities		23,867			5,007
Deferred tax assets:
Seismic and exploration costs		100,414			54,005
Stock-based compensation		12,340			9,329
Domestic NOL carry forwards		158,310			86,599
Foreign NOL carry forwards		20,624			30,407
Other		1,818			1,869
Valuation allowance		(269,639	)		(177,202	)
Total deferred assets, net		23,867			5,007
Net deferred tax assets	$	—		$	—

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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 Dec. 31, 2008	$ 740,471	$ 1,029,572	$ 4,365				$ (293,466)
Class A limited partners' contributions	227,166	227,166
Class B and C limited partners' equity compensation	3,353		2,619	734
Common stock issued upon corporate reorganization		(1,256,738)	(6,984)	(734)	2,743	1,261,713
Equity based compensation	2,402					2,402
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
Net income (loss)	(81,257)						(81,257)
Balance at Dec. 31, 2009	1,741,582				3,405	2,112,900	(374,723)
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 for restricted stock and restricted stock units					22	(22)
Equity based compensation	12,672					12,672
Net income (loss)	(136,476)						(136,476)
Balance at Dec. 31, 2010	1,719,034				3,507	2,226,726	(511,199)
Common stock issued at public offering, net of costs	478,203				357	477,846
Common stock issued for restricted stock and restricted stock units					12	(12)
Equity based compensation	15,505					15,505
Common stock withheld for taxes on equity based compensation	(191)				(1)	(190)
Net income (loss)	(133,637)						(133,637)
Balance at Dec. 31, 2011	2,078,914				3,875	2,719,875	(644,836)
Common stock issued at public offering, net of costs	489,309				181	489,128
Common stock issued for restricted stock and restricted stock units					10	(10)
Equity based compensation	22,410					22,410
Exercise of stock options	338					338
Common stock withheld for taxes on equity based compensation	(170)					(170)
Conversion option relating to 2.625% convertible senior notes, net of allocated costs	381,416					381,416
Net income (loss)	(282,999)						(282,999)
Balance at Dec. 31, 2012	$ 2,689,218				$ 4,066	$ 3,612,987	$ (927,835)

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Cash and Cash Equivalents

12 Months Ended

Dec. 31, 2012

Cash and Cash Equivalents

Cash and Cash Equivalents

3. Cash and Cash Equivalents

        As of December 31, 2012 and 2011, cash and cash equivalents consisted of the following:

	December 31,
	2012		2011
	(in thousands)
Cash at banks	$	65,935	$	2,992
Money market funds		1,105,148		104,805
Held-to-maturity securities(1)		254,732		184,749
	$	1,425,815	$	292,546

(1)

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

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Long-term Debt (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended	86 Months Ended
	Dec. 31, 2012	Dec. 31, 2012
Long-term Debt
Interest expense associate with accrued interest	$ 1,409	$ 1,409
Interest expense associated with accretion of debt discount	1,731	1,731
Total	$ 3,140	$ 3,140

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Commitments (Details) (USD $)	12 Months Ended			86 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012
Contractual obligation and commitments
2013	$ 661,006,000			$ 661,006,000
2014	409,018,000			409,018,000
2015	218,506,000			218,506,000
2016	132,552,000			132,552,000
2017	12,442,000			12,442,000
Thereafter	11,473,000			11,473,000
Office and delay rental expense	12,100,000	7,700,000	6,900,000	42,400,000
Drilling Rig and Related Contracts
Contractual obligation and commitments
2013	594,374,000			594,374,000
2014	342,321,000			342,321,000
2015	154,920,000			154,920,000
2016	60,025,000			60,025,000
Operating Leases
Contractual obligation and commitments
2013	11,200,000			11,200,000
2014	9,860,000			9,860,000
2015	9,515,000			9,515,000
2016	6,063,000			6,063,000
2017	3,571,000			3,571,000
Thereafter	10,402,000			10,402,000
Lease Rentals
Contractual obligation and commitments
2013	6,413,000			6,413,000
2014	5,736,000			5,736,000
2015	5,502,000			5,502,000
2016	3,610,000			3,610,000
2017	3,157,000			3,157,000
Thereafter	1,071,000			1,071,000
Social Payment Obligations
Contractual obligation and commitments
2013	49,019,000			49,019,000
2014	51,101,000			51,101,000
2015	48,569,000			48,569,000
2016	62,854,000			62,854,000
2017	$ 5,714,000			$ 5,714,000

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Contingencies

12 Months Ended

Dec. 31, 2012

Contingencies

Contingencies

20. 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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Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Details 3)	Dec. 31, 2012 acre	Dec. 31, 2011 acre
Total acreage of the Company's existing oil and gas properties:
Undeveloped, gross (in acres)	7,062,000	6,976,000
Undeveloped, net (in acres)	2,537,000	2,485,000
U.S. Gulf of Mexico
Total acreage of the Company's existing oil and gas properties:
Undeveloped, gross (in acres)	1,409,000	1,323,000
Undeveloped, net (in acres)	696,000	644,000
West Africa
Total acreage of the Company's existing oil and gas properties:
Undeveloped, gross (in acres)	5,653,000	5,653,000
Undeveloped, net (in acres)	1,841,000	1,841,000

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Contractual Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Contractual Obligations

Summary of components of short-term and long-term contractual obligations

	December 31,
	2012		2011
	($ in thousands)
Short-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	150	$	1,300
Social obligation payments for Block 21, offshore Angola		300		2,600
Social obligation and bonus payments for Block 20, offshore Angola(1)(2)		48,569		128,565
	$	49,019	$	132,465
Long-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	848	$	800
Social obligation payments for Block 21, offshore Angola		1,684		1,600
Social obligation and bonus payments for Block 20, offshore Angola(2)		165,706		208,561
	$	168,238	$	210,961

(1)

$42.9 million of this amount was paid in January 2013.

(2)

The total amount of social obligation payments for Block 20 has been capitalized. See Note 9.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2012

Stockholders' Equity

Stockholders' Equity

13. Stockholders' Equity

        On April 15, 2011, the Company issued 35,650,000 shares of its common stock at a public offering price of $14.00 per share.

        On December 21, 2011, the Company withheld and cancelled an aggregate amount of 13,763 shares of its common stock, at a price of $13.85 per share, to satisfy tax withholding obligations of certain of our employees that arose upon the lapse of restrictions on restricted stock.

        On January 15, 2012, the Company withheld the issuance of an aggregate amount of 9,127 shares of its common stock, at a price of $18.74 per share, to satisfy tax withholding obligations of certain of its officers that arose upon the distribution of deferred stock compensation.

        On February 29, 2012, the Company issued 18,050,000 shares of common stock at a public offering price of $28.00 per share.

        On December 17, 2012, the Company issued $1.38 billion aggregate principal amount of its 2.625% convertible senior notes due 2019. As of December 31, 2012, $381.4 million was recorded as the equity component of the Notes. See also Note 11—Long-term Debt.