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

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):

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.

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.

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:

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.

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.

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.

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

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.

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

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.

(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.

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."

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."

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."

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

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

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

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.

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.

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

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.

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.

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.

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.

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.

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

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

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.

(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.

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.

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

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."

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."

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.

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,

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."



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."

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

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

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.

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

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.

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.

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

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.

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

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.

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.

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.

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.

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

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.

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

$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."

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:

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.

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.

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.

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

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.

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.

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,

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.

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.

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.

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.

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.

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.

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,

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.

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.

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.

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 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:

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.

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.

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.

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

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."

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,

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.

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.

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.

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.

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

Name		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

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.

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

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.

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.

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.

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

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.

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

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

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:

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.

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

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:

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

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.

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

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

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:

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.

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:

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.

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

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:

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.

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:

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

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

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.

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.

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 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

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.

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:

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

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.

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.

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.

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

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

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.

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:

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.

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.

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.

	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

	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.

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.

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.

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

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.

	Year Ended December 31,

	Year Ended December 31,						Increase (Decrease)			Percentage Change
	2012			2011			Increase (Decrease)			Percentage Change
	($ 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	%

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

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.

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.

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.

	Year Ended December 31,

	Year Ended December 31,						Increase (Decrease)			Percentage Change
	2011			2010			Increase (Decrease)			Percentage Change
	($ 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	)%

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

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.

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.

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

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:

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.

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.

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

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

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

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.

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:

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

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.

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

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.

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

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.

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.

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.

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.

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.

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.

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.

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.


"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.


"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.


"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.


"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.


"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.

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

		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))

		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))

		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

		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

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.

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.

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:

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.

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.

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.

	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

										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

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

										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

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.

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.

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.

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

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.

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:

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 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 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.

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 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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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

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.

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:

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

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

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

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

		December 31,

	Estimated Useful Life (Years)	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

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.

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.

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

		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.

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.

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.

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.

	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

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.

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):

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:

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:

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.

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 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:

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.

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

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.

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	)

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.

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

	1^st Quarter			2^nd Quarter			3^rd Quarter			4^th 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	)

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.

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

	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

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

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

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:

		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))

		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)).

		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


(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

Title of Each Class		Name of Each Exchange on Which Registered

Common stock, $0.01 par value		The New York Stock Exchange


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


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

	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


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)

Item 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

	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


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

			Year Ended December 31,

	As of December 16, 2009		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


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

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

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


/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

U.S. Gulf of Mexico

Gross⁽¹⁾		Net⁽¹⁾
	1		0.42

West Africa

Gross⁽¹⁾		Net⁽¹⁾
	1		0.40

	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	$	—	$	—	$	—

	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		$	—

							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

								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



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

			Weighted Average Exercise Price			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

	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

Cobalt International Energy, Inc.

/s/ JOSEPH H. BRYANT

Joseph H. Bryant

Chairman of the Board of Directors and Chief Executive Officer

Dated: February 26, 2013