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April 19, 2011

Mr. H. Roger Schwall
Assistant Director
Securities and Exchange Commission
Mail Stop 7010
100 F Street N.E.
Washington, DC 20549-4628

Dear Mr. Schwall:

        This letter is in response to your letter dated April 18, 2011. We have set forth your comments followed by the Company's response.

Risk Factors, page 17

The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results, page 20

1.

We note your response to comment three in our letter dated April 13, 2011 implies that you have not historically had defaults other than the EO Group. However, your disclosure on page 20 appears to indicate partners other than the EO Group have been in default in the past. With regard to this disclosure please provide us the following information:

•

tell us which partners besides EO Group have not paid their share of costs in the past;

•

clarify which non-defaulting block partners paid the proportionate share of the costs on behalf of the defaulting parties;

•

tell us the gross amount of payments made on behalf of the defaulting parties, and what your share of such costs was;

•

tell us the partners which paid the EO Group's share of costs and expenses upon their default;

•

tell us if such partners have sought to require the EO Group to forfeit its interest in the Jubilee Unit, or have taken other measures to recover their cost; and

•

tell us how the right to recover the costs paid on behalf of the EO Group factored into your determination regarding your allowance for doubtful accounts.

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Background

        We think it would be helpful to provide an explanation of the two agreements related to your comments numbered 1 through 5 regarding the EO Group. These are, first, our agreement with EO group (the "EO Agreement") that created our obligation to pay EO Group's share of costs (the "EO Carry") under the WCTP Joint Operating Agreement attributable to their 3.5% interest in the WCTP Petroleum Agreement (the "WCTP PA"); and second, the WCTP Joint Operating Agreement (the "WCTP JOA") among Kosmos Ghana, Anadarko WCTP, Tullow Ghana, EO Group and Sabre Oil and Gas ("Sabre"), is the agreement that governs operations and payment of costs under the WCTP PA.

        The EO Agreement, signed in 2004, makes a distinction regarding the repayment for the EO Carry. Regarding development capital expenditures, that is, those costs related to the Jubilee Phase 1 development ("Development Costs"), we are required to pay these costs for EO, and we are to be reimbursed those amounts from EO's production revenue after first production. Additionally, we are required to pay exploration and appraisal costs for EO Group, but the EO Group was not required to reimburse us for those costs.

        The EO Agreement also provides the EO Carry terminates on commencement of production from the WCTP Block. First oil production occurred on November 28, 2010, the EO Carry terminated and from that point on, EO Group was obligated to pay their proportionate share of WCTP PA costs under the terms of the WCTP JOA. As of December 31, 2010, the EO Group had an unpaid balance of $3.7 million under the WCTP JOA. As EO Group had failed to pay their share of costs by the date due, they were in default under the WCTP JOA at December 31, 2010 and remain in default currently. In addition, on termination of the EO Carry, the Development Costs became reimbursable to us; in the amount of $61.7 million.

        Specific provisions related to default under the EO Agreement were not contemplated in 2004 and the agreement does not provide for the creation of a security interest (a lien) in favor of Kosmos for amounts related to the reimbursable portion of the carry. In the US petroleum industry, it is common that partial carry reimbursement obligations remain unsecured. But, unlike in the U.S., a lien cannot be perfected in Ghana by the filing of a form locally (e.g. as with form UCC-1 in the US). The creation of a security interest as a matter of law is difficult in certain international jurisdictions due to third party approvals required, including, in the case of Ghana, the consent of the government. Rather, the agreement creates a contractual obligation for EO Group to reimburse us for the Development Costs we paid on EO Group's behalf.

        The WCTP JOA contains detailed provisions regarding a party's failure to timely pay its share of the WCTP JOA costs. If a party fails to timely pay its share of WCTP JOA costs, that party is in default and the non-defaulting parties are required to pay their proportionate share of the default amount. In addition, if the default is not cured then, among other things:

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First, the defaulting party's share of production is sold by the non-defaulting parties to repay the default amounts they paid.



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Second, if the default is not remedied within 60 days, any non-defaulting party may require the defaulting party to withdraw from the WCTP PA and WCTP JOA and forfeit its interest to the non-defaulting parties (subject to Ghana government consent to such "transfer").

        Subsequently, the non-defaulting party's would proportionately own the defaulting parties interest under the WCTP PA and WCTP JOA. However, this could be disputed in international arbitration under the WCTP JOA and there is some question whether a forfeiture would be enforceable under the governing law in the WCTP JOA.

        On termination of the EO Carry on commencement of oil production from Jubilee Field (on November 28, 2010), EO Group was required to meet its share of the financial obligations under the

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WCTP JOA. However, almost immediately, EO Group did not pay its share of costs and was declared in default under the WCTP JOA in December 2010. Similarly, Sabre had also been declared in default for failure to timely pay its share of the WCTP JOA and DWT JOA costs from January 2010; but it fully cured such defaults in November 2010.

        Our ability to collect the amounts owed us by the EO Group depends on the EO Group's ability to sell their share of the Jubilee oil production or part or all of their interests in the WCTP PA. We are unaware of any other assets or income sources of EO Group to meet such obligation. Because EO Group has been unable to cure its defaults, their share of production is being sold by the non-defaulting parties to pay EO Group's share of costs under the WCTP JOA paid by the non-defaulting parties. These parties include Kosmos since we have paid our share of the EO Group's defaulted amounts under the WCTP JOA. Moreover, if EO Group does not remedy the default within 60 days, any non-defaulting party may require EO Group to withdraw from the WCTP PA and WCTP JOA and forfeit its interest to the non-defaulting parties (subject to Ghana government consent to such "transfer").

        Despite EO Group's default, the non-defaulting parties (Kosmos Ghana, Anadarko WCTP, Tullow Ghana and Sabre) have not sought to require EO Group to withdraw from the WCTP PA and thereby forfeit its interest in the WCTP PA. Instead, the WCTP JOA parties have agreed to temporarily waive such forfeiture as we have been made aware of a potential sale of EO Group's interest in the WCTP PA.

        The process is clear under the WCTP JOA for remedying default through forfeiture by EO Group to the other parties. In contrast, the EO Agreement does not include a default process; and thus our ability to collect the full amount of the Development Costs ($61.7 million) owed us is uncertain, as set out below. EO Group's breach of the EO Agreement in regards to reimbursement of the carried development costs does not give rise to our ability to enforce a WCTP JOA default and initiate forfeiture provisions. Instead, if EO Group fails to pay us, we would have a contractual claim against EO Group for the amounts owed to us. In seeking to collect these amounts we could bring a breach of contract dispute in an international arbitration proceeding. While we may prevail in any such arbitration, our ability to fully collect under an arbitral award would, again, be uncertain.

        Given the uncertainty under the EO Agreement as described above, we considered a number of factors in determining our allowance for doubtful accounts related to the EO Group's carried interest receivable at December 31, 2010. These factors included, but were not limited to, discussions held with the EO Group on recovery of amounts owed, EO Group's lack of access to funds as evidenced by their inability to pay their proportionate share of WCTP JOA costs upon commencement of production on November 28, 2010, the EO Group's subsequent default in payment of WCTP JOA costs, the EO Group's inability to secure outside funding to bridge shortfalls, and the fact that our ability to collect the amounts owed us by the EO Group depends on their ability to sell their share of Jubilee oil production or part or all of their interests in the WCTP PA. Based on the above, we determined we incurred a loss at December 31, 2010. We believe that $39.8 million (approximately 65% of the year-end balance) represents our best estimate of potential uncollectible amounts at December 31, 2010. We determined this estimate represented the most likely outcome based on our assessment of the facts and circumstances. We believe the remaining unreserved balance will be recovered through one or a combination of the above noted factors. We have revised the disclosure on page F-17 of the prospectus to highlight the gross and net receivable balance at December 31, 2010. Please find the changed page reflecting this revision attached to this letter.

Responses

•

tell us which partners besides EO Group have not paid their share of costs in the past;

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Sabre Oil & Gas Holdings Limited ("Sabre") is the only other party to have not paid its share of cost when due. This occurred in multiple instances between January 2010 and October 2010. The non-defaulting parties which paid their proportionate share of Sabre's default amounts were Kosmos Ghana, Anadarko WCTP and Tullow Ghana. In November 2010, Sabre fully remedied defaults and is current in respect of its costs. All non-defaulting parties have been reimbursed for their share of payment of the Sabre defaulted costs.

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clarify which non-defaulting block partners paid the proportionate share of the costs on behalf of the defaulting parties;

Non-defaulting parties which have paid their proportionate share of Sabre's default include Kosmos Ghana, Anadarko WCTP, and Tullow Ghana.

Non-defaulting parties which have paid their proportionate share of EO Group default include Kosmos Ghana, Anadarko WCTP, Sabre Oil & Gas and Tullow Ghana.

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tell us the gross amount of payments made on behalf of the defaulting parties, and what your share of such costs was;

The gross amount of payments made on behalf of Sabre was $51.3 million of which Kosmos' share was $13.7 million. This amount was fully repaid with interest in November 2010.

The gross amount of payments made on behalf of EO Group was $3.7 million of which Kosmos' share was $1.3 million.

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tell us the partners which paid the EO Group's share of costs and expenses upon their default;

Non-defaulting parties which have paid their proportionate share of EO Group default include Kosmos Ghana, Anadarko WCTP, Sabre and Tullow Ghana.

•

tell us if such partners have sought to require the EO Group to forfeit its interest in the Jubilee Unit, or have taken other measures to recover their cost; and

Despite EO group's default, the non-defaulting parties (Kosmos Ghana, Anadarko WCTP, Tullow Ghana and Sabre) have not sought to require EO Group to withdraw from the WCTP PA and thereby forfeit its interest in the WCTP PA. Instead, the WCTP JOA parties have agreed to temporarily waive such forfeiture as we have been made aware of potential sale of EO Group's interest in the WCTP PA. However, in accordance with the WCTP JOA, the non-defaulting parties have exercised the WCTP JOA right to sell EO Group's share of production and utilize the sales proceeds to reimburse the non-defaulting parties' share of costs under the WCTP JOA paid by the non-defaulting parties.

•

tell us how the right to recover the costs paid on behalf of the EO Group factored into your determination regarding your allowance for doubtful accounts.

The process is clear under the WCTP JOA for remedying default through forfeiture by EO Group to the other parties. In contrast, the EO Agreement does not include a default process; and thus our ability to collect the full amount of the Development Costs ($61.7 million) owed us is uncertain. EO Group's breach of the EO Agreement in regards to reimbursement does not give rise to our ability to enforce a WCTP JOA default and initiate forfeiture provisions. Instead, if EO Group fails to pay us, we would have a contractual claim against EO Group for the amounts owed to us. In seeking to collect these amounts we could bring a breach of contract dispute in an international arbitration proceeding. While we may prevail in any such arbitration, our ability to fully collect under an arbitral award would, again, be uncertain.

Given the uncertainty under the EP Agreement as described above, we considered a number of factors in determining our allowance for doubtful accounts related to the EO Group's carried

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interest receivable at December 31, 2010. These factors included, but were not limited to, discussions held with the EO Group on recovery of amounts owed, EO Group's lack of access to funds as evidenced by their inability to pay their proportionate share of WCTP JOA costs upon commencement of production on November 28, 2010, the EO Group's subsequent default in payment of WCTP JOA costs, the EO Group's inability to secure outside funding to bridge shortfalls, and the fact that our ability to collect the amounts owed us by the EO Group depends on their ability to sell their share of Jubilee oil production or part or all of their interests in the WCTP PA. Based on the above, we determined we incurred a loss at December 31, 2010. We believe that $39.8 million (approximately 65% of the year-end balance) represents our best estimate of potential uncollectible amounts at December 31, 2010. We determined this estimate represented the most likely outcome based on our assessment of the facts and circumstances. We believe the remaining unreserved balance will be recovered through one or a combination of the above noted factors. We have revised the disclosure on page F-17 of the prospectus to highlight the gross and net receivable balance at December 31, 2010. Please find the changed pages reflecting this revision attached to this letter.

2.

We further note from your disclosure on page 111, that under the terms of the WCTP agreement, "The EO Group owns a 3.5% 'carried' working interest and all of EO Group's share of costs to first production from the WCTP Block are paid by Kosmos Ghana." As all costs to first production are paid by Kosmos Ghana, please clarify how the EO Group is currently in default under the joint operating agreement for the WCTP Block for failure to pay its share of costs and expenses.

The EO Agreement provides the EO Carry terminates on commencement of production from the WCTP Block. First oil production occurred on November 28, 2010, the EO Carry terminated and from that point on, EO Group was obligated to pay their proportionate share of WCTP PA costs under the terms of the WCTP JOA. However, almost immediately, EO Group did not pay its share of costs and was declared in default under the JOA in December 2010. As of December 31, 2010, the EO Group had an unpaid balance of $3.7 million under the WCTP JOA.

Results of Operations, page 60

Year Ended December 31, 2010 vs. 2009, page 60

Doubtful Accounts Expense, page 61

3.

Your response to comment three in our letter dated April 13, 2011 explains that you do not have a perfected lien against the account receivable in default and, therefore, did not consider future net revenues in your assessment of the collectability of the EO Group receivable. Please clarify what you mean when you refer to a perfected lien, and why you must have a perfected lien in order to collect amounts due from the EO Group. Please also explain if the notion of having a perfected lien in order to collect amounts due from the EO Group was considered in the original agreement between Kosmos Ghana and the EO Group. If so, tell us the specific provisions in the agreements that specify the rights and obligations of each party with regard to the collection of amounts under default. Please also tell us what procedures you performed to ensure you had a perfected lien.

Specific provisions related to default under the EO Agreement were not contemplated in 2004 and the agreement does not provide for the creation of a security interest (a lien) in favor of Kosmos for amounts related to the reimbursable portion of the carry. In the U.S. petroleum industry, it is common that carry reimbursement obligations remain unsecured. But, unlike the U.S., a lien cannot be perfected in Ghana by the filing of a form locally (e.g. as with form UCC-1 in the US). The creation of a security interest as a matter of law is difficult in certain international jurisdictions due to third party approvals required, including, in the case of Ghana, the consent of

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the government. Rather, the agreement creates a contractual obligation for EO Group to reimburse us for the Development Costs we paid on EO Group's behalf, which total $61.7 million.

Please see our response to Comment No. 1 above, the last sub-bullet, in regards to "collection of amounts."

4.

We note from your disclosure on page 111 that the EO Group is required to reimburse Kosmos Ghana for all development costs paid by Kosmos Ghana on EO Group's behalf, with Kosmos Ghana entitled to receive all of EO Group's production proceeds until repayment in full. Please explain how this disclosure is consistent with your response that you did not consider future net revenues in assessing the collectability of the receivable due to the lack of a perfected lien.

We have revised the disclosure on page 111 of the prospectus in response to this comment. Please find the changed page reflecting these revisions attached to this letter.

5.

Your response to comment three in our letter dated April 13, 2011 also explains that the gross amount due from the EO Group is $61.7 million. Please clarify why only a portion of the amount due from the EO Group was considered uncollectible, and how the specific amounts considered collectible versus uncollectible were determined.

The process is clear under the WCTP JOA for remedying default through forfeiture by EO Group to the other parties. In contrast, the EO Agreement does not include a default process; and thus our ability to collect the full amount of the Development Costs ($61.7 million) owed us is uncertain. EO Group's breach of the EO Agreement in regards to reimbursement does not give rise to our ability to enforce a WCTP JOA default and initiate forfeiture provisions. Instead, if EO Group fails to pay us, we would have a contractual claim against EO Group for the amounts owed to us. In seeking to collect these amounts we could bring a breach of contract dispute in an international arbitration proceeding. While we may prevail in any such arbitration, our ability to fully collect under an arbitral award would, again, be uncertain.

Given the uncertainty under the EO Agreement as described above, we considered a number of factors in determining our allowance for doubtful accounts related to the EO Group's carried interest receivable at December 31, 2010. These factors included, but were not limited to, discussions held with the EO Group on recovery of amounts owed, EO Group's lack of access to funds as evidenced by their inability to pay their proportionate share of WCTP JOA costs upon commencement of production on November 28, 2010, the EO Group's subsequent default in payment of WCTP JOA costs, the EO Group's inability to secure outside funding to bridge shortfalls, and the fact that our ability to collect the amounts owed us by the EO Group depends on their ability to sell their share of Jubilee oil production, or part or all of their interests in the WCTP PA. Based on the above, we determined we incurred a loss at December 31, 2010. We believe that $39.8 million (approximately 65% of the year-end balance) represents our best estimate of potential uncollectible amounts at December 31, 2010. We determined this estimate represented the most likely outcome based on our assessment of the facts and circumstances. We believe the remaining unreserved balance will be recovered through one or a combination of the above noted factors. We have revised the disclosure on page F-17 of the prospectus to highlight the gross and net receivable balance at December 31, 2010. Please find the changed page reflecting this revision attached to this letter.

Business, page 81

Our Reserves, page 103

6.

Your response to comment five in our letter dated April 13, 2011 explains that you do not have any corporate income taxes as you are incorporated in Bermuda, and therefore, do not have any income taxes related to your proved reserves. We note you present Ghanaian taxes within your

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presentation of results of operations for oil and gas producing activities as required by ASC 932-235-50-21 through 28 and within your standardized measure of discounted future net cash flows required by ASC 932-235-50-29 through 33. Based on the guidance provided in ASC 932-235-50-25 and 31c, the taxes included within these disclosures and calculations, appear to relate to an entities oil and gas producing activities which are derived from proved oil and gas reserves. Therefore, please clarify why you believe your Ghanaian taxes are not related to you proved oil and gas reserves.

The Company does believe that its Ghanaian tax expenses levied under the WCTP and DT Petroleum Agreements are related to its proved oil and gas reserves. Accordingly, such tax expenses have been included in the calculations of both the Company's PV-10 and Standardized Measure. The Company's calculations of its PV-10 do not include the effects any future income tax expense related to its proved oil and gas reserves other than the Ghanaian tax expenses which are levied under the WCTP and DT Petroleum Agreements (at the asset level); accordingly, the Company's calculations of its PV-10 do not include the effects any future income tax expense levied at a corporate parent level or any other intermediate subsidiary level. In contrast, in line with U.S. GAAP requirements, the Company's calculations of its Standardized Measure include the effects of both future income tax expense related to proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level as well as future tax expense related to proved oil and gas reserves levied at an asset level (in the Company's case, this includes future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements).

However, it should be noted that as the Company has been a tax exempted company incorporated pursuant to the laws of the Cayman Islands to date and will be a tax exempted company incorporated pursuant to the laws of Bermuda following the completion of the corporate reorganization to be completed in connection with this offering, and as the Company's intermediate subsidiaries positioned between it and the subsidiary that is a signatory to the WCTP and DT Petroleum Agreements will continue to be tax exempted companies, the Company has not been and does not expect to be subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent level or intermediate subsidiary level. Accordingly, the Company's Standardized Measure reflects the effects of future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements, as well as the fact that the Company has no future corporate parent level or intermediate subsidiary level tax expense, and therefore is equivalent to the PV-10.

We have clarified the disclosure on pages 104, 105, F-41 and F-42 of the prospectus in response to this comment. Please find changed pages reflecting these revisions attached to this letter.

7.

Your response to comment six in our letter dated April 13, 2011 explains that approximately 3 MMbbls of oil related to the royalty payable to the Ghanaian government is included within your total net proved reserves of 56 MMbbls. As these volumes appear to relate to the interests of others, please revise your presentation of net proved reserves to remove the volumes in accordance with ASC 932-235-50-4.

In the next Amendment to the Registration Statement to be filed with the Commission we will revise the disclosure throughout the prospectus, the unaudited Supplementary Oil and Gas Data note to our financial statements and Exhibits 99.1 and 99.2 to revise the amount of our net proved reserves in response to this comment.

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Notes to Consolidated Financial Statements, page F-8

Note 12 Asset Retirement Obligations, page F-26

8.

The disclosure under the table explains that you recognized your liability related to asset retirement obligations in the fourth quarter of 2010 with the commencement of production. However, your response to comment seven explains that you had 2 development wells in progress of being completed as of December 31, 2010 which are included in the company's asset retirement obligation. As these wells are not currently producing, please clarify the apparent inconsistency between your response and the disclosure in Note 12.

Please refer to our response in Comment No. 9 below for additional clarification on the Company's accounting treatment for asset retirement obligations. Additionally, we have revised footnote 12 on page F-26 of the prospectus to address wells in progress in response to this comment. Please find the changed page reflecting these revisions attached to this letter.

9.

Your response to comment seven in our letter dated April 13, 2011 explains that development wells are plugged after the cessation of drilling activities. Please tell us if you record an asset retirement obligation related to these development wells, and at which point in the development drilling process you incur the obligation to plug the wells. Please also tell us the total amount of costs incurred in each of the past three years related to the temporary plugging of your wells.

Once a field commences production, we estimate and record an asset retirement obligation for wells and infrastructure related to the field. Our estimate of the asset retirement obligation is based on the formal decommissioning plan developed by the field partners. Any changes in the decommissioning plan subsequent to initial recognition will be accounted for prospectively under ASC 410.

Prior to the commencement of production for a field and in the normal course of drilling operations and completion procedures, developmental wells are plugged. Once the wells are plugged, the Company believes it has complied with its abandonment obligations as such exist under Ghanaian law and, therefore, has not recorded an asset retirement obligation related to the plugged developmental wells.

For the years ended December 31, 2010, 2009, and 2008, the Company incurred $1.3 million, $1.8 million and nil related to the plugging of development wells, respectively. These costs have been capitalized in Oil and Gas Properties in the financial statements, as they are considered a development cost. We note that we did not have any developmental wells during 2008 and, therefore, had no related plugging costs for developmental wells.

Note 16 Income Taxes, page F-31

10.

In your response to comment eight in our letter dated April 13, 2011 you explain that you had one oil lifting during the first quarter and expect to have two oil liftings per quarter for the remainder of fiscal year 2011. Please further describe for us the process of your oil liftings, and why these appear to occur at specific times rather than on a continuous basis. Please also tell us why you only had one in the first quarter, and why you are expecting two per quarter for the remainder of fiscal year 2011.

The Jubilee Field commenced production on November 28, 2010. The plan of development under which the field is being developed calls for a gradual increase in production over several quarters as various systems and wells are commissioned and commence production. Oil is produced into a floating, production, storage and offloading facility ("FPSO") and offloaded from the FPSO onto a single oil tranker (a "lifting") once a sufficient amount of oil has been produced from the field.

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The Jubilee Unit partners have agreed to a lifting schedule in which each unit partner is assigned a lifting on a particular date and is responsible for marketing and selling their lifting of oil.

Based on the lifting schedule for 2011, Kosmos was only entitled to one lifting in the first quarter of 2011. As the production volume continues to increase during the year, the Company expects to have multiple crude oil liftings during each of the remaining quarters in 2011.

11.

We note your response to comment eight in our letter dated April 13, 2011. It does not appear the positive evidence cited regarding your expectation of future taxable income is sufficient to offset the negative evidence created by your cumulative losses in recent years. At this time, we are not in a position to agree that the valuation allowance related to your Ghana deferred tax asset should be removed as of December 31, 2010, or to date. Please revise accordingly.

We respectfully disagree with the Staff's conclusion that there is insufficient positive evidence to overcome the negative evidence created by our cumulative losses. We believe that our conclusion that realization of the Ghanaian deferred tax asset is more-likely-than-not is based on what the Company considers overwhelming positive evidence. We respectfully ask the Staff to please reconsider the following guidance and positive evidence the Company has relied upon in making its conclusion to release the Ghana valuation allowance:

1.

ASC 740-10-30-17 requires that "all available evidence, both positive and negative, shall be considered to determine whether, based on all the weight of the evidence, a valuation allowance for a deferred tax asset is needed. The historical information is supplemented by all currently available information about future years. Sometimes, however, historical information may not be available (for example startup operations) or it may not be relevant (for example if there has been a significant recent change in circumstances) and special attention is required." The Company believes that, in its facts and circumstances, the historical cumulative tax losses sustained during the development phase of the Jubilee Field are not relevant indicators of the ability to realize the net deferred tax assets in Ghana. The Company believes that the booking of proved reserves with a PV-10 value of $1.5 billion and the commencement of production of oil in the fourth quarter of 2010 were significant events that required special attention.

2.

The existence of significant proved oil reserves that have been independently verified by Netherland Sewell & Associates, Inc. ("NSAI"), the Company's independent reserve engineers. By definition, proved reserves have a 90% probability of producing the underlying cash flows from the hydrocarbons on a discounted basis. Given the large probability assigned to proved reserves, we believe these proved reserves provide significant positive evidence as to the realization of the Ghanaian deferred tax asset. ASC 740-10-30-22 provides that existing contracts or firm sales backlog that will produce more than enough taxable income to realize the deferred tax asset, based upon existing sales price and costs, is an example of positive evidence that supports the conclusion that a valuation allowance is not needed when there is negative evidence, such as cumulative losses. The Company believes that proved reserves provide even more positive evidence than a firm sales backlog. We also note the 90% probability required for recognizing the proved reserves is a much higher threshold than the more-likely-than-not criteria used in evaluating whether a valuation allowance for the net deferred tax assets in Ghana is required.

3.

According to ASC 740-10-30-22, an excess of appreciated asset value over the tax basis is another source of meaningful positive evidence. For the Company's Ghanaian assets this value has been demonstrated not only by independent third party valuations, but more importantly by a recent third party offer to buy such assets. These valuations and offer put the carrying value at more than three times the basis in the Ghanaian assets.

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4.

The Company is selling a globally traded commodity with strong market demand and known market value.



5.

In projecting its future taxable income, the Company used conservative oil pricing of $86.00/barrel and relied upon objective evidence supported by its proved reserves and production profile as verified by NSAI. Based on this pricing, the Company has estimated its 2011 taxable income in Ghana, before net operating loss ("NOL"), to be $248 million and this taxable income will offset 84% of the Company's $296 million NOL carryforward. At this level of pricing, these proved reserves will produce enough taxable income so that by or before the second quarter of 2012, the Company's entire Ghanaian NOL would be realized. We further note that the $86.00/barrel pricing assumed is substantially less than current market prices for Brent crude. If the current market prices of Brent crude are sustained through the end of 2011, we believe that it is likely that the Company will generate enough taxable income to utilize all its existing NOL carryforwards in Ghana, and could be a net taxpayer by the end of 2011.



6.

Unlimited NOL carryforwards under Ghanaian tax law which provides flexibility in utilization of the significant portion of the deferred tax asset.


The Company believes that it is important to note that while ASC 740-10-30-23 states that a cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome, there is no higher level standard that must be considered (i.e., probable or assured beyond reasonable doubt). ASC 740-10-30-5(e) provides a more-likely-than-not standard (i.e. 50%) in establishing a valuation allowance after weighing all of the available evidence. Using the more-likely-than-not standard the Company feels strongly that its positive evidence meets and exceeds this threshold and outweighs the negative evidence of cumulative losses. Accordingly, we believe that continuing to provide a valuation allowance as of December 31, 2010 would be inappropriately conservative, and would be misleading to readers of the financial statements.

Exhibits

12.

We note your disclosure at pages 62-63 regarding your new commercial debt facility. Please file a copy of the agreement documentation as an to your registration statement. See Item 601(b)(10) of Regulation S-K.

In the next Amendment to the Registration Statement to be filed with the Commission we will revise the Exhibit List to the Registration Statement and include new exhibits 10.17 and 10.20 (being the material documents relating to the Company's new commercial debt facility) in response to this comment.

        To the extent that you have any questions regarding the response contained in this letter, please do not hesitate to contact me at (212) 450-4674.

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        The following table sets forth the estimated future net revenues, excluding derivatives contracts, from net proved reserves and the expected benchmark prices used in projecting net revenues at December 31, 2010.

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Estimated proved reserves

        Unless otherwise specifically identified in this prospectus, the summary data with respect to our estimated proved reserves presented above has been prepared by NSAI, our independent reserve engineering firm, in accordance with the rules and regulations of the SEC applicable to companies

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Pursuant to farm-out agreements for the WCTP Block dated September 1, 2006, Anadarko WCTP Company, Tullow Ghana Limited and Sabre Oil and Gas Limited farmed into the WCTP Block. As a result, Kosmos Ghana, Anadarko WCTP Company, Tullow Ghana Limited and Sabre Oil & Gas Holdings Limited's participating interests are 30.875%, 30.875%, 22.896% and 1.854%, respectively. Kosmos Ghana is the operator. The EO Group owns a 3.5% "carried" working interest and all of EO Group's share of costs to first production from the WCTP Block are paid by Kosmos Ghana. EO Group is required to reimburse Kosmos Ghana for all development costs paid by Kosmos Ghana on EO Group's behalf, through future production proceeds. GNPC has a 10% participating interest and will be carried through the exploration and development phases. Under the WCTP Petroleum Agreement, GNPC exercised its option in December 2008 to acquire an additional paying interest of 2.5% in the Jubilee Field development (see "—Jubilee Field Unitization"). GNPC is obligated to pay its 2.5% share of all future petroleum costs as well as certain historical development and production costs attributable to its 2.5% additional paying interests in the Jubilee Unit. Furthermore, it is obligated to pay 10% of the production costs of the Jubilee Field development, as allocated to the WCTP Block. In August 2009, GNPC notified us and our unit partners it would exercise its right for the contractor group to pay its 2.5% WCTP block share of the Jubilee Field development costs and be reimbursed for such costs plus interest out of GNPC's production revenues under the terms of the WCTP Petroleum Agreement. Kosmos Ghana is required to pay a fixed royalty of 5% and a sliding-scale royalty ("additional oil entitlement") which escalates as the nominal project rate of return increases. These royalties are to be paid in-kind or, at the election of the government of Ghana, in cash. A corporate tax-rate of 35% is applied to profits at a country level.

        The WCTP Block as originally awarded comprised approximately 483,599 acres (1,957 square kilometers). Due to two contractual relinquishments at the commencement of contract periods, the WCTP Block currently comprises approximately 369,917 acres (1,497 square kilometers) in water depths ranging from 165 to 5,900 feet (approximately 50 to 1,800 meters). The term of the WCTP Petroleum Agreement is 30 years from the effective date of such agreement, being July 22, 2004. The initial exploration period of the block is three years, divided into two separate 18-month subperiods. In 2005, a 268,109 acre (1,085 square kilometers) 3D seismic survey was acquired, processed and interpreted by Kosmos Ghana. In 2006, Kosmos Ghana elected to proceed with the second subperiod with an exploration well commitment. The exploration well, Mahogany-1, was drilled and an oil discovery announced on June 18, 2007. The work and financial commitments were met for the initial exploration period. The next phase, the first extension period, commenced at the end of the initial exploration period and was for two years. The one exploration well commitment for this period was met by drilling the Odum-1 well, which tested a different prospect than the Mahogany-1 well. Odum-1 was announced as an oil discovery on February 25, 2008. In addition, the Mahogany-3 appraisal well was designed to test a deeper exploration objective and resulted in the Mahogany Deep discovery which was announced on January 8, 2009. In July 2009, Kosmos elected to enter the second and final two year extension period under the WCTP Petroleum Agreement. The commitment for this period was met by drilling of the Dahoma-1 well, which tested a different prospect from those tested by Mahogany-1 and Odum-1. All work and financial obligations for the exploration periods under the WCTP Petroleum Agreement have been met.

Deepwater Tano ("DT") Block

        Effective July 31, 2006, Kosmos Ghana, Tullow Ghana Limited and Sabre Oil and Gas Limited entered into the DT Petroleum Agreement with GNPC covering the DT Block offshore Ghana in the Tano Basin. Tullow Ghana Limited is the operator with a 49.95% working interest. Sabre Oil & Gas Holdings Limited has a 4.05% working interest. Kosmos Ghana originally held a 36% working interest in the block; however, as a result of a farmout by Kosmos Ghana to Anadarko WCTP Company effective September 1, 2006, Kosmos Ghana and Anadarko WCTP Company each have an 18%

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Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements

5. Jubilee Field Unitization (Continued)

approval in April 2009. On July 13, 2009, the Ministry of Energy provided its written approval of the Jubilee Field Phase 1 Development Plan. Jubilee Field development operations are ongoing.

6. Joint Interest Billings

        The Company's joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. EO Group's share of costs to first production were paid by Kosmos Ghana. EO Group is required to reimburse Kosmos Ghana for all development costs paid by Kosmos Ghana on EO Group's behalf, with repayment expected to be funded through EO Group's future production revenues. The related receivable of $61.7 million became due upon commencement of production. In August 2009, GNPC notified us and our applicable unit partners that it would exercise its right for the applicable contractor group to pay its 2.5% WCTP Block share and 5.0% DT Block share of the Jubilee Field development costs and be reimbursed for such costs plus interest out of a portion of GNPC's production revenues under the terms of the WCTP Petroleum Agreement and DT Petroleum Agreement, respectively. Oil production commenced on November 28, 2010. Joint interest billings are classified on the face of the consolidated balance sheets between current and long-term based on when recovery is expected to occur. Long-term balances of $41.6 million and $21.9 million are shown net of allowances of zero and $39.8 million as of December 31, 2009 and 2010, respectively.

7. Property and Equipment

        Property and equipment is stated at cost and consisted of the following:

        The Company recorded $0.6 million, $1.9 million and $2.2 million of depreciation expense for the years ended December 31, 2008, 2009 and 2010, respectively.

8. Suspended Well Costs

        The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or is impaired. The capitalized exploratory well costs are presented in oil

F-17

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Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

12. Asset Retirement Obligations

        The following table summarizes the changes in the Company's asset retirement obligations:

        The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently, no Ghana environmental regulations expressly require that companies abandon or remove offshore assets although under international industry standards we would do so. The Petroleum Law provides for restoration which includes removal of property and abandonment of wells, but further states the manner of such removal and abandonment will be as provided in the Regulations; however, such Regulations have not been promulgated. Under the Environmental Permit for the Jubilee Field, issued to Tullow Ghana, Ltd., a decommissioning plan will be prepared and submitted to the Ghana Environmental Protection Agency. ASC 410 requires the Company to recognize this liability in the period in which the liability was incurred. We have recorded an asset retirement obligation for fields that have commenced production, including wells in progress in such fields. Accordingly, the Company recognized a liability in the quarterly period ending December 31, 2010 related to our asset retirement obligations.

13. Convertible Preferred Units

        On February 11, 2004, under the Kosmos Energy Holdings Contribution Agreement, Kosmos received provisional commitments of up to $300.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors, to pursue the acquisition, exploration and development of oil and gas ventures in West Africa. For each $10 contribution, one Series A Convertible Preferred Unit ("Series A") was issued. Contributions began on March 9, 2004.

        On June 18, 2008, under the Kosmos Energy Holdings Amended and Restated Contribution Agreement, Kosmos secured an additional provisional commitment of up to $500.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors. For each $25 contribution, one Series B Convertible Preferred Unit ("Series B") was issued. Contributions began on November 3, 2008.

        On October 9, 2009, under the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, Kosmos secured an additional provisional commitment of up to $250.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors. For each $28.25 contribution, one Series C was issued. Contributions began on November 2, 2009. Upon execution and delivery and per Section 1.4 of the Kosmos Energy

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Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

from those used; and actual costs may vary. Kosmos' investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a wide range of different price and cost assumptions.

        The standardized measure is intended to provide a better means to compare the value of Kosmos' proved reserves at a given time with those of other oil producing companies than is provided by comparing raw proved reserve quantities.

Changes in the Standardized Measure for Discounted Cash Flows

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Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

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Kosmos Energy Holdings (A Development Stage Entity) Notes to Consolidated Financial Statements