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. ý

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, 2011, 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 $1.63 billion.

As of January 31, 2012, the registrant had 392,303,969 shares of common stock outstanding.

Portions of the registrant's proxy statement relating to the 2012 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 a world-class below salt prospect inventory in the deepwater of the U.S. Gulf of Mexico and offshore Angola and Gabon in West Africa. All of our prospects are oil-focused. In the U.S. Gulf of Mexico, we have drilled as operator two exploratory wells (Ligurian #1 and Criollo #1) and participated as non-operator in three exploratory wells (Heidelberg #1, Shenandoah #1 and Firefox #1) and two appraisal wells (Heidelberg #2 and Heidelberg #3). These drilling efforts have resulted in the Heidelberg and Shenandoah oil discoveries. We are currently drilling as operator the Ligurian #2 exploratory well. Offshore Angola, we have drilled as operator the Cameia #1 exploratory well on Block 21 which resulted in the Cameia pre-salt oil discovery. We continue to mature high impact prospects in our portfolio for upcoming exploratory drilling in both the deepwater of the U.S. Gulf of Mexico and the deepwater offshore Angola and Gabon. In addition, we will progress our existing discoveries toward development and production through follow-on appraisal drilling and pre-development planning activities.

On December 20, 2011, we announced that we were evaluating the results of the Cameia #1 exploratory well and that the results at that point in time confirmed the existence of hydrocarbons and were very encouraging. On January 10, 2012, we announced that, through further analysis, the Cameia #1 exploratory well results confirmed (i) our West Africa pre-salt geologic model, (ii) a significant oil column with high quality volatile oil, (iii) anticipated net pay estimates that were better than we originally expected, (iv) a high quality carbonate reservoir, and (v) that our drilling had not encountered an oil-to-water contact. 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 oil 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 saturated with light oil. We believe the well, without such restrictions, would have the potential to produce in excess of 20,000 barrels of oil per day. As the Cameia #1 exploratory well only tested the pre-salt carbonate section and did not drill the entire pre-salt interval,

we believe upside potential exists for additional oil in deeper pre-salt intervals. We are the operator of and hold a 40% working interest in the Cameia #1 pre-salt oil discovery.

Our Cameia #1 pre-salt oil discovery confirms our West Africa pre-salt geologic model, including a working pre-salt petroleum system, significantly de-risks the geologic uncertainty associated with the deepwater Angolan pre-salt play, and increases the likelihood of geologic success on our adjacent undrilled prospects offshore Angola and Gabon. In addition, the results of the Cameia #1 exploratory well confirmed or exceeded our pre-drill estimates of oil quality and the reservoir quality and thickness. Such results also lead us to believe that the aerial extent of the Cameia #1 pre-salt oil discovery is between 7,500 and 25,000 acres (30 to 100 square kilometers). Although the results of the Cameia #1 exploratory well support our pre-drill expectations of the prospective area of the Cameia prospect, appraisal wells need to be drilled in order to determine and confirm its aerial extent as well as to test potential deeper pre-salt intervals.

Heidelberg #3. We participated as a non-operator in the Heidelberg #3 appraisal well which was spud in late 2011 in Green Canyon block 903. The Heidelberg #3 well appraised the Heidelberg Miocene oil discovery where more than 200 feet of net oil pay was discovered in February 2009. On February 16, 2012, the operator of the well 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 updip from the Heidelberg #1 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. The operator announced that it plans to immediately sidetrack the well to determine the down-dip extent of the field and also plans to initiate pre-FEED (front-end engineering and design) activities to prepare for sanctioning and a development project. We have a 9.375% working interest in the Heidelberg prospect.

2011 Angolan Pre-Salt Licensing Round. On December 20, 2011, the national oil company of Angola, Sociedade Nacional de Combustíveis de Angola—Empresa Pública ("Sonangol") concluded the highly anticipated 2011 Pre-Salt Licensing Round in Angola. As part of this licensing round, Sonangol finalized the awards of eleven pre-salt exploration blocks offshore Angola, including our award of a 40% interest in and operatorship of Block 20. Other operators awarded blocks include ConocoPhillips, BP, Total, Eni and Statoil. The high degree of interest by some of the world's largest and most experienced deepwater oil companies confirms that the industry now shares our long-held belief in the prospectivity of the pre-salt play offshore Angola. With the addition of Block 20 to our existing licenses on Blocks 9 and 21, we believe we have now established the pre-eminent position in offshore Angola's pre-salt play. We have a 40% working interest in and are the operator of each of our three blocks, something no other company has achieved in offshore Angola's pre-salt play. This leading position is a direct result of our early investment in the seismic data and technology necessary to image and understand the pre-salt geology in West Africa. Our analysis of the data led to our early identification and licensing of what we consider to be the most prospective blocks. Our West Africa strategy has achieved a significant milestone with the announcement of our Cameia #1 pre-salt oil discovery in Block 21.

Block 21 Offshore Angola. Given the results obtained from the Cameia #1 exploratory well, plans are underway to immediately drill the Cameia #2 appraisal well prior to drilling the Bicuar #1 exploratory well. The Bicuar #1 exploratory well remains a very attractive opportunity and a high priority in our Angola pre-salt exploration program. The Cameia #2 appraisal well is expected to spud in February 2012 and will be drilled to a planned total depth of up to 18,000 feet. The Cameia #2 appraisal well is expected to take 100-120 days to drill, followed by an evaluation period based on the well's results. The Cameia #2 appraisal well will help to determine the extent of the Cameia pre-salt

oil discovery as well as test the upside potential in the deeper intervals not tested by the Cameia #1 exploratory well. We have elected to pursue the Cameia #2 appraisal well prior to drilling our Bicuar #1 exploratory well in order to accelerate the evaluation of a phased approach for developing the Cameia pre-salt oil discovery. Our current plans are to implement an early production system incorporating a floating, production, storage and offloading ("FPSO") system for the Cameia development. We believe this phased development approach will help us better understand and quantify the pre-salt reservoir performance as well as deliver earlier cash flow than would be possible starting with a comprehensive full field development strategy. We are currently preparing the development schedule and do not have an estimate of first oil and cash flow from the Cameia discovery at this time.

Block 20 Offshore Angola. On December 20, 2011, we executed a Production Sharing Contract (the "PSC") with Sonangol, as well as Sonangol Pesquisa e Produção, S.A. ("Sonangol P&P"), BP Exploration Angola (Kwanza Benguela) Limited ("BP") and China Sonangol International Holding Limited ("China Sonangol"). The PSC forms the basis of our exploration, development and production operations on Block 20 offshore Angola. We are the operator of and have a 40% working interest in Block 20 offshore Angola. See "—Material Agreements—Production Sharing Contract for Block 20 Offshore Angola." As operator, we have initiated over a one million acre (4,200 square kilometer) 3-D seismic acquisition and processing program on Block 20 offshore Angola. This program will enable the prospect maturation of our extensive pre-salt portfolio on Block 20, including the maturation of our Lontra pre-salt prospect, which we believe displays similar characteristics as our Cameia #1 pre-salt oil discovery. Following the completion of the 3-D acquisition and processing program, we will further mature our Lontra prospect with plans to drill the Lontra #1 exploratory well in 2013.

Block 9 Offshore Angola. As operator, we continue to process and evaluate the approximate 600,000 acre (2,500 square kilometer) 3-D seismic survey we acquired on Block 9 in 2011. This 3-D seismic survey has further confirmed the presence of pre-salt prospects and structures on the block. We are currently in the process of maturing a number of pre-salt prospects, including our Loengo pre-salt prospect. Loengo is a pre-salt prospect that we have high-graded as a result of the 3-D seismic survey. Loengo is adjacent to the Azul #1 discovery announced by Maersk Oil in January 2012. Azul #1 gives us confidence that there is a working hydrocarbon system in the immediate area. Following the processing of our 3-D seismic survey, we will further mature our Loengo prospect with plans to drill the Loengo #1 pre-salt exploratory well in early 2013.

Diaba Block Offshore Gabon. We are currently participating as a non-operator with a 21.25% working interest in the deepwater Diaba block offshore Gabon. The operator continues to process and evaluate the approximate 1.5 million acre (6,000 square kilometer) 3-D seismic survey completed on the Diaba block in 2010. This 3-D seismic survey has further confirmed the presence of pre-salt prospects and structures on the block. The Diaba block is in close proximity to both onshore and offshore pre-salt oil discoveries such as the Rabi-Kounga field and the Maruba #2 discovery. The operator is currently in the process of maturing a number of pre-salt prospects, including the Mango and Mango South pre-salt prospects. These prospects were identified as two bifurcated prospects as a result of the 3-D seismic survey. Previously, they comprised our Longhorn prospect. We anticipate that the operator will drill the first pre-salt exploratory well in Diaba in early 2013.

Return to Continuous Operations in U.S. Gulf of Mexico. The legislative and regulatory response to the Deepwater Horizon drilling rig incident and oil spill significantly impacted our and our partners' ability to obtain permits and drill in the U.S. Gulf of Mexico. As a result of this period of drilling suspension and delay, the Ensco 8503 drilling rig, under contract to us, was directly sublet from its owner, Ensco Offshore Company, to a subsidiary of Tullow Oil plc. The term of this sublet was longer than originally anticipated, however, the Ensco 8503 drilling rig returned to the U.S. Gulf of Mexico late in the fourth quarter of 2011. Shortly after its return, we received the required U.S. Coast Guard

Certificate of Compliance and subsequently received Application for Permit to Drill ("APD") approval from the Bureau of Safety and Environmental Enforcement ("BSEE") for our Ligurian #2 exploratory well. While we were unable to drill any wells in the U.S. Gulf of Mexico in 2011, we expect to maintain a continuous drilling program in the U.S. Gulf of Mexico for the foreseeable future.

Ligurian #2. On January 1, 2012, we spud the Ligurian #2 exploratory well on Green Canyon Block 814. We believe the Ligurian blocks (Green Canyon 813, 814 and 858) and the Heidelberg blocks (Green Canyon 859 and 903) cover a common structural accumulation and we therefore refer to them as a joint prospect. On February 2, 2009, we announced that the Heidelberg #1 exploratory well had encountered more than 200 feet of net pay thickness in the Miocene horizons. The Ligurian #2 exploratory well will test the northwest flank of the Ligurian/Heidelberg interval discovered by the Heidelberg #1 exploratory well structure and evaluate a deeper Miocene formation. We anticipate announcing the results of the Ligurian #2 exploratory well in mid-2012. We are the named operator of and own a 45% working interest in the Ligurian blocks.

North Platte #1. After drilling and evaluating the Ligurian #2 exploratory well, we plan to move the Ensco 8503 drilling rig to our North Platte prospect to drill and evaluate the North Platte #1 exploratory well, for which we have an approved APD. The North Platte #1 exploratory well is located in the heart of the emerging inboard Lower Tertiary play in which we believe we hold a dominant position with numerous follow-on inboard Lower Tertiary exploratory prospects. We anticipate that the North Platte #1 exploratory well will take approximately six months to drill and evaluate. We are the operator of North Platte #1 and have a 60% working interest in the prospect.

Shenandoah #2. We will participate as a non-operator in the Shenandoah #2 appraisal well. This well will appraise the Shenandoah inboard Lower Tertiary oil discovery, made in 2009, where more than 300 feet of net oil pay was discovered. We expect well results in late 2012 or early 2013. We have a 20% working interest in the Shenandoah prospect.

Rum Ramsey #1. We expect to participate as a non-operator in the Rum Ramsey #1 exploratory well, which will test Miocene formations. We expect that the operator will spud the Rum Ramsey #1 exploratory well in the fourth quarter of 2012, with results anticipated in the second quarter of 2013. We have a 24% working interest in the Rum Ramsey prospect.

We currently have two drilling rigs under contract: the Ensco 8503 drilling rig and the Diamond Offshore Ocean Confidence drilling rig.

Ensco 8503 Drilling Rig. On December 21, 2011, we announced that the Ensco 8503 drilling rig had returned to the U.S. Gulf of Mexico following a sublet of the rig to an operator in French Guiana. The Ensco 8503 is a newly-built, fifth generation semi-submersible drilling rig. Our contract for the Ensco 8503 has a two year term, which commenced on January 1, 2012, and may be extended to up to four years at our option. The contract for the Ensco 8503 provides for an aggregate rate for the first two years of the contract of approximately $372 million, representing a base operating rate of $510,000 per day, subject to adjustment. We expect to utilize the Ensco 8503 continuously for at least the entire initial two-year term.

Diamond Offshore Ocean Confidence Drilling Rig. We executed a drilling contract with an affiliate of Diamond Offshore Company on November 8, 2010, for the use of the Ocean Confidence drilling rig to drill two firm wells, with options for two additional wells. Following the one-well assignment we made to Total Angola and the drilling of our Cameia #1 exploratory well on Block 21 offshore Angola, we have the right under this contract to use the Ocean Confidence to drill two additional wells at a base operating rate of $360,000 per day for the first well and a base operating rate of $375,000 per day for the second well. We are currently pursuing an additional drilling rig for our operations offshore

Angola. See "Risk Factors—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".

Since our formation, we have drilled as operator three exploratory wells (Cameia #1, Ligurian #1 and Criollo #1) and participated as non-operator in three exploratory wells (Heidelberg #1, Shenandoah #1 and Firefox #1) and two appraisal wells (Heidelberg #2 and Heidelberg #3). We have successfully made discoveries in both the U.S. Gulf of Mexico and offshore West Africa.

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 oil 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 saturated with light oil. See "—Cameia Pre-Salt Oil Discovery Offshore Angola."

Heidelberg #1, Ligurian #1, Heidelberg #2 and Heidelberg #3. On February 2, 2009, we announced that the Heidelberg #1 well had encountered more than 200 feet of net pay thickness in the Miocene horizons. Located in approximately 5,200 feet of water in Green Canyon 859 within the Tahiti Basin Miocene trend, this well was drilled to approximately 30,000 feet. Anadarko operates the block and we hold a 9.375% working interest. We purchased our interest in Green Canyon 859 and 903 (the "Heidelberg blocks") from an existing owner in May 2008 after we successfully acquired 100% of the working interest in the adjacent blocks of Green Canyon 813, 814 and 858 (the "Ligurian blocks") in the 2008 Central Gulf of Mexico Lease Sale.

On July 16, 2009, we spud Ligurian #1 on Green Canyon 858 to target the 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. We did encounter oil in the wellbore above the targeted horizons, but believe further drilling operations will be required to adequately test the prospect. See "—U.S. Gulf of Mexico Operational Update and Drilling Schedule—Ligurian #2."

On February 17, 2010, the Heidelberg #2 appraisal well was spud by the operator in approximately 5,300 feet of water in Green Canyon 903. On April 29, 2010, we announced that the operator 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 operator spud the Heidelberg #3 appraisal well in late 2011, thereby resuming the Heidelberg appraisal drilling program. On February 16, 2012, the operator of the well 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 updip from the Heidelberg #1 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. The operator announced that it plans to immediately sidetrack the well to determine the down-dip extent of

the field and also plans to initiate pre-FEED (front-end engineering and design) activities to prepare for sanctioning and a development project.

Shenandoah #1. On February 4, 2009, we announced that the Shenandoah #1 well had been drilled into inboard Lower Tertiary horizons. The operator has stated that this well encountered approximately 300 feet of net pay thickness. This well, located in approximately 5,750 feet of water in Walker Ridge 52, was drilled to approximately 30,000 feet. We hold a 20% working interest in this prospect. We strategically purchased our interest in Shenandoah #1 to test our hypothesis that targeting the previously undrilled inboard Lower Tertiary, which we regard as an emerging trend located to the northwest of existing outboard Lower Tertiary fields such as St. Malo, Jack and Cascade, would lead to discoveries that exhibit meaningfully better reservoir characteristics than had previously been encountered by the industry in the outboard Lower Tertiary. We believe the successful results of the Shenandoah #1 well support our hypothesis. We expect the results of the Shenandoah #2 appraisal well, which will appraise the Shenandoah #1 discovery, in late 2012 or early 2013. See "—U.S. Gulf of Mexico Operational Update and Drilling Schedule—Shenandoah #2."

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 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 hold 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 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 hold a 30% working interest in this prospect.

On April 6, 2009, we announced a long-term alliance with TOTAL E&P USA, INC. ("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 224 blocks. We will 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 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, 2011, approximately $193 million of the $300 million that Total is obligated to carry us remains available to us, as does the potential award of up to $180 million based on the success of the alliance.

On April 22, 2009, we announced a partnership in the U.S. Gulf of Mexico with 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 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 U.S. Gulf of Mexico leases pursuant to this partnership bringing the total partnership portfolio to 15 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 prospect identification and analysis 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 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 U.S. Gulf of Mexico. In West Africa, we have acquired approximately 125,000 line miles (200,000 line kilometers) of 2-D seismic data and, as of January 15, 2012, approximately 6,100 square miles (15,800 square kilometers) of 3-D seismic data. 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. As part of our prospect identification and analysis approach, we estimate, among other things, the "mean net area" of our prospects. To determine the aerial extent of a hydrocarbon-bearing section of a prospect, or the prospect area, we use our seismic data and all available geologic data to map the aerial extent of the closures or trapping geometries that can hold hydrocarbons. Because it is not possible to directly detect the presence of hydrocarbons prior to drilling the prospect, we use statistical methods to define the amount of the closure that can be filled with hydrocarbons. We use a lognormal distribution to define the probabilities of the size of the prospect area. The prospect area may extend across multiple lease blocks or license areas, including on lease blocks and license areas in which we do not own an interest. For each block or license area, our

ownership percentage is referred to as our working interest. For those prospects which extend beyond our leasehold acreage, we include only the portion of prospect acreage for which we hold leasehold title. We refer to this as the mean net area of the prospect. Depending on the terms of our lease or license agreement, we may be required to pay royalties on our oil and gas production.

The accuracy of our estimates is subject to a number of risks and uncertainties as described under the heading "Risk Factors—We face substantial uncertainties in estimating the characteristics of our prospects, so you should not place undue reliance on any of our estimates."

Once a prospect is identified and analyzed, we may seek to acquire leasehold title to the lease blocks (in the U.S. Gulf of Mexico) or license area (offshore Angola and Gabon) that include the prospect. The leasehold acquisition typically occurs from one of two sources: from governments through lease sales, licensing rounds or direct negotiations, 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 or license areas that we believe includes the entire prospect or a portion thereof.

Our oil-focused exploration efforts primarily target subsalt Miocene and Lower Tertiary horizons in the deepwater U.S. Gulf of Mexico. The deepwater subsalt petroleum provinces are the least explored of the accessible regions of the U.S. Gulf of Mexico. Advances in technology over the past 10 years have led to significant discoveries and increased the hydrocarbon assessment 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, including Tahiti (Green Canyon 640), Knotty Head (Green Canyon 512), Kaskida (Keathley Canyon 292) and Tiber (Keathley Canyon 102).

Miocene. The subsalt Miocene trend is an established play in the deepwater U.S. Gulf of Mexico. Major discoveries in this trend include Thunder Horse, Atlantis, Tahiti, Mad Dog, Knotty Head and Heidelberg. 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. Based on these studies, we have identified two trends located primarily in the Green Canyon protraction area, which we refer to as the Tahiti Basin Miocene trend and the Adjacent Miocene trend. The Tahiti Basin Miocene trend is in one of the most successful hydrocarbon bearing basins within the deepwater U.S. Gulf of Mexico. Major discoveries in this area include Tahiti, Caesar, Tonga, Knotty Head, Pony and the discovery at Heidelberg #1. Because many fields have been discovered in this area, a network of facility and pipeline infrastructure may be available for commercializing potential discoveries. The Adjacent Miocene trend is located adjacent to the Tahiti Basin Miocene trend. We believe our prospects within the Adjacent Miocene trend offer substantial, commercially viable resource potential due to similarities in the geologic profile to that of the Tahiti Basin Miocene trend. Our prospect inventory in this trend benefits from significant seismic delineation via proprietary 3-D reprocessing that indicates large, well-defined subsalt closures. In much of the trend there is limited facility and pipeline infrastructure. As such, we anticipate that free-standing, independent facilities may be required to develop discoveries in this area.

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. These reservoirs are generally located in water depths of 5,000 feet to 8,000 feet, and have shown net pay thickness zones of up to 800 feet. In 2006, the discovery at Kaskida (Keathley Canyon 292) encountered 800 feet of net pay thickness. A more recent discovery in the Lower Tertiary, Shenandoah, has encountered approximately 300 feet of net pay thickness. 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 very similar to that of existing Miocene discoveries is the inboard Lower Tertiary trend, which includes the Shenandoah discovery. 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. Our technical team's hypothesis regarding the region's potentially higher-quality reservoir properties was supported by the result of the Shenandoah #1 well in which we participated. This discovery had reservoir characteristics more similar to Miocene reservoirs. 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 potentially superior reservoir quality. Because the inboard Lower Tertiary is an emerging trend, there is limited facility and pipeline infrastructure in the area. As such, we anticipate that free-standing, independent facilities may be required to develop discoveries in this area. To date, the inboard Lower Tertiary trend remains largely undrilled.

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 Lower Tertiary horizons, were ultimately transported and deposited by gravity flows in slope minibasins 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, the 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 recently garnered interest from the industry with recent 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.

As of December 31, 2011, we owned working interests in 231 blocks within the deepwater U.S. Gulf of Mexico covering approximately 1.3 million gross acres (0.6 million net acres). We are the operator of approximately 75% of our U.S. Gulf of Mexico blocks. Most of our U.S. Gulf of Mexico blocks have a 10-year primary term, expiring between 2016 and 2020. 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. In the U.S. Gulf of Mexico, the royalties on our lease blocks range from 12.5% to 18.75% with an average of 15.4%.

As of December 31, 2010, we identified the 47 prospects on our blocks that are discussed below, comprised of 20 Miocene trend prospects, 22 inboard Lower Tertiary trend prospects and 5 dual Miocene and inboard Lower Tertiary trend prospects. The legislative and regulatory response to the Deepwater Horizon drilling rig incident and oil spill significantly impacted our and our partners' ability to obtain permits and drill in the U.S. Gulf of Mexico. As a result of this period of drilling suspension and delay, the Ensco 8503 drilling rig, under contract to us, was directly sublet from its owner, Ensco Offshore Company, to a subsidiary of Tullow Oil plc. The term of this sublet was longer than originally anticipated, however, the Ensco 8503 drilling rig returned to the U.S. Gulf of Mexico late in the fourth quarter of 2011. Because we did not drill any wells in the U.S. Gulf of Mexico in 2011, we have no basis to change our number of identified prospects or our estimates regarding the net mean area associated with those prospects. As we continue to drill exploratory and appraisal wells in the U.S. Gulf of Mexico, our estimates associated with our prospects could change. In interpreting this information, specific reference should be made to the subsections of this Annual Report on Form 10-K titled "Risk Factors—We face substantial uncertainties in estimating the characteristics of our prospects, so you should not place undue reliance on any of our estimates" and "Business—How We Identify and Analyze Prospects."

Ligurian/Heidelberg. The undrilled deeper portion of the Ligurian/Heidelberg prospect is a 3-way structure targeting deep Miocene horizons below the Miocene reservoir discovered by the Heidelberg #1 exploratory well. We believe the Ligurian blocks and the Heidelberg blocks cover a common structure accumulation, and we therefore refer to them as a joint prospect. We are the named operator and own a 45% working interest in the Ligurian blocks, and we have a 9.375% working interest in the Anadarko-operated Heidelberg blocks. We purchased our interest in the Heidelberg blocks from an existing owner in May 2008 after we successfully acquired 100% of the working interest in the adjacent Ligurian blocks in the 2008 Central Gulf of Mexico Lease Sale. This prospect was mapped using proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. The undrilled Miocene horizons of this prospect have an estimated mean net area of 5,400 acres. For prior drilling results on Ligurian/Heidelberg, see "—Prior Drilling Results—Heidelberg #1, Ligurian #1, Heidelberg #2 and Heidelberg #3." For information on our current drilling plans see "—U.S. Gulf of Mexico Operational Update and Drilling Schedule—Ligurian #2."

Ardennes. Ardennes is a 3-way prospect targeting Miocene and Lower Tertiary horizons located in Green Canyon blocks 895, 896 and 939, where we are the named operator and own a 42% working interest. This prospect was acquired through a 2007 direct purchase, a trade in 2008, and in the 2007 and 2008 Central Gulf of Mexico Lease Sales. 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. The Miocene horizons of this prospect have an estimated mean net area of 3,300 acres. In addition to the Miocene horizons, the Lower Tertiary horizons of this prospect have an estimated mean net area of 3,600 acres. We expect that we will spud the Ardennes #1 exploratory well in 2013.

Rum Ramsey. Rum Ramsey is a 3-way prospect targeting Miocene horizons located in Green Canyon blocks 632, 633 and 676, where BHP is the named operator and we own a 24% working interest. This prospect was acquired in the 2008 Central Gulf of Mexico Lease Sale and through a 2008 trade. Rum Ramsey was mapped using our proprietarily processed, pre-stack, depth-migrated, narrow-azimuth 3-D seismic data and non-proprietary, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 4,500 acres. For information on our current drilling plans, see "—U.S. Gulf of Mexico Operational Update and Drilling Schedule—Rum Ramsey #1."

Lyell. Lyell is a 4-way prospect targeting Miocene horizons located in Green Canyon blocks 550 and 551, where Anadarko is the named operator and we own a 15% working interest. This prospect was acquired through a 2006 farm-in agreement and 2009 direct purchase. Lyell was mapped using non-proprietary, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 1,100 acres.

Racer. Racer is a 3-way prospect targeting Miocene and Lower Tertiary horizons located in Green Canyon blocks 762 and 806, where BHP is the named operator and we own a 24% working interest. This prospect was acquired in the 2007 Central Gulf of Mexico Lease Sale and through a trade in 2008. Racer was mapped using our proprietarily processed, pre-stack, depth-migrated, narrow-azimuth 3-D seismic data and non-proprietary wide-azimuth 3-D depth data. The Miocene horizons of this prospect have an estimated mean net area of 4,800 acres. In addition to the Miocene horizons, the Lower Tertiary horizons of this prospect have an estimated mean net area of 5,200 acres. We expect that the operator will spud the Racer #1 exploratory well in 2013.

Rocky Mountain. Rocky Mountain is a 3-way prospect targeting Miocene horizons located in Mississippi Canyon blocks 649, 693 and 737, where we are the named operator and own a 45% working interest. This prospect was acquired in the 2008 Central Gulf of Mexico Lease Sale and is syncline separated from the Blind Faith field. Rocky Mountain was mapped using our proprietarily processed, pre-stack, depth-migrated, narrow-azimuth 3-D seismic data. This prospect has an estimated mean net area of 2,400 acres.

Saddelbred. Saddelbred is a 3-way prospect targeting Miocene horizons located in Green Canyon blocks 414, 457 and 458, where we are the named operator and own a 60% working interest. This prospect was acquired in the 2007 and 2010 Central Gulf of Mexico Lease Sales. Saddelbred was mapped using our proprietarily processed, wave-equation, pre-stack, depth-migrated, narrow-azimuth 3-D seismic data. This prospect has an estimated mean net area of 7,900 acres.

Additional Miocene Prospects. We have 18 additional prospects targeting Miocene horizons, in which we have an average working interest of 40%. Three of these prospects are dual Miocene and Lower Tertiary prospects. These prospects are operated by either us or various other companies. Each of these additional prospects was acquired in various Gulf of Mexico Lease Sales or through direct purchases or trades. We mapped these prospects using a variety of 3-D seismic data. These prospects have an average estimated mean net area of 1,400 acres.

North Platte. North Platte is a 4-way prospect targeting Lower Tertiary horizons located in Garden Banks blocks 915, 958, 959, 1002 and 1003, where we are the named operator and own a 60% working interest. This prospect was acquired in the 2006 Western Gulf of Mexico Lease Sale and the 2007 and 2008 Central Gulf of Mexico Lease Sales. North Platte was mapped using our proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 5,600 acres. For information on our current drilling plans see "—U.S. Gulf of Mexico Operational Update and Drilling Schedule—North Platte #1."

Aegean. Aegean is a 3-way prospect targeting Lower Tertiary horizons located in Keathley Canyon blocks 162, 163 and 207, where we are the named operator and own a 37.5% working interest. This prospect was acquired in the 2008 Central Gulf of Mexico Lease Sale and through a 2010 trade. Aegean was mapped using proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 6,700 acres. We expect that we will spud the Ardennes #1 exploratory well in 2013.

Shenandoah. The deeper undrilled portion of the Shenandoah prospect is a 3-way structure targeting Lower Tertiary horizons not penetrated by the Shenandoah #1 exploratory well. This prospect is located in Walker Ridge blocks 51 and 52, where Anadarko is the named operator and we own a 20% working interest. This prospect was acquired through a 2008 purchase. Shenandoah was mapped using non-proprietarily processed pre-stack, depth-migrated, wide-azimuth 3-D seismic data. The undrilled Lower Tertiary horizons of this prospect have an estimated mean net area of 5,700 acres. These estimates exclude the net pay encountered in certain Lower Tertiary horizons that were drilled by Shenandoah #1. For prior drilling results on Shenandoah, see "—Prior Drilling Results—Shenandoah #1." For information on our current drilling plans see "—U.S. Gulf of Mexico Operational Update and Drilling Schedule—Shenandoah #2."

Goodfellow (formerly Catalan). Goodfellow is a 3-way prospect targeting Lower Tertiary horizons located in Keathley Canyon block 129 and Walker Ridge blocks 89, 90 and 133, where Eni is the operator and we own a 29% working interest. This prospect was primarily acquired in the 2008 and 2009 Central Gulf of Mexico Lease Sales and in a 2009 trade. Goodfellow was mapped using our proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 5,100 acres.

Latvian. Latvian is a 3-way prospect targeting Lower Tertiary horizons located in Garden Banks blocks 874, 917, 918 and 919, where we are the named operator and own a 60% working interest. This prospect was acquired in the 2006 Western Gulf of Mexico Lease Sale and the 2007 and 2008 Central Gulf of Mexico Lease Sales. Latvian was mapped using our proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 1,800 acres.

Williams Fork. Williams Fork is a 3-way prospect targeting Lower Tertiary horizons located in Garden Banks blocks 821, 823, 865, 866 and 867, where Nexen is the named operator except for Garden Banks block 821 for which we are the operator. We have a 60% working interest in Garden Banks block 821 and a 30% working interest in the remaining blocks. This prospect was acquired in the 2006 Western Gulf of Mexico Lease Sale and the 2007 and 2008 Central Gulf of Mexico Lease Sales. Williams Fork was mapped using non-proprietarily processed, pre-stack, depth-migrated wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 5,200 acres.

Caspian. Caspian is a 4-way prospect targeting Lower Tertiary horizons located in Garden Banks blocks 495, 496, 497, 539, 540 and 541, where we are the named operator and own a 60% working interest. This prospect was acquired in the 2008 Western Gulf of Mexico Lease Sale, the 2009 Central Gulf of Mexico Lease Sale and a 2009 trade. Caspian was mapped using our non-proprietarily processed, pre-stack, depth-migrated, narrow-azimuth 3-D seismic data. This prospect has an estimated mean net area of 7,200 acres.

South Platte. South Platte is a 3-way prospect targeting 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. This prospect was acquired in the 2006 Western Gulf of Mexico Lease Sale, the 2008 Central Gulf of Mexico Lease Sale and through a 2009 trade. South Platte was mapped using our proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 3,800 acres.

Baffin Bay. Baffin Bay is a 3-way prospect targeting Lower Tertiary horizons located in Garden Banks blocks 956 and 957, where we are the named operator and own a 60% working interest. This prospect was acquired in the 2008 Central Gulf of Mexico Lease Sale. Baffin Bay was mapped using our proprietarily processed, pre-stack, depth-migrated, wide-azimuth 3-D seismic data. This prospect has an estimated mean net area of 4,600 acres.

Additional Inboard Lower Tertiary Prospects. We have 16 additional prospects targeting inboard Lower Tertiary horizons, in which we have an average working interest of 41%. Three of these prospects are dual Miocene and Lower Tertiary prospects. These prospects are operated by either us or various other companies. Each of these additional prospects was acquired in various Gulf of Mexico Lease Sales or through trades. We mapped these prospects using a variety of 3-D seismic data. These prospects have an average estimated mean net area of 1,900 acres.

The initial well drilled to test a prospect is referred to as an exploratory well. If a discovery is made by the initial exploratory well, the operator may choose to drill one or more appraisal wells to delineate the size and other characteristics of the discovered field. This information is used to create a plan of development, which may include the construction of offshore facilities and drilling of development wells designed to efficiently produce hydrocarbons from the field. Any oil resources, if developed, would use either newly constructed processing facilities owned by the working-interest partnership or processing facilities leased from third-party providers. In general, we expect our development wells will be produced through subsea templates tied back to the processing facilities.

Prior to the Deepwater Horizon incident, we estimated that the average gross cost to drill and evaluate an exploratory well would be approximately $100 to $130 million for Miocene prospects and approximately $140 to $170 million for inboard Lower Tertiary prospects, that the average gross cost to drill and evaluate an appraisal well would be approximately $110 to $140 million for Miocene prospects and approximately $150 to $180 million for inboard Lower Tertiary prospects and 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. We initially estimate that compliance with new regulations will increase these costs by approximately 20%, however, as we conduct drilling operations under these new regulations, we may be able achieve operational efficiencies which could offset some of these projected cost increases.

We have licenses with pre-salt and above salt exploration potential offshore Angola (Blocks 9, 20 and 21) and Gabon (Diaba block). We obtained our licenses offshore Angola and Gabon after a multi-year assessment of global deepwater hydrocarbon trends and resource potential. Our assessment was driven by our interpretation of seismic data, the international operating experience of our management and technical teams and an in-depth evaluation of regional political risk and economic conditions. The emerging offshore West African pre-salt exploration trend has geologic characteristics similar to the pre-salt basins offshore Brazil, which includes the Lula (formerly Tupi) and Jupiter fields in the Santos Basin and the Whale Park (Jubarte) complex in the Campos Basin. Our Cameia #1 pre-salt oil discovery, along with Maersk's Azul pre-salt oil discovery, confirms our West Africa pre-salt geologic model, significantly de-risks the geologic uncertainty associated with the deepwater Angolan pre-salt play, and increases the likelihood of geologic success on our adjacent undrilled prospects offshore Angola and Gabon. For more information regarding our Cameia discovery, see "—Cameia Pre-Salt Oil Discovery 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.

Offshore Angola, we have executed Risk Services Agreements ("RSAs") for Blocks 9 and 21 with Sonangol, as well as 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 the PSC with Sonangol, as well as Sonangol P&P, BP, and 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.

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 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.

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. See "Item 1A. Risk Factors—We have no proved reserves and areas that we decide to drill may not yield oil in commercial quantities or quality, or at all."

Given the evidence of large structural closures and widespread sealing salt and rich source rocks, the primary geologic risk of the deepwater West Africa pre-salt play was the presence of quality reservoirs. Our Cameia #1 pre-salt oil discovery, along with Maersk's Azul pre-salt oil discovery, confirmed our West Africa pre-salt geologic model and rift basin hypothesis, 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 and Gabon. In addition, the results of the Cameia #1 exploratory well confirmed or exceeded our pre-drill estimates of reservoir quality and thickness. Given the results obtained from the Cameia #1 exploratory well, for the foreseeable future we plan to focus our exploratory and appraisal drilling activities offshore West Africa exclusively on the pre-salt play. For more information regarding our Cameia discovery, see "—Cameia Pre-Salt Oil Discovery Offshore Angola."

As of December 31, 2010, we had identified 122 prospects, 79 within our license areas offshore Angola (Blocks 9, 20, and 21) and 43 within our license area offshore Gabon (Diaba block). During 2011, we continued to process and evaluate the 3-D seismic surveys we completed on Blocks 9 and 21, and we initiated over a one million acre (4,000 square kilometer) 3-D seismic acquisition and processing program on Block 20. In addition, we drilled the Cameia #1 exploratory well on Block 21, which resulted in our Cameia pre-salt oil discovery. As a result of these activities, we have high-graded the 41 pre-salt prospects (31 offshore Angola and 10 offshore Gabon) discussed below. In addition, given our Cameia pre-salt oil discovery, for the foreseeable future we plan to focus our exploratory and appraisal drilling activities offshore West Africa exclusively on the pre-salt play and do not currently have plans to drill any of our prospects targeting Albian horizons. We are continuing to mature our prospect inventory. As we continue to drill exploratory and appraisal wells offshore West Africa and acquire and process additional seismic data, our estimates associated with and numbers of our prospects could change. In interpreting this information, specific reference should be made to the subsections of this Annual Report on Form 10-K titled "Risk Factors—We face substantial uncertainties in estimating the characteristics of our prospects, so you should not place undue reliance on any of our estimates" and "Business—How We Identify and Analyze Prospects."

Cameia. 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 oil 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 minimal bottom-hole pressure 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 saturated with light oil. We believe the well, without such restrictions, would have the potential to produce in excess of 20,000 barrels of oil per day. As the Cameia #1 exploratory well only tested the pre-salt carbonate section and did not drill the entire pre-salt interval, we believe upside potential exists for additional oil in deeper pre-salt intervals. Given the results obtained from the Cameia #1 exploratory well, plans are underway to immediately drill the Cameia #2 appraisal well prior to drilling the Bicuar #1 exploratory well. The Bicuar #1 exploratory well remains a very attractive opportunity and a high priority in our Angola pre-salt exploration program. The Cameia #2 appraisal well is expected to spud in February 2012 and will be drilled to a planned total depth of up to 18,000 feet. The Cameia #2 appraisal well is expected to take 100-120 days to drill, followed by an evaluation period based on the well's results. The Cameia #2 appraisal well will help to determine the extent of the Cameia pre-salt oil discovery as well as test the upside potential in the deeper intervals not tested by the Cameia #1 exploratory well. We have elected to pursue the Cameia #2 appraisal well prior to drilling our Bicuar #1 exploratory well in order to accelerate the evaluation of a phased approach for developing the Cameia pre-salt oil discovery. Our current plans are to implement an early production system incorporating an FPSO system for the Cameia development. We believe this phased development approach will help us better understand and quantify the pre-salt reservoir performance as well as deliver earlier cash flow than would be possible starting with a comprehensive full field development strategy. We are currently preparing the development schedule and do not have an estimate of first oil and cash flow from the Cameia discovery at this time. We are the operator of and hold a 40% working interest in the Cameia prospect. For more information regarding the Cameia prospect, see "—Cameia Pre-Salt Oil Discovery Offshore Angola."

Bicuar. Bicuar is a prospect targeting pre-salt horizons in Block 21, where we are the named operator and have a 40% working interest. Bicuar was mapped using our pre-stack, depth-migrated 3-D seismic data. This prospect has an estimated mean net area of 21,000 acres. On July 19, 2011, we spud the surface hole of the Bicuar #1 exploratory well. On July 20, 2011, after setting the 36" conductor casing and drilling approximately 210 meters of surface hole, we encountered an over pressured water sand resulting in a water flow. No safety or environmental issues resulted from the incident. We abandoned the Bicuar #1 exploratory well and moved the drilling rig to and drilled the Cameia #1 exploratory well so we could reexamine our shallow hazard analysis before respudding the Bicuar #1 exploratory well. We have completed this work and we plan to drill the Bicuar #1 pre-salt exploratory well at a different surface hole location from the location in which we originally spud the Bicuar #1 exploratory well. See "—West Africa Operational Update and Drilling Schedule—Block 21 Offshore Angola."

Lontra. Lontra is a prospect targeting pre-salt horizons in Block 20, where we are the named operator with a 40% working interest. Lontra was mapped using our 2-D seismic data. This prospect has an estimated mean net area of 61,700 acres. See "—West Africa Operational Update and Drilling Schedule—Block 20 Offshore Angola."

North Cameia. North Cameia is a prospect targeting pre-salt horizons in Block 21, where we are the named operator and have a 40% working interest. North Cameia was mapped using our pre-stack, depth-migrated 3-D seismic data. This prospect has an estimated mean net area of 6,500 acres and is located approximately 10 kilometers northwest of the Cameia #1 exploratory well location. We expect to spud North Cameia in 2013.

Loengo. Loengo is a prospect targeting pre-salt horizons in Block 9, where we are the named operator and have a 40% working interest. Loengo was mapped using our 3-D seismic data. This prospect has an estimated mean net area of 19,700 acres.

Monte Carlo. Monte Carlo is a prospect targeting pre-salt horizons in Block 21, where we are the named operator and have a 40% working interest. Monte Carlo was mapped using our 2-D seismic data. This prospect has an estimated mean net area of 31,200 acres.

Elstar. Elstar is a prospect targeting pre-salt horizons in Block 20, where we are the named operator with a 40% working interest. Elstar was mapped using our 2-D seismic data. This prospect has an estimated mean net area of 17,400 acres.

Haas. Haas is a prospect targeting pre-salt horizons in Block 20, where we are the named operator with a 40% working interest. Haas was mapped using our 2-D seismic data. This prospect has an estimated mean net area of 12,600 acres.

Additional Angola Prospects (Blocks 9, 20 and 21). We currently have 23 additional prospects targeting pre-salt horizons, in which we have a 40% working interest. We are the named operator for all of these prospects. In addition, we have identified 43 prospects targeting Albian horizons on Blocks 9, 20 and 21 offshore Angola. However, as a result of our Cameia pre-salt oil discovery, for the foreseeable future we plan to focus our exploratory and appraisal drilling activities offshore Angola exclusively on the pre-salt play and do not currently have plans to drill any of our prospects targeting Albian horizons.

Mango and Mango South. As a result of our 3-D seismic acquisition and processing we completed in 2011, Mango and Mango South were identified as two bifurcated prospects which previously comprised our Longhorn prospect. Mango and Mango South are both prospects targeting pre-salt horizons, where Total Gabon is the named operator and we have a 21.25% working interest. Mango has an estimated mean net area of 25,000 acres and Mango South has an estimated mean net area of 20,000 acres.

Pioneer. Pioneer is a prospect targeting pre-salt horizons, where Total Gabon is the named operator and we have a 21.25% working interest. Pioneer was mapped using our 2-D seismic data. This prospect has an estimated mean net area of 35,000 acres.

Rainbow. Rainbow is a prospect targeting pre-salt horizons, where Total Gabon is the named operator and we have a 21.25% working interest. Rainbow was mapped using our 2-D seismic data. This prospect has an estimated mean net area of 61,500 acres.

Additional Gabon Prospects. We currently have 6 additional prospects targeting pre-salt horizons offshore Gabon, in which we have a 21.25% working interest. These prospects have been mapped using our 3-D seismic data. Total Gabon is the named operator for all of these prospects. In addition, we have identified 15 prospects targeting Albian horizons on the Diaba block offshore Gabon. However, as a result of our Cameia pre-salt oil discovery, for the foreseeable future we plan to participate in exploratory and appraisal drilling activities offshore Gabon that exclusively focus on the pre-salt play and do not currently have plans to participate in the drilling of any prospects targeting Albian horizons.

In Angola, we work in a contractor relationship to the national oil company, Sonangol, with terms and conditions established by the RSAs for Blocks 9 and 21 and the PSC for Block 20. In Gabon, we work in a contractor relationship to the Republic of Gabon with terms and conditions established by the PSA. The PSC, PSA and RSAs, as the case may be, define contractual terms, including fiscal terms, minimum contractor work, investment obligations, the carry of local partners' capital investments, and required progress milestones.

The drilling of exploratory and appraisal wells in both Angola and Gabon is well within known technological boundaries. The marine and subsurface conditions are anticipated to be normally pressured thus enabling standardization and simplification of well design. Offshore Angola and Gabon, we estimate that the gross cost to drill and evaluate exploratory and appraisal wells is approximately $100 to $140 million per well for pre-salt prospects. The timing of our exploratory and appraisal wells included herein represents our current expectations as to the priority in which prospects will be drilled. Actual timing decisions may differ significantly due to availability of critical equipment such as drilling rigs, material and staff, drilling results from offset or nearby prospects, government approvals, and funding priorities.

As an operator in Angola, we expect that our primary development concept for any discovery, including our Cameia pre-salt oil 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 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.

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 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 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.

We entered into a base drilling contract related to the Ensco 8503 drilling rig with Ensco on May 8, 2008. This contract has a two year term, which commenced on January 1, 2012, at a base operating rate of $510,000 per day, subject to adjustment, which aggregates to approximately $372 million over the two years of the base contract. See "—Drilling Rigs—Ensco 8503 Drilling Rig."

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 Cobalt as the operator of Block 20. On December 20, 2011, CIE Angola Block 20 Ltd., our wholly-owned subsidiary, executed the PSC with Sonangol, as well as Sonangol P&P, BP and China Sonangol. The PSC forms the basis of our exploration, development and production operations on Block 20 offshore Angola. We are the operator of and have 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, BP and China Sonangol 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. On January 20, 2012, we notified Sonangol that we had satisfied our obligations with respect to the acquisition of 1,500 square kilometers of 3-D seismic data and requested Sonangol to approve that our letter of credit be reduced by approximately $17 million (net). In addition, pursuant to the PSC, we, BP, and China Sonangol 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 below) 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 size of the applicable rate of return. 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.

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 Cobalt 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, as well as 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 oil 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 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 231 blocks within the deepwater U.S. Gulf of Mexico covering approximately 1.3 million gross acres (0.6 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 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").

HWCG has a contract with Helix Energy Services Group which 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. Members of HWCG include Anadarko Petroleum Corporation, Apache Deepwater LLC, ATP Oil & Gas Corporation, BHP Billiton (Americas), Inc., Hess Corporation, Marathon Oil Company, Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Plains Exploration & Production Company, and Statoil Gulf of Mexico LLC, among others.

CGA administers the HWCG membership agreements and also provides us with access to a wide variety of surface spill response equipment, such as skimmers, dispersant and containment boom. As a member of MPA, we have access to the resources of the Marine Spill Response Corporation ("MSRC"). MSRC provides a wide variety of surface spill equipment, including approximately 75% of the existing dispersant material in the U.S. Gulf of Mexico region. NRC is an umbrella response corporation that provides us access to a wide variety of surface spill response equipment as well as a wide group of surface response contractors that can address a surface response as well as play a

support role in addressing a subsea well containment event. In addition, we have existing contracts with a number of contractors which have equipment that could assist in well containment efforts as well as with the surface effects of a subsea blowout or in addressing a concurrent surface spill. Examples of such equipment include, but are not limited to, anchor and supply vessels, subsea transponders and communication equipment, subsea cutting equipment, debris removal equipment, air and water monitoring and scientific support vessels, remote-operated vehicles, storage and shuttle vessels, and subsea dispersant equipment.

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

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

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

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. In West Africa, we have insurance coverage in place for our operations, consisting of a $500 million policy for operator's extra expense and up to $450 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—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—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 and transportation 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—Interim 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 believe that the extensive new regulations and changes proposed thereto, increased regulatory scrutiny including the requirement 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 conduct our drilling operations in the U.S. Gulf of Mexico. Substantial costs associated with compliance with these regulations and substantial increases in the time and effort required to obtain drilling permits 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 development 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.

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 primarily to

regulation 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 that may be issued in final form by 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 proposed using 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, the EPA and National Highway Traffic Safety Administration finalized GHG emissions standards for light-duty vehicles. 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 new 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 binding and proposed 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 is set to expire in 2012. Passage of a successor international agreement or scheme aimed at the reduction of GHGs is uncertain. In late 2011, however, 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 addition, the Durban conference resulted in the relevant parties agreeing to extend the Kyoto Protocol for a second commitment period. U.S. federal climate change regulation or laws or climate change 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 regulation, respectively. These regulations govern licensing for drilling operations, mandatory involvement of local partners in our operations, taxation of our revenues, safety and environmental matters and our ability to operate in such jurisdictions as a foreign participant. 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. We have engaged third party consultants to assist us with our compliance efforts in Angola.

As of December 31, 2011, we had 75 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, 2011, we had 90 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	56	Chairman of the Board of Directors and Chief Executive Officer
Van P. Whitfield	60	Chief Operating Officer
John P. Wilkirson	54	Chief Financial Officer and Executive Vice President
James H. Painter	54	Executive Vice President, Gulf of Mexico
Michael D. Drennon	56	Executive Vice President and General Manager, Cobalt Angola
James W. Farnsworth	56	Chief Exploration Officer
Jeffrey A. Starzec	35	Senior Vice President and General Counsel
Lynne L. Hackedorn	53	Vice President, Government and Public Affairs
Richard A. Smith	52	Vice President, Investor Relations and Planning

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 34 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 37 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 31 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 32 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 and General Manager, Cobalt Angola since April 2010 and has 35 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 27 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 27 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 and Planning since October 2011. 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 29 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. However, 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. Additionally, 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.

We face substantial uncertainties in estimating the characteristics of our prospects, so you should not place undue reliance on any of our estimates.

In this Annual Report on Form 10-K we provide estimates of the numerical characteristics of our prospects, including with regard to the size and quality of our discoveries and prospects. These estimates may be incorrect, as the accuracy of these estimates is a function of the available data, geological interpretation and judgment. To date, only a limited number of our prospects have been drilled. Any analogies drawn by us from other wells, prospects or producing fields may not prove to be accurate indicators of the success of developing reserves from our prospects. Furthermore, we have no way of evaluating the accuracy of the data from analog wells or prospects produced by other parties which we may use.

It is possible that few or none of our wells to be drilled will find accumulations of hydrocarbons in commercial quantities or qualities. Any significant variance between actual results and our assumptions could materially affect the quantities of oil attributable to any particular group of properties. In this Annual Report on Form 10-K, we refer to the "mean" of the estimated data. This measurement is statistically calculated based on a range of possible values of such estimates, with such ranges being particularly large in scope. Therefore, there may be large discrepancies between the mean estimate provided in this Annual Report on Form 10-K and our actual results.

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.

New 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.

BSEE, responded to this incident by imposing moratoria on drilling operations and adopting numerous new regulations and new interpretations of existing regulations regarding operations in the U.S. Gulf of Mexico. Compliance with these new regulations has increased the cost of our drilling operations in the U.S. Gulf of Mexico.

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

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

In addition, we cannot predict how federal and state authorities will further respond to the Deepwater Horizon incident or whether additional changes in laws and regulations governing oil and gas operations in the U.S. Gulf of Mexico will result or how the DOI, BOEM, or BSEE will interpret or enforce the rules and regulations issued in response to the Deepwater Horizon incident. It is possible that additional laws, regulations or limitations may be imposed on us. Such regulations may require a change in the way we conduct our business, increase our costs of doing business, or delay our business plans. We cannot predict with any certainty what form any additional laws or regulations will take, how they will be interpreted or enforced, or the extent to which they may impact 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.

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 market our oil production 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 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 equipment, qualified personnel and capital, 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 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 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 have a limited operating history 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 oil 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. 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. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies, in establishing necessary staffing or personnel levels, or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that our drilling schedules are not completed, 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.

Investors in our common stock 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. In making a decision to invest in our common stock, you must be willing to rely to a significant extent on our management's discretion and judgment. A significant portion of our senior management and technical team's equity in us will vest in coming years or pursuant to their employment agreements. 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. If we are unable to retain or replace our employees and individual consultants as we grow our business, their loss 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.

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 2013, 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 would 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 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.

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 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, subject to certain extensions. In addition, most of our U.S. Gulf of Mexico blocks have a 10-year primary term, expiring between 2016 and 2020. Generally, we are required to commence exploration and production activities or successfully exploit our properties during the primary lease term in order for these leases to extend beyond the primary lease term. Should the prospects we have identified in this Annual Report on Form 10-K under the licenses 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. Historically, the oil markets have been volatile and will likely continue to be volatile in the future. The prices that we will receive for our production and the levels of our production 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, 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 oil properties are located in deepwater, which generally increases the capital and operating costs, technical challenges and risks associated with oil exploration and production activities. As a result, our oil exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil 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 oil 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 oil, 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 oil 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 oil. 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 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 oil, 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 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 properties 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.

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 supply. 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 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.

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, 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 requirements, our leases 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, 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 to increase significantly or eliminate financial liability caps for economic damages, 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 and proposed 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. Nazaki has repeatedly denied the allegations in writing. 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.

The adoption of The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, and the rules to be promulgated thereunder, could have an adverse effect on our business.

The Dodd-Frank Act requires, no later than 270 days after the enactment of the Dodd-Frank Act, the SEC to promulgate rules requiring SEC reporting companies that engage in the commercial development of oil, natural gas or minerals, to include in their annual reports filed with the SEC disclosure about all payments (including taxes, royalties, fees and other amounts) made by the issuer or an entity controlled by the issuer to the United States or to any non-U.S. government for the purpose of commercial development of oil, natural gas or minerals. The SEC has not yet promulgated these rules. Accordingly, as these rules are yet to be released and are not yet effective, we are unable to predict what form these rules may take and whether we will be able to comply with them without adversely impacting our business, or at all. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

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 became eligible for sale in the public market in late 2010, subject in certain circumstances to the volume, manner of sale 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.

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

Our four largest stockholders collectively own approximately 65% of our outstanding common stock. Consequently, 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.

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.

We are a "controlled company" within the meaning of the NYSE rules and, as a result, we qualify for and rely on exemptions from certain corporate governance requirements.

Funds affiliated with First Reserve Corporation, Goldman, Sachs & Co., Riverstone Holdings LLC and The Carlyle Group, and KERN Partners Ltd. and certain limited partners in such funds affiliated with KERN Partners Ltd., respectively, control a majority of the voting power of our outstanding common stock. Consequently we are a "controlled company" within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a "controlled company" and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

We are currently treated as a controlled company and utilize these exemptions, including the exemption for a board of directors composed of a majority of independent directors. In addition, although we have adopted charters for our audit, nominating and corporate governance and compensation committees and conduct annual performance evaluations for these committees, only the audit committee is presently composed entirely of independent directors. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.

Please refer to the information under the captions "Business—Deepwater U.S. Gulf of Mexico" and "Business—West Africa Deepwater" 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, 2012, the last reported sale price for our common stock on New York Stock Exchange was $32.00 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, 2012
First Quarter (through February 15, 2012)	$	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
Year ended December 31, 2010
Fourth Quarter	$	13.50	$	8.99
Third Quarter		10.01		7.00
Second Quarter		14.22		6.16
First Quarter		16.07		11.85

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, 2011.

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, 2011:

As of December 31, 2011, there were approximately 107 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.

To date, we have not paid any dividends since becoming a public company. 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 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.

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

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, 2011, 2010, 2009, 2008, and 2007 were derived from Cobalt International Energy, Inc.'s audited financial statements.

	Year Ended December 31,

	2011			2010			2009			2008			2007
	($ in thousands except per share data)
Oil and gas revenue	$	—		$	—		$	—		$	—		$	—
Operating costs and expenses
Seismic and exploration		32,239			45,030			30,666			41,274			86,813
Dry hole expense and impairment		45,732			44,178			14,486			—			—
General and administrative		59,130			48,063			35,996			31,271			23,090
Depreciation and amortization		735			787			622			683			435

Total operating costs and expenses		137,836			138,058			81,770			73,228			110,338

Operating income (loss)		(137,836	)		(138,058	)		(81,770	)		(73,228	)		(110,338	)
Other income (expense):
Interest income		4,199			1,582			513			1,632			1,384

Total other income (expense)		4,199			1,582			513			1,632			1,384

Net income (loss) before income tax		(133,637	)		(136,476	)		(81,257	)		(71,596	)		(108,954	)
Income tax expense (benefit)(1)(2)		—			—			—			—			—

Net income (loss)	$	(133,637	)	$	(136,476	)	$	(81,257	)	$	(71,596	)	$	(108,954	)

Basic and diluted income (loss) per common share	$	(0.35	)	$	(0.39	)
Weighted average number of common shares—basic and diluted		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,

	2011		2010		2009		2008		2007
	($ in thousands)
Cash and cash equivalents(1)	$	292,546	$	302,720	$	1,093,100	$	5,103	$	95,946
Short-term restricted cash		69,009		—		—		—		—
Short-term investments(2)		858,293		534,933		—		—		—
Total current assets		1,335,094		889,632		1,153,946		23,876		99,371
Total property, plant and equipment(3)		863,326		463,769		471,612		760,728		122,097
Long-term restricted cash		270,235		338,515		186,547		—		—
Long-term investments		47,232		40,003		—		—		—
Total assets		2,527,944		1,746,443		1,812,105		784,604		254,658
Total current liabilities(4)		238,069		24,559		70,523		44,133		10,785
Total long term liabilities(5)		210,961		2,850		—		—		—
Total partners' capital/stockholders' equity		2,078,914		1,719,034		1,741,582		740,471		243,873
Total liabilities and partners' capital/stockholders' equity		2,527,944		1,746,443		1,812,105		784,604		254,658

(1): 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 from December 31, 2010 to 2011 was attributed to the investments of the proceeds of $478.2 million from our public offering of common stock in April 2011.
(3): The increase from December 31, 2010 to 2011 reflects the acquisition costs of Block 20 offshore Angola. The decrease from December 31, 2008 to December 31, 2009 reflects the farm-out of the U.S. Gulf of Mexico lease interests to Total and Sonangol. The year-to-year variances from 2007 to 2008 represent additions to our lease inventory in the U.S. Gulf of Mexico and offshore Angola and Gabon.
(4): 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 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," "Business—How We Identify and Analyze Prospects" 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. As a result of our corporate reorganization in connection with our initial public offering, we are no longer required to pay monitoring fees to certain limited partnership interest holders pursuant to the terms of Cobalt International Energy, L.P.'s limited partnership agreement. These differences in general and administrative expenses are not reflected in our historical financial statements other than for fiscal years 2010 and 2009.

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
	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	)		(33.0	)%
Dry hole expense and impairment		23,323			44,178			(20,855	)		(47.2	)%
General and administrative		45,742			33,674			12,068			35.8	%
Depreciation and amortization		653			783			(130	)		(16.6	)%

Total operating costs and expenses		80,425			94,619			(14,194	)		(15.0	)%

Operating income (loss)		(80,425	)		(94,619	)		(14,194	)		(15.0	)%
Other income (expense)
Interest income (expense), net		4,194			1,582			2,612			165.1	%

Total other income (expense)		4,194			1,582			2,612			165.1	%

Net income (loss) before income tax		(76,231	)		(93,037	)		(16,806	)		(18.1	)%
Income tax expense (benefit)		—			—			—			—

Net income (loss)	$	(76,231	)	$	(93,037	)	$	(16,806	)		(18.1	)%

*West Africa Segment:*
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		21,532			29,046			(7,514	)		(25.9	)%
Dry hole expense and impairment		22,409			—			22,409			—
General and administrative		13,388			14,389			(1,001	)		(7.0	)%
Depreciation and amortization		82			4			78			1950.0	%

Total operating costs and expenses		57,411			43,439			13,972			32.2	%

Operating income (loss)		(57,411	)		(43,439	)		13,972			32.2	%
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			32.2	%
Income tax expense (benefit)		—			—			—			—

Net income (loss)	$	(57,406	)	$	(43,439	)	$	13,967			32.2	%

*Consolidated Operations:*
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		32,239			45,030		$	(12,791	)		(28.4	)%
Dry hole expense and impairment		45,732			44,178			1,554			3.5	%
General and administrative		59,130			48,063			11,067			23.0	%
Depreciation and amortization		735			787			(52	)		(6.6	)%

Total operating costs and expenses		137,836			138,058			(222	)		(0.2	)%

Operating income (loss)		(137,836	)		(138,058	)		(222	)		(0.2	)%
Other income (expense)
Interest income (expense), net		4,199			1,582			2,617			165.4	%

Total other income (expense)		4,199			1,582			2,617			165.4	%

Net income (loss) before income tax		(133,637	)		(136,476	)		(2,839	)		(2.1	)%
Income tax expense (benefit)		—			—			—			—

Net income (loss)	$	(133,637	)	$	(136,476	)	$	(2,839	)		(2.1	)%

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 was due to the net effect of (i) an $8.2 million charge for the Criollo #1 exploratory well representing amounts previously suspended pending further evaluation, (ii) a $6.0 million charge against the Heidelberg #2 appraisal well, and (iii) an allowance of $9.1 million against future impairment on the carrying value of our unproved leasehold properties that are individually less than $1 million during the year ended December 31, 2011, which were offset by (iv) an $8.4 million charge against the Criollo #1 exploratory well, (v) an $11.1 million charge against the Heidelberg #2 appraisal well, (vi) a $12.5 million charge against the Firefox #1 exploratory well, (vii) a $0.1 million charge for the Ligurian #1 exploratory well, (viii) a $2.9 million expense for pre-spud costs related to the North Platte #1 exploratory well, and (ix) a $9.2 million valuation allowance against future impairment on the carrying value of our unproved leasehold properties that are individually less than $1 million during the year ended December 31, 2010.

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.

	Year Ended December 31,

	Year Ended December 31,						Increase (Decrease)			Percentage Change
	2010			2009			Increase (Decrease)			Percentage Change
	($ in thousands)
*U.S. Gulf of Mexico Segment:*
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		15,984			8,793			7,191			81.8	%
Dry hole expense and impairment		44,178			14,486			29,692			205.0	%
General and administrative		33,674			35,934			(2,260	)		(6.3	)%
Depreciation and amortization		783			622			161			25.9	%

Total operating costs and expenses		94,619			59,835			34,784			58.1	%

Operating income (loss)		(94,619	)		(59,835	)		34,784			58.1	%
Other income (expense)
Interest income (expense), net		1,582			513			1,069			208.4	%

Total other income (expense)		1,582			513			1,069			208.4	%

Net income (loss) before income tax		(93,037	)		(59,322	)		33,715			56.8	%
Income tax expense (benefit)		—			—			—			—

Net income (loss)	$	(93,037	)	$	(59,322	)	$	33,715			56.8	%

*West Africa Segment:*
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		29,046			21,873			7,173			32.8	%
Dry hole expense and impairment		—			—			—			—
General and administrative		14,389			62			14,327			23108.1	%
Depreciation and amortization		4			—			4			—

Total operating costs and expenses		43,439			21,935			21,504			98.0	%

Operating income (loss)		(43,439	)		(21,935	)		21,504			98.0	%
Other income (expense)
Interest income (expense), net		—			—			—			—

Total other income (expense)		—			—			—			—

Net income (loss) before income tax		(43,439	)		(21,935	)		21,504			98.0	%
Income tax expense (benefit)		—			—			—			—

Net income (loss)	$	(43,439	)	$	(21,935	)	$	21,504			98.0	%

*Consolidated Operations:*
Oil and gas revenue	$	—		$	—		$	—			—	%
Operating costs and expenses
Seismic and exploration		45,030			30,666			14,364			46.8	%
Dry hole expense and impairment		44,178			14,486			29,692			205.0	%
General and administrative		48,063			35,996			12,067			33.5	%
Depreciation and amortization		787			622			165			26.5	%

Total operating costs and expenses		138,058			81,770			56,288			68.8	%

Operating income (loss)		(138,058	)		(81,770	)		56,288			68.8	%
Other income (expense)
Interest income (expense), net		1,582			513			1,069			208.4	%

Total other income (expense)		1,582			513			1,069			208.4	%

Net income (loss) before income tax		(136,476	)		(81,257	)		55,219			67.9	%
Income tax expense (benefit)		—			—			—			—

Net income (loss)	$	(136,476	)	$	(81,257	)	$	55,219			67.9	%

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, 2010 and 2009.

Operating costs and expenses. Our operating costs and expenses for the U.S. Gulf of Mexico operations consisted of the following during the years ended December 31, 2010 and 2009:

Seismic and exploration. Seismic and exploration costs increased by approximately $7.2 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009. The increase in seismic and exploration costs during 2010 was primarily due to (i) $13.5 million in force majeure expenses related to the drilling rig and other equipment and services which were to be used to drill the North Platte #1 exploratory well that was suspended as a result of the Deepwater Horizon incident and (ii) a $0.9 million increase in costs to ensure that the Ensco 8503 drilling rig meets the regulatory requirements for drilling in the U.S. Gulf of Mexico during the year ended December 31, 2010 which were offset by a $7.2 million decrease in seismic and exploration costs for past seismic costs charged to West Africa for recovery from partners.

Dry hole expense and impairment. Dry hole expense and impairment increased by $29.7 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009. The increase was due to the net effect of (i) a $0.1 million charge against the Ligurian #1 exploratory well, (ii) an $8.4 million charge against the Criollo #1 exploratory well, (iii) an $11.1 million charge against the Heidelberg #2 appraisal well, (iv) a $12.5 million charge against the Firefox #1 exploratory well, (v) $2.9 million in pre-spud costs for the North Platte #1 exploratory well, and (vi) a $9.2 million valuation allowance against future impairment on the carrying value of our unproved leasehold properties that are individually less than $1 million during the year ended December 31, 2010, which were offset by (vii) a $10.5 million charge against the Ligurian #1 exploratory well and (viii) a $4.0 million charge against the Criollo #1 exploratory well during the year ended December 31, 2009. No allowance against future impairment on the carry value of our unproved leasehold properties were recorded for the year ended December 31, 2009.

General and administrative. General and administrative costs decreased by $2.3 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009. The decrease in general and administrative costs during 2010 was primarily attributed to an $8.2 million increase in costs related to equity-based compensation, an increase of $2.1 million in consultant and contractor fees, an increase of $2.5 million in insurance-related expenses, and an increase of $1.4 million in office-related support expenses, which were offset by a decrease of $2.6 million in fees paid prior to our initial public offering and an decrease of $13.9 million in reimbursement of our general and administrative costs from our partners in the U.S. Gulf of Mexico and West Africa during the year ended December 31, 2010.

Depreciation and amortization. Depreciation and amortization did not change significantly during the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Other income. Other income increased by $1.1 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase of $1.1 million was primarily due to interest recognized on investment securities during the year ended December 31, 2010.

Income taxes. As a result of net operating losses, for income tax purposes, we recorded a net deferred tax asset of $97.6 million and $28.9 million with a corresponding full valuation of $97.6 million and $28.9 million for the years ended December 31, 2010 and for period from December 15-31, 2009, 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, 2010 and 2009.

Operating costs and expenses. Our operating costs and expenses for the West Africa operations consisted of the following during the years ended December 31, 2010 and 2009:

Dry hole expense and impairment. There was no dry hole expense and impairment during the years ended December 31, 2010 and 2009.

General and administrative. General and administrative costs increased by $14.3 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009. The increase in general and administrative costs during 2010 was primarily attributed to a $4.3 million increase in social obligations for Blocks 9 and 21, a $7.7 million increase for past general and administrative costs from U.S. Gulf of Mexico operations and a $2.3 million increase for operating costs related to our Angola offices.

Depreciation and amortization. Depreciation and amortization did not change significantly during the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Other income. There was no other income for the West Africa operations during the years ended December 31, 2010 and 2009.

Income taxes. The net operating losses in our West Africa operations for the years ended December 31, 2010 and 2009 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. We do not know how long it will take to achieve substantial production from our oil properties. With respect to our Cameia pre-salt oil discovery, we are currently preparing the development schedule and do not have an estimate of first oil and cash flow at this time. With respect to our non-operated U.S. Gulf of Mexico discoveries, we are unable to provide information with respect to the operator's development schedule and estimates of first oil and cash flow at this time. Until substantial production is achieved, our primary sources of liquidity are expected to be cash on hand, amounts paid pursuant to the terms of our Total alliance and funds from future equity and debt financings, asset sales and farm-out arrangements.

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

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, 2011, we had approximately $1.5 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 $550 to $650 million for our ongoing operations and general corporate purposes in 2012, which includes the approximate $123 million we funded in January 2012 to satisfy our initial obligations under the Block 20 PSC. Our full year 2011 expenditures were approximately $194 million. We expect that our existing cash on hand will be sufficient to fund our planned exploration and appraisal drilling program at least through the end of 2013. 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 $57.8 million used in operating activities during 2011 was primarily related to cash payments for seismic expenses, consultants and contractors for West Africa operations and staff costs. The increase in net cash used in 2010 compared to 2009 was 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 the Deepwater Horizon incident and expenses incurred relating to mobilization of the Ensco 8503 drilling rig, which were offset by the receipt of approximately $15.1 million from our partner in West Africa for reimbursement of past seismic data expenditures and general and administrative charges. The net cash used in operating activities during 2009 was primarily related to cash payments for seismic expenses in the U.S. Gulf of

Mexico, which was offset by the receipt of approximately $10.0 million from a partner in the U.S. Gulf of Mexico for reimbursement of past seismic data expenditures.

Investing activities. Net cash used in investing activities in 2011 was approximately $430.4 million, compared with net cash used in investing activities of approximately $758.4 million and net cash provided by investing activities of approximately $87.1 million in 2010 and 2009, respectively. The net cash used in 2011 primarily relates to investment of the net proceeds from our public offering of common stock in April 2011 and 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. The decrease in net cash used in 2009 was primarily attributed to proceeds received in 2009 totaling approximately $333.3 million for the sale of leasehold interests in the U.S. Gulf of Mexico, which was offset by an increase in restricted cash to guarantee the Ensco 8503 rig contract and an increase in exploratory well investment.

Financing activities. Net cash provided by financing activities in 2011 was approximately $478.0 million, compared with net cash provided by financing activities of approximately $101.3 and $1,076 million in 2010 and 2009, respectively. The increase in net cash provided by financing activities in 2011 compared to 2010 was attributed to the net proceeds we received from our public offering of common stock in April 2011. The decrease in net cash provided by financing activities in 2010 compared to 2009 was primarily attributed to the proceeds we received from our initial public offering in December 2009. In January 2010, we received net proceeds of approximately $101.3 million from the underwriters' exercise of their over-allotment option in connection with our initial public offering. The increase in net cash provided by financing activities in 2009 was attributed to cash received from Cobalt International Energy, L.P.'s Class A limited partnership interest holders and the net proceeds of approximately $856.1 million from the initial public offering and sale of 3,125,000 shares of common stock pursuant to Regulation S, which closed on December 21, 2009.

As of December 31, 2011, our contractual obligations were limited to payments to be made in connection with the leases related to the Ensco 8503 and Diamond Ocean Confidence drilling rigs and other related drilling contracts, office lease payments and lease rental payments for exploration rights from the BOEM for further exploration in the western and central U.S. Gulf of Mexico and social payment obligations for Blocks 9, 20 and 21, offshore West Africa. The following table summarizes by period the payments due for our estimated contractual obligations as of December 31, 2011:

In the future, we may be party to the following contractual arrangements, 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, 2011, 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 and the credit ratings of the issuers of these 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 guidance of Accounting Standards Codification (ASC) No. 320, 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 lower of cost or market. 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 FASB ASC No. 740, "Income Taxes" as clarified by FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, "Accounting for 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 (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, 2011, 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. 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 FASB ASC No. 410-20, "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 nonvested restricted shares outstanding during the periods presented, unless their effect is 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, 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 and interest rates. 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, 2011, 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, 2011.

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, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 "2012 Proxy Statement") for our annual meeting of stockholders to be held on April 26, 2012, 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 2012 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 2012 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 2012 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 2012 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"		A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed the related oil and natural gas operating expenses and taxes.
"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.
"Gas-oil ratio"		The ratio of the volume of gas that comes out of solution from the volume of oil at standard conditions (expressed in standard cubic feet per barrel of oil).
"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.
"Mean net area"		The estimated mean aerial extent of a hydrocarbon-bearing rock (expressed in acres) to which we hold a license or leasehold title.
"Mud"		Mud is a term that is generally synonymous with drilling fluid and that encompasses most fluids used in hydrocarbon drilling operations, especially fluids that contain significant amounts of suspended solids, emulsified water or oil.
"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.
"Probable reserves"		Oil and gas whose existence is not proven by geological information but is probably present due to proximity to proved reserves and can be produced if located. Probable reserves are less accurate than proved reserves.
"Producing well"		A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
"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.
"Protraction area"		An offshore area in the U.S. Gulf of Mexico defined by a series of blocks.
"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.


"Secondary recovery"		An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.
"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))

9.1	*	Stockholders Agreement, dated December 15, 2009, among the Company and the stockholders that are signatory thereto.

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))

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))

		Description of Document

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	†	Long Term Incentive Plan of the Company (incorporated by reference to Exhibit 99.1 to the Company's Registration Statement on Form S-8 filed December 21, 2009 (File No. 333-163883))

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.

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		Termination and Release of Irrevocable Contract Guarantee, dated December 9, 2009, between Ensco Offshore Company and the Guarantors named therein (incorporated by reference to Exhibit 10.25 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579)).

10.23	†	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)).

10.24	†	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)).

10.25	†	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)).

		Description of Document

10.26		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)).

10.27		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)).

10.28	†	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)).

10.29	†	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))

10.30	*	Severance Agreement, dated April 1, 2010, between the Company and Michael D. Drennon.

10.31	*	Registration Rights Agreement, dated December 15, 2009, among the Company and the parties 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, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011 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, 2011, 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, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2011 consolidated financial statements of Cobalt International Energy, Inc. (a development stage enterprise) and our report dated February 20, 2012 expressed an unqualified opinion thereon.

We have audited the accompanying consolidated balance sheets of Cobalt International Energy, Inc. (a development stage enterprise) (the "Company") as of December 31, 2011 and 2010, 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, 2011 and for the period November 10, 2005 (inception) through December 31, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 and for the period November 10, 2005 (inception) through December 31, 2011 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, 2011, 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 20, 2012 expressed an unqualified opinion thereon.

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

Consolidated Balance Sheets

	December 31,

	2011			2010
	($ in thousands, except per share data)
Assets
Current assets:
Cash and cash equivalents	$	292,546		$	302,720
Joint interest and other receivables		56,983			8,237
Prepaid expenses and other current assets		22,214			9,004
Inventory		36,049			34,738
Short-term restricted cash		69,009			—
Short-term investments		858,293			534,933

Total current assets		1,335,094			889,632
Property, plant, and equipment:
Oil and gas properties, successful efforts method of accounting, net of accumulated depletion of $0		861,955			462,500
Other property and equipment, net of accumulated depreciation and amortization of $3,555 and $2,820, as of December 31, 2011 and 2010, respectively		1,371			1,269

Total property, plant, and equipment, net		863,326			463,769

Long-term restricted cash		270,235			338,515
Long-term investments		47,232			40,003
Other assets		12,057			14,524

Total assets	$	2,527,944		$	1,746,443

Liabilities and Partners' Capital/Stockholders' Equity
Current liabilities:
Trade and other accounts payable	$	71,186		$	11,989
Accrued liabilities		34,418			9,120
Short-term contractual obligations		132,465			3,450

Total current liabilities		238,069			24,559

Long-term contractual obligations		210,961			2,850
Stockholders' equity:
Common stock, $0.01 par value per share; 2,000,000,000 shares authorized 387,531,630 and 350,733,998 issued and outstanding as of December 31, 2011 and 2010, respectively		3,875			3,507
Additional paid-in capital		2,719,875			2,226,726
Accumulated deficit during the development stage		(644,836	)		(511,199	)

Total stockholders' equity		2,078,914			1,719,034

Total liabilities and stockholders' equity	$	2,527,944		$	1,746,443

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

Consolidated Statements of Operations

										For the Period November 10, 2005 (Inception) Through December 31, 2011

	Year Ended December 31
	2011			2010			2009
	($ in thousands except per share data)
Oil and gas revenue	$	—		$	—		$	—		$	—
Operating costs and expenses:
Seismic and exploration		32,239			45,030			30,666			328,840
Dry hole expense and impairment		45,732			44,178			14,486			104,396
General and administrative		59,130			48,063			35,996			217,980
Depreciation and amortization		735			787			622			3,555

Total operating costs and expenses		137,836			138,058			81,770			654,771

Operating income (loss)		(137,836	)		(138,058	)		(81,770	)		(654,771	)
Other income (expense):
Interest income, net		4,199			1,582			513			9,935

Total other income (expense)		4,199			1,582			513			9,935

Net income (loss) before income tax		(133,637	)		(136,476	)		(81,257	)		(644,836	)
Income tax expense		—			—			—			—

Net income (loss)	$	(133,637	)	$	(136,476	)	$	(81,257	)	$	(644,836	)

Basic and diluted income (loss) per share	$	(0.35	)	$	(0.39	)

Pro forma basic and diluted income (loss) per share (unaudited)							$	(0.33	)

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

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

	General Partner		Class A Limited Partners			Class B Limited Partners			Class C Limited Partners			Common Stock			Additional Paid-in Capital			Accumulated Deficit During Development Stage			Total

	($ in thousands)
Balance, November 10, 2005 (inception)	$	—	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Class A limited partners' contributions		—		3,000			—			—			—			—			—			3,000
Class B limited partners' equity compensation		—		—			142			—			—			—			—			142
Net income (loss)		—		—			—			—			—			—			(1,389	)		(1,389	)

Balance, December 31, 2005		—		3,000			142			—			—			—			(1,389	)		1,753
Class A limited partners' contributions		—		154,984			—			—			—			—			—			154,984
Class B limited partners' equity compensation		—		—			1,350			—			—			—			—			1,350
Net income (loss)		—		—			—			—			—			—			(111,527	)		(111,527	)

Balance, December 31, 2006		—		157,984			1,492			—			—			—			(112,916	)		46,560
Class A limited partners' contributions		—		305,135			—			—			—			—			—			305,135
Class B limited partners' equity compensation		—		—			1,132			—			—			—			—			1,132
Net income (loss)		—		—			—			—			—			—			(108,954	)		(108,954	)

Balance, December 31, 2007		—		463,119			2,624			—			—			—			(221,870	)		243,873
Class A limited partners' contributions		—		566,453			—			—			—			—			—			566,453
Class B limited partners' equity compensation		—		—			1,741			—			—			—			—			1,741
Net income (loss)		—		—			—			—			—			—			(71,596	)		(71,596	)

Balance, 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 vested 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 vested restricted stock		—		—			—			—			12			(12	)		—			—
Equity based compensation		—		—			—			—			—			15,505			—			15,505
Repurchase of common stock		—		—			—			—			(1	)		(190	)		—			(191	)
Net income (loss)		—		—			—			—			—			—			(133,637	)		(133,637	)

Balance, December 31, 2011	$	—	$	—		$	—		$	—		$	3,875		$	2,719,875		$	(644,836	)	$	2,078,914

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

Consolidated Statements of Cash Flows

										For the Period November 10, 2005 (Inception) Through December 31, 2011

	Year Ended December 31
	2011			2010			2009
	($ In thousands)
Cash flows provided from operating activities
Net income (loss)	$	(133,637	)	$	(136,476	)	$	(81,257	)	$	(644,836	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization		735			787			622			3,555
Dry hole expense and impairment of unproved properties		45,732			44,178			14,486			104,396
Equity based compensation		15,505			12,672			5,755			38,298
Amortization of premium (accretion of discount) on investment securities		22,082			1,608			—			25,687
Other		—			—			503			1,631
Changes in operating assets and liabilities:
Joint interest and other receivables		(59,515	)		31,266			(38,967	)		(69,485	)
Inventory		(1,621	)		(28,047	)		4,981			(36,359	)
Prepaid expense and other assets		(10,742	)		(14,126	)		(3,373	)		(34,271	)
Trade and other accounts payable		59,196			(22,977	)		16,314			71,130
Accrued liabilities and other		4,470			(22,149	)		5,450			40,721

Net cash provided by (used in) operating activities		(57,795	)		(133,264	)		(75,486	)		(499,533	)

Cash flows from investing activities
Capital expenditures for oil and gas properties		—			(1,746	)		(14,250	)		(704,107	)
Capital expenditures for other property and equipment		(782	)		(1,185	)		(537	)		(4,871	)
Exploratory wells drilling in process		(86,979	)		(32,585	)		(45,424	)		(264,885	)
Proceeds from sale of oil and gas properties		—			5,656			333,346			339,001
Change in restricted cash		(541	)		(151,527	)		(186,012	)		(338,578	)
Proceeds from maturity of investment securities		1,288,067			224,985			—			1,514,830
Purchase of investment securities		(1,630,156	)		(801,970	)		—			(2,434,206	)

Net cash provided by (used in) investing activities		(430,391	)		(758,372	)		87,123			(1,892,816	)

Cash flows from financing activities
Capital contributions prior to IPO—Class A limited partners		—			—			226,913			1,256,180
Proceeds from initial public offering, net of costs		—			101,256			849,447			950,703
Proceeds from public offering, net of costs		478,203			—			—			478,203
Repurchase of common stock		(191	)		—			—			(191	)

Net cash provided by (used in) financing activities		478,012			101,256			1,076,360			2,684,895

Net increase (decrease) in cash and cash equivalents		(10,174	)		(790,380	)		1,087,997			292,546
Cash and cash equivalents, beginning of period		302,720			1,093,100			5,103			—

Cash and cash equivalents, end of period	$	292,546		$	302,720		$	1,093,100		$	292,546

Non-Cash Disclosures
Capital expenditures in liabilities	$	357,900		$	2,011		$	4,628		$	357,900

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

Notes to Consolidated Financial Statements

December 31, 2011 and 2010

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. 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. On April 15, 2011, the Company completed a registered underwritten public offering of 35,650,000 shares of its common stock at a public offering price of $14.00 per share, resulting in net proceeds to the Company of $478.2 million. The proceeds from these offerings of common stock have been and will be used to fund the Company's drilling and exploration program.

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 a world-class below salt prospect inventory in the deepwater of the U.S. Gulf of Mexico and offshore Angola and Gabon in West Africa. All of its prospects are oil-focused. In the U.S. Gulf of Mexico, the Company has drilled as operator two exploratory wells (Ligurian #1 and Criollo #1) and participated as non-operator in three exploratory wells (Heidelberg #1, Shenandoah #1 and Firefox #1) and two appraisal wells (Heidelberg #2 and Heidelberg #3). These drilling efforts have resulted in the Heidelberg and Shenandoah oil discoveries. The Company is currently drilling as operator the Ligurian #2 exploratory well. Offshore Angola, the Company has drilled as operator the Cameia #1 exploratory well on Block 21 which resulted in the Cameia pre-salt oil discovery. The Company continues to mature high impact prospects in its portfolio for upcoming exploratory drilling in both the deepwater of

the U.S. Gulf of Mexico and the deepwater offshore Angola and Gabon. The Company has two geographic operating 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 FASB Accounting Standards Codification (ASC) No. 915 "Development Stage Entities."

At December 31, 2011, 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.

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 (c) assumptions used in impairment testing. Although the Company believes these estimates are reasonable, actual results could differ from these estimates.

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, 2011 and 2010, 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 and believes that the credit risk is minimal.

Restricted cash 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.

In 2010, the Company adopted a policy on accounting for its investments, which consist entirely of debt securities, based on the guidance of Accounting Standards Codification No. 320, 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, which approximates fair market value as of December 31, 2011 and 2010. Income related to these securities is reported as a component of interest income in the Company's consolidated statements of operations. See Note 8—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, 2011 and 2010, 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. 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 FASB ASC No. 410-20, "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 lower cost or market. 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 FASB ASC No. 740, "Income Taxes" as clarified by FASB Interpretation No. 48 ("FIN 48"), Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, "Accounting for 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 16.

The Company accounts for stock-based compensation at fair value. The Company grants various types of stock-based awards including stock options, restricted stock and performance-based awards. The fair value of stock option awards is determined using the Black-Scholes-Merton option-pricing model. For restricted stock awards with market conditions, the fair value of the awards is measured using the asset-or-nothing option pricing model. Restricted stock awards without market conditions and the performance-based awards are valued using the market price of the Company's common stock on the grant date. The Company records compensation cost, net of estimated forfeitures, for stock-based compensation awards over the requisite service period except for performance-based awards. For performance-based awards, compensation cost is recognized over the requisite service period as and when the Company determines that the achievement of the performance condition is probable, using the per-share fair value measured at grant date. See Note 14.

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.

The Company's financial instruments consist of cash and cash equivalents, joint interest and other receivables, investments and restricted cash. The fair value of these instruments approximates carrying values due to their short-term duration. The Company's long-term investments do not exceed two years. See Note 5—Restricted Cash and Note 8—Investments, for a discussion of the carrying value and fair value of the Company's investments in held-to-maturity securities.

As of December 31, 2011 and 2010, cash and cash equivalents consisted of the following:

(2): $151.3 million was held in a collateral account established in March 2010 as collateral for letters of credit issued in support of the Company's contractually agreed work program obligations on Blocks 21 and 9 offshore Angola. In April 2011, the collateral was reduced by approximately $10.0 million following the completion of the seismic phase of the work program obligations for Block 9 offshore Angola. During the year ended December 31, 2011, the Company reclassified $53.3 million from long-term restricted cash to short term restricted cash as this amount represents the work program obligations for two wells on Block 21 offshore Angola that are expected to be drilled within the next twelve months. As of December 31, 2011, the short-term and long-term collateral in this account was invested in U.S. Treasury bills and U.S. government guaranteed corporate bonds, purchased at discounts and at premiums, respectively, resulting in a net carrying value of $141.7 million. The contractual maturities of these securities are within one year.
(3): $186.0 million was held in an escrow account established in December 2009 as a guarantee of performance to Ensco Offshore Company for the Ensco 8503 drilling rig contract. The Company reclassified $4.9 million from long-term restricted cash to short-term restricted cash as this amount represents the standby rates for the Ensco 8503 drilling rig to be paid out of the escrow account sometime in early 2012. As of December 31, 2011, the short-term and long-term funds in the escrow account were invested in U.S. Treasury bills and Treasury notes, purchased at a discount and at a premium, respectively, resulting in a net carrying value of $179.5 million and in a money market fund with a carrying value of $6.5 million. The contractual maturities of the U.S. Treasury bills and Treasury notes are within six months.

As of December 31, 2011 and 2010, 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, 2011 and 2010, prepaid expenses and other current assets were $22.2 million and $9.0 million, respectively.

The Company's investments in held-to-maturity securities which are stated at amortized cost, the approximate fair market value of which were as follows at December 31, 2011 and 2010:

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, 2011 and 2010 were as follows:

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)		2011			2010
			($ in thousands)
Oil and Gas Properties:
Unproved oil and gas properties			$	701,892		$	364,766
Less: accumulated valuation allowance				(18,275	)		(9,147	)

				683,617			355,619
Exploratory wells in process				178,338			106,881

Total oil and gas properties, net				861,955			462,500
Other Property and Equipment:
Computer equipment and software		3		2,847			2,300
Office equipment and furniture		3		1,114			1,047
Vehicles		3		129			76
Leasehold improvements		3		836			666

				4,926			4,089
Less: accumulated depreciation and amortization				(3,555	)		(2,820	)

Total other property and equipment, net				1,371			1,269

Property, plant, and equipment, net			$	863,326		$	463,769

The Company recorded $0.7 million, $0.8 million, $0.6 million and $3.6 million of depreciation and amortization expense for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (inception) through December 31, 2011, 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. In addition to the Block 20 interests, the Company has $10.8 million of unproved property acquisition costs relating to 40% interests in Blocks 9 and 21 offshore Angola and Gabon. No significant impairment of these properties has been recognized since the Company intends to continue exploration and development of these properties. The Company also has $325.7 million of unproved property acquisition costs, net of valuation allowance, relating to properties offshore Gulf of Mexico. As of December 31, 2011 and 2010, the Company has a net total of $683.6 million and $355.6 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. Significant unproved leases are assessed individually for impairment based on the

Company's current exploration plans and an allowance is provided if impairment is indicated. Unproved leasehold costs for properties offshore U.S. Gulf of Mexico that are individually less than $1.0 million in carrying value 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, 2011 and 2010, the balance for unproved leaseholds that were individually less than $1.0 million before impairment provision was $65.1 million and $65.1 million, respectively. For the years ended December 31, 2011, 2010, 2009 and for the period November 10, 2005 (inception) through December 31, 2011, the Company recorded $9.1 million, $9.1 million, $0 million and $18.2 million, respectively, as amortized expense on its unproved leasehold properties.

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,

	2011			2010
	($ in thousands)
Beginning of year	$	106,881		$	107,226
Addition to capitalized exploratory well cost pending determination of proved reserves
U.S. Gulf of Mexico:
Shenandoah #1 Exploratory Well		(53	)		176
Heidelberg #1 Exploratory Well		—			8
Heidelberg #2 Appraisal Well		5,999			10,854
Heidelberg #3 Exploratory Well		4,056			—
Ligurian #1 Exploratory Well		—			86
Ligurian #2 Exploratory Well pre-spud costs		2,034			—
Criollo #1 Exploratory Well		(822	)		8,171
Firefox #1 Exploratory Well		—			12,463
Other pre-spud costs		—			2,839
West Africa:
Bicuar #1 Exploratory Well costs		25,444			—
Cameia #1 Exploratory Well costs		71,405			—
Reclassifications to wells, facilities, and equipment based on determination of proved reserves		—			—
Amounts charged to expense(1)		(36,606	)		(34,942	)

End of year	$	178,338		$	106,881

			December 31,

	Year Drilled		December 31,
	Year Drilled		2011		2010
			($ in thousands)
Cumulative costs:
Shenandoah #1 Exploratory Well		2008		69,468	$	69,521
Heidelberg #1 Exploratory Well		2008		20,240		20,240
Ligurian #1 Exploratory Well		2009		8,100		8,100
Criollo #1 Exploratory Well		2009		—		9,020
Ligurian #2 Exploratory Well pre-spud costs		2011		2,034		—
Heidelberg #3 Exploratory Well		2011		4,056		—
Bicuar #1 Exploratory Well		2011		3,035		—
Cameia #1 Exploratory Well		2011		71,405		—

			$	178,338	$	106,881

Exploratory Well costs capitalized for a period greater than one year after completion of drilling at December 31, 2011 and 2010 (included in table above)			$	97,861	$	106,881

Capitalized exploratory well costs that have been suspended longer than one year are associated with the Shenandoah #1, Heidelberg #1 and Ligurian #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, 2011, no exploratory wells have been drilled by the Company offshore Gabon.

Costs associated with the mobilization and equipment upgrades of the Ensco 8503 drilling rig and subsea containment were deferred in other assets. The Company will amortize these costs to respective exploratory wells as and when the rig is used for drilling activities over the term of the drilling contract. These costs will be expensed or capitalized to oil and gas properties as exploratory drilling costs, depending on the drilling results. As of December 31, 2011 and 2010, no amortization on these costs was recorded since the Ensco 8503 drilling rig did not commence drilling activities until January 2012. As of December 31, 2011 and 2010, the accumulated costs associated with the Ensco 8503 drilling rig and subsea containment in other assets were $12.1 million and $14.5 million, respectively.

	December 31,

	2011		2010
	($ in thousands)
Short-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	1,300	$	1,150
Social obligation payments for Block 21, offshore Angola		2,600		2,300
Social obligation and bonus payments for Block 20, offshore Angola(1)		128,565		—

	$	132,465	$	3,450

Long-term Contractual Obligations:
Social obligation payments for Block 9, offshore Angola	$	800	$	950
Social obligation payments for Block 21, offshore Angola		1,600		1,900
Social obligation and bonus payments for Block 20, offshore Angola		208,561		—

	$	210,961	$	2,850

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.

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.

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, 2011, approximately 9.4 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, 2011, 600,719 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 the period from the Company's corporate reorganization on December 15, 2009 to December 31, 2011:

	Years Ended December 31,

	2011					2010					2009
	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		5,570,895		$	9.77		8,015,041		$	7.67		9,113,772		$	0.32
Granted pre-reorganization		—			—		—			—		1,043,507		$	20.86
Granted post-reorganization		214,792		$	8.54		442,156		$	9.96		3,705,425		$	11.71
Vested		(1,185,904	)	$	3.75		(2,213,277	)	$	0.51		(5,356,756	)	$	0.25
Forfeited or expired		—			—		(673,025	)	$	15.35		(490,907	)	$	0.31

Non-vested shares at end of year		4,599,783		$	11.27		5,570,895		$	9.77		8,015,041		$	7.67

Weighted-average period remaining		2.5 years					3.3 years					3.2 years

Unrecognized compensation ($ in thousands)	$	29,559				$	41,599				$	63,371

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.

During the year ended December 31, 2011, the Company granted 51,620 restricted stock units to non-employee directors and also granted 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. As of December 31, 2011, there were 51,620 nonvested shares relating to non-employee directors and a total of $0.3 million of unrecognized compensation cost, all of which will be recognized during 2012. The weighted average fair value of these shares at grant date was $13.56.

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 and vest ratably over a four-year period from date of grant. There were no non-qualified stock options granted prior to December 3, 2010.

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 3, 2010 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, 2011 is presented below:

The weighted-average grant-date fair value of stock options granted during 2011 and 2010 was $0 and $6.78 per option, respectively, using the Black-Scholes option-pricing model. No stock options were exercised during 2011. As of December 31, 2011, there were 1,133,960 shares of common stock underlying outstanding stock options. As of December 31, 2011, $5.4 million of total unrecognized

compensation cost related to stock option is expected to be recognized over a weighted-average period of 2.92 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%. No payout in the form of the RSUs will be made if the number of successful wells drilled between January 1, 2011 and December 31, 2013 divided by the total wells spud during the same period is less than 20%. 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 awards is determined by the closing price of the Company's common stock at the date of grant, which was $12.45 per share, in accordance with ASC No. 718, Compensation—Stock Compensation. Compensation cost will be recognized as and when the performance condition is satisfied. Until such time when the Company completes drilling a well in the U.S. Gulf of Mexico and/or completes drilling and evaluation of a well offshore Angola in 2012, the Company will be unable to determine the probability of successful wells drilled. As a result, no compensation cost was recognized for the years ended December 31, 2011 and 2010 for these awards. As of December 31, 2011 and 2010, unrecognized compensation cost related to restricted stock units ranged from $2.5 million to $5.0 million.

The table below summarizes the equity-based compensation costs recognized for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (inception) through December 31, 2011:

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 the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (inception) through December 31, 2011, the Company recorded $0, $0, $0.5 million and $1.4 million, respectively, in benefits contributions to the Plan, which are included in the general and administrative expenses.

For the years ended December 31, 2011 and 2010, the Company recorded a net deferred tax asset of $177.2 million and $97.6 million, respectively with a corresponding full valuation allowance of $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. Prior to its corporate reorganization on December 15, 2009, 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. At the time of the corporate reorganization, the Company recorded a net deferred tax asset of $28.9 million with a corresponding full valuation allowance of $28.9 million for book/tax differences contributed to the corporation by the underlying partners.

The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company's income tax expense (benefit) for the year ended December 31, 2011 and 2010 and for the period from December 15, 2009 through December 31, 2009 are as follows:

	Year Ended December 31,

	Year Ended December 31,										Period from December 15-31, 2009
	2011					2010					Period from December 15-31, 2009
	($ in thousands)
Income tax expense (benefit) at the federal statutory rate	$	(46,773	)	35.00	%	$	(47,767	)	35.00	%	$	(12,114	)	35.00	%
State income taxes, net of federal income tax benefit		(2,579	)	1.93	%		(339	)	0.25	%		—		—
Foreign NOL(1)		(30,407	)	22.75	%		—		—			—		—
Deferred income taxes established at date of corporate reorganization(2)		—		—			(8,735	)	6.33	%		(28,867	)	83.40	%
Other		117		0.08	%		176		0.13	%		86		0.25	%
Valuation allowance		79,642		59.60	%		56,665		41.45	%		40,895		118.15	%

	$	—		—		$	—		—		$	—		—

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,

	2011			2010
	($ in thousands)
Deferred tax liabilities:
Oil and gas properties	$	4,555		$	8,084
Other		452			666

Total deferred tax liabilities		5,007			8,750

Deferred tax assets:
Seismic and exploration costs		54,005		$	47,613
Stock-based compensation		9,329			5,142
Domestic NOL carry forwards		86,599			51,003
Foreign NOL carry forwards		30,407			—
Other		1,869			2,552
Valuation allowance		(177,202	)		(97,560	)

Total deferred assets, net		5,007			8,750

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 the years ended December 31, 2011, 2010 and for the period December 15, 2009 to December 31, 2009.

The NOL carryforward for federal and state income tax purposes of approximately $272.9 million as of December 31, 2011 begins to expire in 2024. The utilization of the NOL carryforwards is dependent upon generating sufficient future taxable income in the appropriate jusidictions within the carryforward period.

As of December 31, 2011, we had NOL carryforward for foreign income tax purposes of approximately $48.2 million which begins to expire in 2012. We do not expect to be able to utilize our foreign NOLs because we do not currently have sufficient estimated future taxable income in the appropriate jurisdiction. 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, 2011 and 2010.

The following table presents the calculation of basic and diluted income (loss) per share and pro forma basic and diluted income (loss) per share for the years ended December 31, 2011, 2010 and 2009, respectively, as discussed further in the summary of significant accounting policies in Note 2:

	December 31,

	2011			2010			2009
	($ in thousands except per share data)
Net income (loss)	$	(133,637	)	$	(136,476	)	$	(81,257	)
Income tax expense		—			—			—

Net income (loss)	$	(133,637	)	$	(136,476	)	$	(81,257	)

Pro forma income tax expense(1)(2)							$	—
Pro forma management fees(3)								2,872

Pro forma net income (loss)							$	(78,385	)

Basic and diluted income (loss) per common share	$	(0.35	)	$	(0.39	)

Weighted average common shares outstanding		376,603,520			349,342,050

Pro forma basic and diluted income (loss) per share							$	(0.33	)

Weighted average common shares outstanding used in pro forma basic and diluted net income (loss) per common share								236,751,219

As of December 31, 2011, the Company's contractual obligations were limited to payments to be made in connection with the leases related to the Ensco 8503 and Diamond Ocean Confidence drilling rigs and other related drilling contracts, office lease payments and lease rental payments for exploration rights from the BOEM for further exploration in the western and central U.S. Gulf of Mexico and social payment obligations for Blocks 9, 20 and 21, offshore West Africa. The following table

summarizes by period the payments due for the Company's estimated contractual obligations as of December 31, 2011:

The Company recorded $7.7 million, $6.9 million, $6.4 million and $30.3 million of office and delay rental expense for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (Inception) through December 31, 2011, respectively.

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.

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 the years ended December 31, 2011, 2010 and 2009:

	U.S. Gulf of Mexico			West Africa			Total

	($ in thousands)
*Year ended December 31, 2011*
Operating costs and expense	$	80,425		$	57,411		$	137,836
Interest income		(4,194	)		(5	)		(4,199	)

Net income (loss)	$	(76,231	)	$	(57,406	)	$	(133,637	)

Net properties and equipment	$	430,699		$	432,627		$	863,326

*Year ended December 31, 2010*
Operating costs and expense	$	94,619		$	43,439		$	138,058
Interest income		(1,582	)		—			(1,582	)

Net income (loss)	$	(93,037	)	$	(43,439	)	$	(136,476	)

Net properties and equipment	$	443,024		$	20,745		$	463,769

*Year ended December 31, 2009*
Operating costs and expense	$	59,835		$	21,935		$	81,770
Interest income		(513	)		—			(513	)

Net income (loss)	$	(59,322	)	$	(21,935	)	$	(81,257	)

Net properties and equipment	$	450,867		$	20,745		$	471,612

Unaudited quarterly financial data for the years ended December 31, 2011 and 2010 are as follows:

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

	($ in thousands)
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	)
Year ended December 31, 2010
Operating costs and expenses	$	29,829		$	41,994		$	35,589		$	30,646
Operating income (loss)		(29,829	)		(41,994	)		(35,589	)		(30,646	)
Net income (loss)		(29,732	)		(41,766	)		(35,182	)		(29,796	)
Basic and diluted income (loss) per common share(1)	$	(0.09	)	$	(0.12	)	$	(0.10	)	$	(0.09	)

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, 2011 and 2010, 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, 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

*As of December 31, 2010*
Unproved properties(1)	$	450,903		$	20,745	$	471,648
Accumulated valuation allowance		(9,148	)		—		(9,148	)

		441,755			20,745		462,500
Proved properties		—			—		—

Net capitalized costs	$	441,755		$	20,745	$	462,500

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, 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

*Year ended December 31, 2009*
Property acquisition
Unproved	$	14,250	$	—	$	14,250
Proved		—		—		—
Exploration
Capitalized		50,051		—		50,051
Expensed		8,793		21,873		30,666
Development		—		—		—

Total Costs Incurred	$	73,094	$	21,873	$	94,967

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))

9.1	*	Stockholders Agreement, dated December 15, 2009, among the Company and the stockholders that are signatory thereto.

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))

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))

		Description of Document

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	†	Long Term Incentive Plan of the Company (incorporated by reference to Exhibit 99.1 to the Company's Registration Statement on Form S-8 filed December 21, 2009 (File No. 333-163883))

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.

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		Termination and Release of Irrevocable Contract Guarantee, dated December 9, 2009, between Ensco Offshore Company and the Guarantors named therein (incorporated by reference to Exhibit 10.25 to the Company's Annual Report on Form 10-K filed March 30, 2010 (File No. 001-34579)).

10.23	†	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)).

10.24	†	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)).

10.25	†	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)).

		Description of Document

10.26		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)).

10.27		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)).

10.28	†	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)).

10.29	†	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))

10.30	*	Severance Agreement, dated April 1, 2010, between the Company and Michael D. Drennon.

10.31	*	Registration Rights Agreement, dated December 15, 2009, among the Company and the parties 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


(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, 2011
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to


Delaware (State or other jurisdiction of incorporation or organization)		27-0821169 (I.R.S. Employer Identification No.)
Two Post Oak Central 1980 Post Oak Boulevard, Suite 1200 Houston, TX 77056 (Address of principal executive offices, including zip code)
(713) 579-9100 (Registrant's telephone number, including area code)

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

			Year Ended December 31,

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



		PART I
1		Business	2
1	A	Risk Factors	36
1	B	Unresolved Staff Comments	54
2		Properties	54
3		Legal Proceedings	54
4		Mine Safety Disclosures	54
		PART II
5		Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	55
6		Selected Financial Data	57
7		Management's Discussion and Analysis of Financial Condition and Results of Operations	59
7	A	Quantitative and Qualitative Disclosures About Market Risk	73
8		Financial Statements and Supplementary Data	73
9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73
9	A	Controls and Procedures	73
9	B	Other Information	74
		PART III
10		Directors, Executive Officers and Corporate Governance	74
11		Executive Compensation	74
12		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	74
13		Certain Relationships and Related Transactions, and Director Independence	75
14		Principal Accountant Fees and Services	75
		Glossary of Selected Oil and Gas Terms	76
		PART IV
15		Exhibits and Financial Statement Schedules	81
		Signatures	85

	Payments Due By Year

	2012		2013		2014		2015		2016		Thereafter		Total
	($ in thousands)
Drilling Rig and Related Contracts	$	195,640	$	119,197	$	—	$	—	$	—	$	—	$	314,837
Operating Leases		2,690		2,110		1,900		1,900		1,900		8,498		18,998
Lease Rentals		5,792		5,037		4,859		4,813		3,066		2,881		26,448
Social Payment Obligations		139,465		49,019		49,019		48,569		62,854		—		348,926

Total	$	343,587	$	175,363	$	55,778	$	55,282	$	67,820	$	11,379	$	709,209


Management's Report on Internal Control over Financial Reporting		F-2
Reports of Independent Registered Public Accounting Firm		F-3
Consolidated Balance Sheet of Cobalt International Energy, Inc. as of December 31, 2011 and 2010		F-5
Consolidated Statements of Operations of Cobalt International Energy, Inc. for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (Inception) through December 31, 2011		F-6
Consolidated Statements of Changes in Stockholders' Equity of Cobalt International Energy, Inc. for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (Inception) through December 31, 2011.		F-7
Consolidated Statements of Cash Flows of Cobalt International Energy, Inc. for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (Inception) through December 31, 2011		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 21, 2012
/s/ JOHN P. WILKIRSON John P. Wilkirson	Chief Financial Officer and Executive Vice President (Principal Financial Officer and Principal Accounting Officer)	February 21, 2012
/s/ PETER R. CONEWAY Peter R. Coneway	Director	February 21, 2012
/s/ MICHAEL G. FRANCE Michael G. France	Director	February 21, 2012
/s/ JACK E. GOLDEN Jack E. Golden	Director	February 21, 2012
/s/ N. JOHN LANCASTER N. John Lancaster	Director	February 21, 2012

Signature	Title	Date


/s/ SCOTT L. LEBOVITZ Scott L. Lebovitz	Director	February 21, 2012
/s/ JON A. MARSHALL Jon A. Marshall	Director	February 21, 2012
/s/ KENNETH W. MOORE Kenneth W. Moore	Director	February 21, 2012
/s/ KENNETH A. PONTARELLI Kenneth A. Pontarelli	Director	February 21, 2012
/s/ MYLES W. SCOGGINS Myles W. Scoggins	Director	February 21, 2012
/s/ D. JEFF VAN STEENBERGEN D. Jeff van Steenbergen	Director	February 21, 2012
/s/ MARTIN H. YOUNG, JR. Martin H. Young, Jr.	Director	February 21, 2012


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, 2011 and 2010			F-5
Consolidated Statements of Operations of Cobalt International Energy, Inc. for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (Inception) through December 31, 2011.			F-6
Consolidated Statements of Changes in Stockholders' Equity of Cobalt International Energy, Inc. for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (Inception) through December 31, 2011.			F-7
Consolidated Statements of Cash Flows of Cobalt International Energy, Inc. for the years ended December 31, 2011, 2010 and 2009, and for the period November 10, 2005 (Inception) through December 31, 2011.			F-8
Notes to Consolidated Financial Statements			F-9


/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

	December 31,

	2011		2010
	(in thousands)
Cash at banks	$	2,992	$	10,327
Money market funds		104,805		59,792
Held-to-maturity securities(1)		184,749		232,601

	$	292,546	$	302,720

	December 31,

	2011				2010
	Amortized Cost		Estimated Fair Value		Amortized Cost		Estimated Fair Value
	($ in thousands)
Within 1 year	$	1,364,213	$	1,364,213	$	1,105,333	$	1,105,333
After 1 year		47,232		47,232		40,003		40,003

	$	1,411,445	$	1,411,445	$	1,145,336	$	1,145,336


		/s/ ERNST & YOUNG LLP


		/s/ ERNST & YOUNG LLP

									For the Period November 10, 2005 (Inception) through December 31, 2011

	For Year Ended December 31,
	2011		2010			2009
	($ in thousands)
Seismic costs	$	20,443	$	39,748		$	34,551		$	299,601
Seismic cost recovery(1)		—		(15,126	)		(10,000	)		(25,126	)
Leasehold delay rentals		6,075		5,989			6,115			26,770
Force Majeure expense(2)		—		13,549			—			13,549
Drilling rig expense		5,721		870			—			14,046

	$	32,239	$	45,030		$	30,666		$	328,840



Expected Term in Years	—	6.25
Expected Volatility	—	54.4	%
Expected Dividends	—	0	%
Risk-Free Interest Rate	—	2.7	%

		Weighted Average Exercise Price			Aggregate Intrinsic Value (thousands)

Outstanding at January 1, 2011	1,133,960	$	12.45	9.9	$	7,688
Granted	—		—
Exercised	—		—
Forfeited or expired	—		—

Outstanding at December 31, 2011	1,133,960	$	12.45	8.9	$	7,688

Vested or expected to vest at December 31, 2011	283,490	$	12.45	8.9	$	1,922

Exercisable at December 31, 2011	283,490	$	12.45	8.9	$	1,922

	Year Ended December 31,

	Year Ended December 31,				Period from December 15 - 31, 2009
	2011		2010		Period from December 15 - 31, 2009
	($ in thousands)
Current taxes:
U.S. federal	$	—	$	—	$	—
Foreign		—		—		—
Deferred taxes:
U.S. federal		—		—		—
Foreign		—		—		—

Total	$	—	$	—	$	—

	Thousands of Acres

	Developed				Undeveloped
	Gross		Net		Gross		Net
*Acreage at December 31, 2011*
U.S. Gulf of Mexico		—		—		1,323		644
West Africa		—		—		5,653		1,841

Total		—		—		6,976		2,485

*Acreage at December 31, 2010*
U.S. Gulf of Mexico		—		—		1,323		644
West Africa		—		—		4,442		1,357

Total		—		—		5,765		2,001

Cobalt International Energy, Inc.

/s/ JOSEPH H. BRYANT

Joseph H. Bryant

Chairman of the Board of Directors and Chief Executive Officer