The following discussion and analysis 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 "Cautionary Statement Regarding Forward-Looking Statements" and "Item 1A. Risk Factors." The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this annual report on Form 10-K.

Overview

We are a leading independent oil and gas exploration and production company focused on frontier and emerging areas in Africa and South America. Our asset portfolio includes existing production and other major project developments offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Mauritania, Morocco and Suriname and onshore Cameroon.

We were incorporated pursuant to the laws of Bermuda as Kosmos Energy Ltd. in January 2011 to become a holding company for Kosmos Energy Holdings. Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of Kosmos Energy Ltd.'s IPO on May 16, 2011, all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. As a result, Kosmos Energy Holdings became wholly owned by Kosmos Energy Ltd.

Recent Developments

On November 23, 2012, we entered into the revolving credit facility (the "Corporate Revolver"). The total size of the Corporate Revolver is $300 million, with $260 million of commitments initially available to us and an additional $40 million of commitments being available if such lenders choose to increase their commitments or if commitments from new financial institutions are added. In connection with the Corporate Revolver, we also amended and restated the $2.0 billion commercial debt facility (the "Facility") to cancel $500 million of unused commitments, cancel the uncommitted $1.0 billion accordion and add certain financial covenants, among other things. As a result of the transaction, $5.3 million of deferred financing costs were written off as a loss on extinguishment of debt.

Ghana

During 2012, we had six liftings of oil totaling 5,905 MBbl from the Jubilee Field production resulting in revenues of $668.0 million. Our average realized price was $113.12 per barrel.

We have received an approval for the Phase 1A PoD of the Jubilee Field, with production from Phase 1A commencing in late 2012. Drilling of the Phase 1A wells is expected to be completed in 2013 and includes eight additional wells, including five production wells and three water injection wells.

In January 2012, the Ntomme-2A appraisal well confirmed a downdip extension of the Ntomme Field on the DT Block. The well encountered high-quality stacked reservoir sandstones. A drill stem test was performed on the well in May 2012, which successfully flowed oil from multiple zones in the reservoir and confirmed continuity with the Ntomme discovery well. Fluid samples recovered from the well indicate an oil gravity of approximately 35 degrees API.

In March 2012, the Enyenra-4A appraisal well confirmed a downdip extension of the Enyenra light oil field on the DT Block. Analysis of well results, including wireline logs, reservoir pressures and fluid samples, indicated the Enyenra-4A well encountered oil-bearing pay. Fluid samples recovered from the well indicate an oil gravity of approximately 34 degrees API. In March 2012, the Owo-1RA (discovery well of the Enyenra field) drill stem test was successful in encountering oil flow across three zones.

Drilling of the Teak-4A appraisal well was completed in May 2012. The well encountered non-commercial reservoirs and accordingly was plugged and abandoned. Total well related costs incurred from inception of $15.0 million are included in exploration expenses in the accompanying consolidated statement of operations for 2012.

In July 2012, the Wawa-1 exploration well made a hydrocarbon discovery on the DT Block. Analysis of well results, including wireline logs, reservoir pressures and fluid samples, indicated the well encountered gas-condensate and oil-bearing pay. Fluid samples recovered from the well indicate an oil gravity of between 38 and 44 degrees API.

In August 2012, a drill stem test performed on the Akasa-1 well on the WCTP Block was successful in encountering oil flow.

In November 2012, we submitted a declaration of commerciality and plan of development covering the Tweneboa, Enyenra and Ntomme discoveries (the "TEN PoD") on the DT Block. The TEN PoD plans for a flexible and expandable development, with an initial base capacity of 80,000 barrels of oil per day. The final development concept is subject to approval from the government of Ghana.

Drilling of the Okure-1 exploration well on the DT Block was completed in December 2012. The well encountered non-commercial reservoirs and accordingly was plugged and abandoned. Total well related costs incurred from inception of $13.8 million are included in exploration expenses in the accompanying consolidated statement of operations for 2012.

The Sapele-1 exploration well on the DT Block was spud in December 2012. Drilling of the well was completed in February 2013. The well is not considered a productive well and accordingly will be plugged and abandoned.

In January 2013, we relinquished the discovery area associated with the Banda discovery on the WCTP Block, as we do not consider this discovery to be commercially viable. As the exploration phase of the WCTP PA has expired, we no longer have any rights to this discovery area (unless we enter into a new petroleum agreement with the Ghana Ministry of Energy and the Ghana National Petroleum Company covering this and other relinquished areas of the WCTP Block). This relinquishment is not expected to impact our consolidated financial statements for the quarter ended March 31, 2013, as we have previously recorded the unsuccessful well costs associated with the Banda-1 exploration well as exploration expenses.

Cameroon

In January 2012, Kosmos entered into a petroleum contract with the Republic of Cameroon for the Fako Block. Kosmos is the operator and has a 100% participating interest in the block. The Republic of Cameroon has an option to acquire an interest of up to 15% in a commercial discovery on the block. The block covers 318,519 acres (1,289 square kilometers) and borders the southeast portion of our Ndian River Block in the Rio del Rey Basin.

In October 2012, the current renewal period of the Ndian River Block was extended through November 19, 2013 and carries a one-well obligation. The Sipo-1 exploration well on the Ndian River Block spud in February 2013. This well is expected to reach its target depth in April 2013.

Mauritania

In April 2012, we completed negotiations with Mauritania's Ministry of Petroleum, Energy and Mines and executed separate petroleum contracts covering Blocks C8, C12 and C13 offshore Mauritania. Kosmos is the operator and has a 90% participating interest in each of these blocks. The government of Mauritania has a 10% carried interest during the exploration period and the option to participate in any discovery on these blocks, and if it elects to exercise such option its participation

interest would be between 10% and 14%. The first phase of the exploration period of the petroleum contract covering each of the blocks is four years in duration. These contracts were officially gazetted by the Government of Mauritania on June 15, 2012, thereby establishing the effective date for the petroleum contracts.

In order to conform the southern boundaries of Blocks C8 and C13 with the Mauritanian border with Senegal, the petroleum contracts were amended in September 2012. The total area covered by the blocks in now 6.6 million acres (26,775 square kilometers). The blocks are located within the western margin of the proven Mauritanian salt basin, on the Atlantic passive margin. The source rock in the basin is the same age and type as the source rock generated by the petroleum system in the Jubilee Field. Additionally, we believe the play model in the basin is similar to the play model found in the Jubilee Field. A petroleum system in Mauritania has been proven by the presence of offshore producing fields in adjacent blocks to those which we hold.

During the first half of 2013, we anticipate initiating a 2D seismic data acquisition program on approximately 6,000 line-kilometers, covering portions of all three blocks. Based on interpretation of results of the 2D seismic data, a 3D seismic program will be targeted for commencement in 2013.

Morocco

In March 2012, we completed a 4,925 square kilometer 3D seismic acquisition program which covered the Essaouira Offshore Block and the Foum Assaka Block, both in the Agadir Basin offshore Morocco. Processing and interpretation of the data continues.

In October 2012, the Moroccan government issued a joint ministerial order approving our acquisition of the additional 18.75% participating interest from Pathfinder, a wholly owned subsidiary of Fastnet, one of our block partners. Upon receipt of this order, we closed the acquisition of such additional participating interest with Pathfinder. We expect final governmental processes required to officially reflect the acquisition under Moroccan law to be completed in due course. After giving effect to the acquisition, our participating interest in the Foum Assaka Offshore Block is 56.25%.

In September 2012, Kosmos entered into an agreement to acquire an additional 37.5% participating interest in the Essaouira Offshore Block from Canamens Energy Morocco SARL, one of our block partners. Certain governmental approvals and processes are still required to be completed before this acquisition can be closed. After completing the acquisition, our participating interest in the Essaouira Offshore Block will be 75%.

In September 2012, Kosmos made its election under the Tarhazoute Reconnaissance Contract to enter into a petroleum contract. Negotiation of the petroleum contract and associated documents is currently ongoing. We anticipate we will be the operator of the license and hold a 75% participating interest.

Suriname

In November 2012, Kosmos closed an agreement with Chevron under which Kosmos assigned half of its interest in Block 42 and Block 45, offshore Suriname, to Chevron. Each party now has a 50% participating interest in Block 42 and Block 45.

In October 2012, we completed a 3D seismic data acquisition program which covered approximately 3,900 square kilometers of portions of Block 42 and Block 45, both in the Suriname-Guyana Basin. Processing of the data is ongoing.

Results of Operations

All of our results, as presented in the table below, represent operations from the Jubilee Field in Ghana. Certain operating results and statistics for the comparative years of 2012, 2011 and 2010 are included in the following table:

                                                    Years Ended December 31,
                                                    2012          2011      2010
                                                         (In thousands,
                                                     except per barrel data)
      Sales volumes:
      MBbl                                             5,905        5,971       -
      Revenues:
      Oil sales                                  $   667,951    $ 666,912    $  -
      Average sales price per Bbl                     113.12       111.70       -
      Costs:
      Oil production, excluding workovers        $    50,640    $  83,551    $  -
      Oil production, workovers                       44,469            -       -

      Total oil production costs                 $    95,109    $  83,551       -
      Depletion                                  $   178,568    $ 135,532       -
      Average cost per Bbl:
      Oil production, excluding workovers        $      8.58    $   13.99    $  -
      Oil production, workovers                         7.53            -       -

      Total oil production costs                       16.11        13.99       -
      Depletion                                        30.24        22.70       -

      Oil production cost and depletion costs    $     46.35    $   36.69    $  -

The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.

     Year Ended December 31, 2012 vs. 2011

                                                   Years Ended
                                                  December 31,          Increase
                                                2012        2011       (Decrease)
                                                         (In thousands)
      Revenues and other income:
      Oil and gas revenue                     $ 667,951   $ 666,912    $     1,039
      Interest income                             1,108       9,093         (7,985 )
      Other income                                3,150         775          2,375

      Total revenues and other income           672,209     676,780         (4,571 )
      Costs and expenses:
      Oil and gas production                     95,109      83,551         11,558
      Exploration expenses                       97,712     126,409        (28,697 )
      General and administrative                160,027     113,579         46,448
      Depletion and depreciation                185,707     140,469         45,238
      Amortization-deferred financing costs       8,984      16,193         (7,209 )
      Interest expense                           52,207      65,749        (13,542 )
      Derivatives, net                           31,490      11,777         19,713
      Loss on extinguishment of debt              5,342      59,643        (54,301 )
      Doubtful accounts expense                       -     (39,782 )       39,782
      Other expenses, net                         1,475         149          1,326

      Total costs and expenses                  638,053     577,737         60,316

      Income before income taxes                 34,156      99,043        (64,887 )
      Income tax expense                        101,184      76,686         24,498

      Net income (loss)                       $ (67,028 ) $  22,357    $   (89,385 )

Oil and gas revenue. Oil and gas revenue increased by $1.0 million during the year ended December 31, 2012 as compared to the year ended December 31, 2011 primarily due to a higher realized price per barrel. We lifted and sold approximately 5,905 MBbl at an average realized price per barrel of $113.12 in 2012 and approximately 5,971 MBbl at an average realized price per barrel of $111.70 in 2011.

Interest income. Interest income decreased by $8.0 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011, primarily due to interest on notes receivable. The related notes receivable was satisfied in December 2011 as part of the acquisition of the FPSO we are using to produce hydrocarbons from the Jubilee Field.

Other income. Other income increased by $2.4 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011, primarily due to an increase in technical services fees and overhead charges billed to partners.

Oil and gas production. Oil and gas production costs increased by $11.6 million during the year ended December 31, 2012 as compared to the year ended December 31, 2011 primarily due to $44.5 million of workover costs related to acid stimulations on Jubilee Field wells, offset by a decrease due to the purchase of the FPSO in December 2011. During the year ended December 31, 2012, the amortization of costs capitalized in connection with the purchase of the FPSO were expensed as

depletion. Our average production cost per barrel was $16.11 and $13.99 for the years ended December 31, 2012 and 2011, respectively.

Exploration expenses. Exploration expenses decreased by $28.7 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011. During the year ended December 31, 2012, we incurred $53.9 million for seismic costs for Morocco, Suriname, Ghana and Cameroon; $32.2 million of unsuccessful well costs, primarily related to the Ghana Teak-4A appraisal well and Ghana Okure-1 exploration well; and $9.9 million of new business costs. During the year ended December 31, 2011, we incurred $32.8 million for seismic costs and $91.3 million of unsuccessful well costs, primarily related to the Cameroon N'gata-1, Ghana Makore-1, Ghana Banda-1 and Ghana Odum exploration wells.

General and administrative. General and administrative costs increased by $46.4 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011, primarily due to increases in non-cash expenses of $32.4 million for equity-based compensation and an increase in staffing. Total non-cash general and administrative costs were $83.4 million and $51.0 million for the years ended December 31, 2012 and 2011, respectively.

Depletion and depreciation. Depletion and depreciation increased $45.2 million during the year ended December 31, 2012, as compared with the year ended December 31, 2011, primarily due to an increase in the cost basis of our oil and gas properties related to the purchase of the FPSO and an increase in the number of completed wells.

Amortization-deferred financing costs and Loss on extinguishment of debt. In March 2011, we refinanced our existing commercial debt facilities. As part of the transaction, we incurred approximately $52.3 million of deferred financing costs, in addition to our existing unamortized deferred financing costs of $68.6 million. As a result of the transaction, we recorded a $59.6 million loss on the extinguishment of debt. The remaining costs were capitalized and are being amortized over the term of the Facility. The related amortization of deferred financing costs for the Facility decreased by $7.5 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011, due to the decrease in capitalized deferred financing costs and the longer term associated with the Facility. In November 2012, we amended the Facility and secured a $300 million Corporate Revolver. As a result of these transactions, $5.3 million of deferred financing costs were written off as a loss on extinguishment of debt.

Interest expense. Interest expense decreased by $13.5 million during the year ended December 31, 2012, as compared to the year ended December 31, 2011, primarily due to a decrease in the unrealized loss on the interest rate derivative instruments related to changes in fair value and a lower weighted average interest rate on the Facility, partially offset by an accrual for transaction taxes during the year ended December 31, 2012.

Derivatives, net. Derivatives, net increased $19.7 million during the year ended December 31, 2012, as compared with December 31, 2011, due to the change in fair value and notional amount of the commodity derivative instruments.

Doubtful accounts expense. During the year ended December 31, 2011, we released a $39.8 million allowance for doubtful accounts related to a receivable previously in default. We received the full amount of the receivable during the third quarter of 2011.

Income tax expense. The Company recognized an income tax provision attributable to earnings of $101.2 million and $76.7 million during 2012 and 2011, respectively. The Company's effective tax rates for 2012 and 2011 were 296.2% and 77.4%, respectively. The large variance in income taxes between 2012 and 2011 is due to the impact of the book/tax difference related to the decrease in fair value of certain vested equity awards. The large effective tax rate in 2012 is due to losses incurred in

jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits; losses in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such losses; and the impact on deferred tax assets based on the book/tax difference related to the decrease in fair value of certain vested equity awards.

     Year Ended December 31, 2011 vs. 2010

                                                  Years Ended
                                                  December 31,          Increase
                                               2011         2010       (Decrease)
                                                        (In thousands)
     Revenues and other income:
     Oil and gas revenue                     $ 666,912   $        -    $   666,912
     Interest income                             9,093        4,231          4,862
     Other income                                  775        5,109         (4,334 )

     Total revenues and other income           676,780        9,340        667,440
     Costs and expenses:
     Oil and gas production                     83,551            -         83,551
     Exploration expenses                      126,409       73,126         53,283
     General and administrative                113,579       98,967         14,612
     Depletion and depreciation                140,469        2,423        138,046
     Amortization-deferred financing costs      16,193       28,827        (12,634 )
     Interest expense                           65,749       59,582          6,167
     Derivatives, net                           11,777       28,319        (16,542 )
     Loss on extinguishment of debt             59,643            -         59,643
     Doubtful accounts expense                 (39,782 )     39,782        (79,564 )
     Other expenses, net                           149        1,094           (945 )

     Total costs and expenses                  577,737      332,120        245,617

     Income (loss) before income taxes          99,043     (322,780 )      421,823
     Income tax expense (benefit)               76,686      (77,108 )      153,794

     Net income (loss)                       $  22,357   $ (245,672 )  $   268,029

Oil and gas revenue. During the year ended December 31, 2011, we recorded oil sales of $666.9 million due to oil production from the Jubilee Field. We lifted and sold approximately 5,971 MBbl at an average realized price per barrel of $111.70. In 2010, we had no oil sales and, therefore, no associated revenues.

Interest income. Interest income increased by $4.9 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010, primarily due to interest on notes receivable. The related note receivable was satisfied in December 2011 as part of the acquisition of the FPSO we are using to produce hydrocarbons from the Jubilee Field.

Other income. Other income decreased by $4.3 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010, primarily due to a decrease in technical services fees and overhead charges billed to partners for services provided on the Jubilee Field Phase 1 development.

Oil and gas production. During the year ended December 31, 2011, we recorded oil and gas production costs of $83.6 million related to oil production from the Jubilee Field. Our average production cost per barrel was $13.99. In 2010, there were no oil sales and, therefore, no associated oil and gas production costs.

Exploration expenses. Exploration expenses increased by $53.3 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010. During the year ended December 31, 2011, we incurred $32.8 million for seismic costs and $91.3 million of unsuccessful well costs, primarily related to the Cameroon N'gata-1, Ghana Makore-1, Ghana Banda-1 and Ghana Odum exploration wells. During the year ended December 31, 2010, the Company incurred $59.4 million of unsuccessful well costs primarily related to the Ghana Dahoma-1 and Cameroon Mombe-1 wells and $13.0 million for seismic costs.

General and administrative. General and administrative costs increased by $14.6 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010, primarily due to an increase in staffing and increases in non-cash expenses of $37.2 million for equity-based compensation, partially offset by decreases in cash expenses for professional fees. Total non-cash general and administrative costs were $51.0 million and $13.8 million for the years ended December 31, 2011 and 2010, respectively.

Depletion and depreciation. Depletion and depreciation increased $138.0 million during the year ended December 31, 2011, as compared with the year ended December 31, 2010, due to production from the Jubilee Field. In 2010, there were no oil sales and, therefore, no associated depletion.

Amortization-deferred financing costs and Loss on extinguishment of debt. During the year ended December 31, 2011, we incurred approximately $52.3 million of deferred financing costs as part of our debt refinancing, in addition to our existing unamortized deferred financing costs of $68.6 million. As a result of the debt refinancing, we recorded a $59.6 million loss on the extinguishment of debt. The remaining costs were capitalized and are being amortized over the term of the Facility. The related amortization of deferred financing costs decreased by $12.6 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010, due to the decrease in capitalized deferred financing costs and the longer term associated with the Facility.

Interest expense. Interest expense increased by $6.2 million during the year ended December 31, 2011, as compared to the year ended December 31, 2010, primarily due to a decrease in capitalized interest and higher average outstanding debt during the year ended December 31, 2011.

Derivatives, net. Derivatives, net decreased $16.5 million during the year ended December 31, 2011, as compared with December 31, 2010, due to the change in fair value of the commodity derivative instruments.

Doubtful accounts expense. During the year ended December 31, 2011, we released a $39.8 million allowance for doubtful accounts related to a receivable previously in default that was provided for in 2010. We received the full amount of the receivable during the third quarter of 2011.

Income tax expense (benefit). The Company recognized an income tax provision attributable to earnings of $76.7 million during 2011 and an income tax benefit of $77.1 million during 2010. The Company's effective tax rates for 2011 and 2010 were 77.4% and 23.9%, respectively. The large variance in income taxes between 2011 and 2010 is due to the release of a valuation allowance related to the Ghana operations in 2010. The large effective tax rate in 2011 is . . .