cak_corresp.htm

Houston Headquarters

1330 Post Oak Blvd, Suite 2250, Houston, TX 77056

Tel: 713-797-2940 Fax: 713-797-2990

January 7, 2012

VIA EDGAR CORRESPONDENCE

Mr. Brad Skinner

Senior Assistant Chief Accountant

United States Securities and Exchange Commission

Division of Corporation Finance

101 F Street N.E.

Washington, D.C. 20549

Re: CAMAC Energy, Inc.

Form 10-K for Fiscal Year Ended December 31, 2011

Filed March 15, 2012

Definitive Proxy Statement on Schedule 14A

Filed April 30, 2012

File No. 1-34525

Dear Mr. Skinner:

We have received your letter dated December 20, 2012 (the “Comment Letter”), addressed to Dr. Kase Lukman Lawal, Chief Executive Officer of CAMAC Energy, Inc. (the “Company”), pursuant to which you provided comments from the staff (the “Staff”) of the United States Securities and Exchange Commission (“SEC”) pertaining to our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (File No. 1-34525) filed with the SEC on March 15, 2012 (“Form 10-K”) and our Definitive Proxy Statement on Schedule 14A (File No. 1-34525) filed with the SEC on April 30, 2012 (the “Proxy Statement”).

We have set forth below the responses of the Company to the Staff’s comments on Form 10-K and the Proxy Statement. For your convenience, the comments contained in your Comment Letter are set forth below verbatim in italicized text. We have also attached hereto as Exhibits A through D drafts of certain revised disclosures discussed herein that we will include in a Form 10-K/A for the fiscal year ended December 31, 2011 (the “Form 10-K/A”) in response to certain of the Staff’s comments. We will file the Form 10-K/A after we receive clearance from the Staff for our proposed revisions. For purposes of this letter, we have included only the relevant portions of the various Items that are being revised. In accordance with Rule 12b-15, however, we will include the full text of each Item affected when we file the final Form 10-K/A.

Form 10-K for Fiscal Year Ended December 31, 2011

Description of Business, page 4

Nigeria-Oyo Field Production Sharing Contract Interest, page 4

1. From the disclosure provided on page 4, it appears that the results of the workover on the #5 well did not achieve your objective of “increasing crude oil production from this well” and that “the water production has increased again.” Please tell us how you have taken into consideration the lack of an increase in the oil production rate and the increase in water production since the workover in estimating the proved reserves as of December 31, 2011 for well #5. Also tell us if all of the proved reserves attributable to this well can be recovered absent further intervention to reduce gas and/or water production.

Response:

The objective of the workover of well #5 in the Oyo Field was to reduce the large amount of gas production from this well. No increase in production or additional reserves that would have resulted from a successful workover were assumed in estimating proved reserves prior to the completion of the workover or after. Proved reserves as of December 31, 2011 were estimated assuming the high gas production rate would continue with a limited oil rate. The remaining reserves attributable to well #5 in the Oyo Field are expected to be recovered under current high gas and/or water production conditions without future intervention.

Operations, page 8

Please expand your organizational chart on page 8 to include CAMAC Energy, Inc. and CAMAC International Limited. Also, please provide the full and shortened names of each entity. For example, we note that your chart refers to CAMAC Nigeria whereas you reference CINL throughout your filing.

Response:

We have revised the chart to reflect the Staff’s comment and have also revised the relevant paragraphs of the Form 10-K to provide further clarification. These changes are attached hereto as Exhibit A and will be included in a Form 10-K/A to be filed by the Company. We note that CAMAC Energy Inc. holds certain rights under the OML 120/121 PSC by assignment from CINL and Allied (the Oyo Contract Rights and the Non-Oyo Contract Rights) but does not appear on the chart as it does not hold an interest in the underlying license.

Crude Oil Reserves, page 12

We note your presentation of PV-10. Please note that this represents a non-GAAP measure which is required to include the disclosures identified in Item 10(e)(1)(i) of Regulation S-K. Revise your presentation to include the required disclosures.

Response:

We have revised the presentation in response to the Staff’s comment to properly label the disclosed amounts as the standardized measure of discounted future net cash flows for proved reserves, which is a GAAP measure. The changes are attached hereto as Exhibit B and will be included in a Form 10-K/A to be filed by the Company.

Development of Proved Undeveloped Reserves, page 13

We note you state on page 13 that “none of our proved undeveloped reserves currently have remained undeveloped for more than five years from the date of initial recognition as proved undeveloped.” For purposes of determining the five year period for development to occur in estimating proved undeveloped reserves, Item 1203(d) of Regulation S-K requires that you use the date of the initial disclosure as the starting reference date. Please tell us the extent to which any of the proved undeveloped reserves disclosed as of December 31, 2011 will not be developed within five years since your initial disclosure of these reserves.

Response:

Under current development plans, all proved undeveloped reserves disclosed as of December 31, 2011 are expected to be developed within five years of the initial disclosure of these reserves.

Environmental and Governmental Regulation, page 14

To the extent material, disclose the material effects of compliance with environmental regulations as Item 101(c)(xi) of Regulation S-K requires. For example, we note your related risk factors on pages 24 and 25.

Response:

During the fiscal year ended December 31, 2011, the Company did not have any material expenditures for Environmental and Governmental Regulation. In response to the Staff’s comment, we have revised the disclosure to include a statement to this effect. The changes are attached hereto as Exhibit C and will be included in a Form 10-K/A to be filed by the Company.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 33

Results of Operations, page 39

The discussion under this section indicates, in part, that your share of net production from the Oyo filed varies materially from period to period. However, the discussion does not explain the reasons for this variance. Revise your disclosure to explain, in reasonable detail, the specific reasons why your share of net production from the Oyo field varies from period to period. Note that this comment also applies to the discussion of interim period results of operations included in your reports on Form 10-Q.

Response:

We acknowledge the Staff’s comments and propose to provide the following more detailed disclosure in future filings on Forms 10-Q and 10-K:

Cost Oil, as defined in the terms of the OML 120/121 PSC, is a significant component of the allocation of production and is dedicated to the recovery of costs previously paid by the partners. Prior to June 2011, virtually all expenditures for capital and operating costs of this field since the commencement of the OML 120/121 PSC had been funded by NAE. Therefore, through that date, all Cost Oil was allocated to NAE. During December 2010 and year 2011, the Company incurred $59.6 million in total costs relative to the workover to reduce gas production rising from the #5 well in the Oyo Field, offshore Nigeria, with the objective of increasing crude oil production from this well. By joint agreement with Allied, the Company will pay for the workover. Through December 31, 2011, the Company has paid $39.2 million of the $59.6 million incurred related to the workover, of which $30.3 million had been recovered through the allocation of Cost Oil. To the extent the Company additionally funds these costs, it is entitled to cost recovery of such costs as non-capital costs from Cost Oil, as defined in the terms of the OML 120/121 PSC, subject to future production levels. For purposes of Cost Oil recovery on each sale of production, non-capital costs are allocated for recovery prior to capital costs.

Financial Statements

Note 3: Significant Accounting Policies, page 66

Impairment of Long-Lived Assets, page 67

7. We note that a review for impairment of long-lived assets is required whenever changes

in circumstances indicate that the carrying amount of assets may not be fully recoverable. Please tell us whether you reviewed for impairment during 2011 the capitalized costs related to your oil and gas activities in Africa and explain to us the basis for your conclusion.

As part of your response, address the 2011 downward revision of 2,288,000 barrels of oil, as disclosed on page 90 of your supplemental data, and whether it was a change in circumstance that would have required you to review for impairment your capitalized costs.

Additionally, please explain to us how you considered as part of your impairment evaluation a comparison of the $80,312,000 future net cash flows before discount for Africa, as disclosed on page 92 in your Standardized Measure of Discounted Future Net Cash Flows calculation, and the net capitalized costs of $195,979,000 that relate to Africa, as disclosed on page 91 of your capitalized costs table. The difference between these two amounts suggests that your costs may not be recoverable.

Response:

As disclosed in the notes to consolidated financial statements, The Company reviews its long-lived assets in accordance with ASC Topic 360, Property, Plant and Equipment. The Company performed a review for impairment of capitalized costs related to Oil and Gas activities in Africa during 2011 and concluded that an impairment charge was not required.

The December 31, 2011 Reserve Report reflected a reduction in proved oil reserves of 2.3 million barrels, or approximately 43% of 2010 proved reserves. We determined that this represented a significant change in circumstances related to the realizable value of our oil and gas assets. Therefore, as required by ASC Topic 360, we calculated the undiscounted future net cash flows of our oil and gas assets using the 2011 Reserve Report and adjusting the probable and possible reserves and future net cash flows for risk. We reduced the undiscounted future net cash flows of probable and possible reserves by 50% and 90%, respectively. See calculation summary below:

Net Proved Reserves at	100%	=	$ 80,311,900
Net Probable Reserves at	50%	=	$105,045,100
Net Possible Reserves at	10%	=	$ 67,504,660

Total risk adjusted undiscounted future net revenues		=	$252,861,660

The risk adjusted undiscounted future net cash flows were in excess of the Company’s Oyo Field oil and gas long-lived assets’ carrying value of $190,979,000. As a result, we concluded that no impairment charge was required.

In addition, we calculated a revised depletion rate using only the 2011 Reserve Report proved oil reserves, which resulted in a rate of $72 per barrel. When the resulting higher depletion rate of $72 per barrel was compared to the Company’s 2011 average price per barrel sold of $113 per barrel and other future pricing information, we concluded that the Company would still realize net profit from future sales of oil. We have used the new depletion rate beginning January 1, 2012.

Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited), page 90

Estimated Net Proved Crude Oil Reserves, page 90

8. We note your disclosure of the changes in net quantities of your proved reserves in Table

1 on page 90. As part of the changes for the period ending December 31, 2011, you disclose a significant downward revision of previous estimates which appears to include a material change in your proved undeveloped reserves. Your filing does not appear to include any explanation of the significant changes in your reserves. Please revise your disclosures as necessary to comply with Item 1203(b) of Regulation S-K and FASB ASC paragraph 932-235-50-5.

Response:

We have revised the disclosure in response to the Staff’s comment to provide an explanation for the revision to estimated reserves at December 31, 2011 from December 31, 2010. The changes are attached hereto as Exhibit D and will be included in a Form 10-K/A to be filed by the Company.

Exhibit 99.1

From the disclosure provided on page 2 of the report, we note “capital costs are included as required for a workover and new development wells.” Please provide us with the capital costs for each development well and workover and a schedule showing the month and year that each development well and workover is forecast to go on production in the report.

Response:

As requested, below is the capital costs schedule.

Well/Workover	Gross Capex ($M)	Production Start Date
Oyo 7 development well	$100,859	1/1/2013
Oyo 8H development well	$105,836	4/1/2013
Oyo 9H development well	$100,859	1/1/2014

Definitive Proxy Statement on Schedule 14A

Executive Compensation and Other Information, page 17

Compensation Discussion and Analysis, page 17

10.

Please provide further analysis of how you arrived at and why you paid each of the particular forms and levels of compensation for 2011. For example, you state that the annual bonuses were based on “achievement of short-term corporate goals and to recognize individual and team achievements.” Please provide sufficient quantitative and qualitative analysis of the factors the compensation committee considered in making specific compensation awards.

In addition, please disclose the targets the compensation committee used in its determination to award annual bonuses for the named executive officers. Refer to prior comment 2 from our letter dated January 14, 2010.

Response:

In accordance with what we disclosed in the Compensation Discussion and Analysis (“CD&A”) in our 2012 proxy statement, the principal components of compensation for the executive officers are (1) base salary, (2) annual cash incentive compensation (bonus) and (3) long-term incentive compensation. The Compensation Committee (the “Committee”) engaged a firm specializing in executive compensation analysis to provide the Committee with market data and advice regarding executive compensation packages in our industry as well as to conduct an annual review of the total direct compensation to the executive officers for market competitiveness. The details of this process and the role of the Committee and the consultant are set out in our CD&A.

Base Salary: The base salaries for each of the named executive officers were established in their written employment agreements entered into in 2011. As stated in the CD&A on page 18 of the proxy statement, the Committee concluded that the base salaries of the executives were aligned with the base salary philosophy to remain competitive with other companies in its peer group.

Annual Bonus: The annual cash bonus for each of the named executive officers is established by their written employment agreements to be between 0-100% of base salary at the discretion of the Committee. The Committee exercised its business judgment in determining the relative success in meeting Company, individual, and team goals that it relied upon in making the 2011 annual incentive payouts to executives. Each of the executive officers that received annual bonus payouts had a targeted annual bonus of 50% of base salary as disclosed in the CD&A on page 23 of the proxy statement. As such, the Committee received recommendations from the CEO and reviewed past annual Company and individual performance to determine the annual incentive payouts for each executive. Each of the named executive officers that received bonuses commenced employment after the beginning of 2011, and accordingly each of the annual incentive bonuses were prorated to reflect both actual length of service of the executive during 2011 in terms of potential contribution and the full amount of bonus based upon actual contribution, as determined by the Committee. As stated in the CD&A, the Committee reserves and retains the ability to apply discretion and modify annual incentive awards as it sees fit. In terms of its discretion the Committee considered both quantitative and qualitative objectives as set for each executive with regard to the commencement of employment, the challenges presented, the retention and motivation of the executive with regard to immediate and future requirements on behalf of shareholders and an assessment of the executives overall fit and leadership capacity on behalf of the organization itself.

Long-Term Incentive: As described in the CD&A, the Committee has authority to award equity incentive compensation to executive officers in its sole discretion. The long-term equity compensation granted in 2012 was determined by reference to the market analysis prepared by the consultant, also taking into consideration Company performance, individual performance and retention concerns.

We also note that we believe our discussions regarding how any particular officer or employee met or did not meet certain established standards should be held privately with the particular officer or employee and that public explanations as to why standards were or were not met by any particular officer or employee are not appropriate. We propose, however, to include a paragraph similar to the following in our 2013 proxy statement, which will apply to all discussions about compensation of officers or directors:

The Company is aware of its responsibility in hiring and retaining competent and responsible officers and employees. The Company consults with firms specializing in compensation analyses so that its employees are receiving compensation and incentive plans at least comparable to that of similar companies and are rewarded for providing the best service for the benefit of the shareholders. In the following discussions, we disclose which named officers or directors have participated in various incentive plans and any standards they are expected to meet in order to receive such benefits. We also disclose how much they have received under those plans during the past fiscal year, and in some cases for prior years.

Unless we specifically state otherwise, all of the factors considered in determining salaries and other compensation are applied to the individual officers and employees with regard to their positions, duties, extent of authority, responsibilities, performance of the individual, and performance of the Company. We do not disclose publicly the degree to which any particular officer or employee met a particular standard. We do not disclose this information because there is a personal relationship between the officer or employee and the Company, and such disclosure may be an invasion of that employee's privacy. The Committee has been charged with fair administration of base and incentive compensation to officers and the Board of Directors believes that the Committee has always and will continue to use its business judgment in carrying out its objectives.

In Connection with its response, CAMAC Energy Inc. acknowledges that:

●	CAMAC Energy Inc. is responsible for the adequacy and accuracy of the disclosures in the filings;

●	Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filings; and

●	CAMAC Energy Inc. may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

If you have any questions or comments regarding this letter, please contact the undersigned at 713 797 2940.

Very truly yours,

CAMAC Energy Inc.

By:	/s/ Nicolas J. Evanoff
	Nicolas J. Evanoff
	Senior Vice President & General Counsel

EXHIBIT A

Operations

Africa – OML 120/121 Production Sharing Contract

On December 15, 2009, NAE, a subsidiary of Italy’s ENI SpA, and CEHL announced that they had commenced production of the Oyo Field. The Oyo Field has been producing from two subsea wells in a water depth of greater than 300 meters, which are connected to the Armada Perdana Floating Production Storage and Offloading (“FPSO”) vessel. The FPSO has a treatment capacity of 40,000 barrels of liquids per day, with gas treatment and re-injection facilities, and is capable of storing up to one million barrels of crude oil. The first lifting (sale) of crude oil was in February 2010. The associated gas has been largely re-injected into the Oyo Field reservoir by a third well, to minimize flaring and to maximize oil recovery. During December 2010 and year 2011, the Company incurred $59.6 million in costs relative to the workover to reduce gas production rising from the #5 well in the Oyo Field with the objective of increasing crude oil production from this well. By joint agreement with Allied, the Company will pay for the workover. We recovered a significant portion of these costs as revenue in 2011 and expect to recover the remainder in future liftings.

On July 22, 2005, a Production Sharing Contract (the “OML 120/121 PSC”) was signed among CEHL affiliates (Allied and CINL) and NAE. Pursuant to the OML 120/121 PSC, NAE assumed the rights and obligations as the Operating Contractor to the petroleum operations in the Oyo field and was assigned an undivided 40% interest, with Allied retaining an undivided 57.5% interest and CINL retaining the remaining undivided 2.5% interest. The parties to the OML 120 /121 PSC are represented in the chart below.

As previously discussed, in two separate transactions, the Company acquired the Oyo Contract Rights and the Non-Oyo Contract Rights related to the OML 120/121 PSC by assignment, but does not hold an interest in the underlying license. The percentages held by Allied, CINL and NAE, however, are not indicative of the actual allocation of proceeds from production of oil or other hydrocarbons under the Oyo Contract Rights and the Non-Oyo Contract Rights because such allocations are affected by the amount of participation in funding of OML 120/121 PSC operating and capital costs.

EXHIBIT B

Summary of Crude Oil Reserves

The following estimates of the net proved oil reserves of our oil and gas properties located in Nigeria are based on evaluations prepared by NSAI. Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost changes except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available. The Company presently has no reserves in China.

Crude Oil Reserves

(1)

Standardized Measure of Discounted Future Net Cash Flows reflects our estimated future net revenues, net of estimated income taxes, to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the average of the first-day-of-the-month commodity prices during the 12-month period ended on December 31, 2011) without giving effect to non-property related expenses such as DD&A expense and discounted at 10 percent per year. The average first-day-of-the-month commodity prices during the 12-month periods ending on December 31, 2011 and 2010, were $112.26 and $79.21 per barrel of crude oil, respectively, including differentials.

EXHIBIT C

Environmental and Government Regulation

Various federal, state, local and international laws and regulations relating to the discharge of materials into the environment, the disposal of oil and natural gas wastes, or otherwise relating to the protection of the environment may affect our operations and costs. We are committed to the protection of the environment and believe we are in substantial compliance with the applicable laws and regulations. However, regulatory requirements may, and often do, change and become more stringent, and there can be no assurance that future regulations will not have a material adverse effect on our financial position, results of operations and cash flows. During the year ended December 31, 2011, we did not have any significant expenditures relating to environmental and government regulation.

EXHIBIT D

Estimated Net Proved Crude Oil Reserves

The following estimates of the net proved crude oil reserves in Nigeria are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available. Our proved undeveloped reserves were revised downward at December 31, 2011 after a reinterpretation by our third-party reservoir engineers of certain reservoir geoscience data. After this evaluation we removed the updip oil volumes for a portion of the reservoir from estimates of proved reserves at December 31, 2011.