UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from: _____________ to _____________

001-34525

(Commission File Number)

CAMAC ENERGY INC.

 (Exact name of registrant as specified in its charter)

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Delaware	30-0349798
(State or Other Jurisdiction	(I.R.S. Employer
of Incorporation or Organization)	Identification No.)

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

 (Address of Principal Executive Office) (Zip Code)

(713) 797-2940

(Registrant’s telephone number, including area code)

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Securities registered pursuant to Section 12(b) of the Act:

Common Stock, $0.001 par value

Securities registered pursuant to Section 12(g) of the Act:

None

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨   No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨   No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ    No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes   þ   No   ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or  information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o   Accelerated filer o   Non-accelerated filer ¨   Smaller reporting company þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨    No þ

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $40,715,302 based on a share price of $0.63.  All executive officers and directors of the registrant have been deemed, solely for the purpose of the forgoing calculation, to be “affiliates” of the registrant.

As of April 9, 2013, there were 156,224,287 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement or Form 10-K/A relating to the Company’s Annual Meeting of Stockholders to be held on May 13, 2013 are incorporated by reference in Part III of this report.

CAMAC Energy Inc.

FORM 10-K

TABLE OF CONTENTS

		Page
Cautionary Statement Relevant to Forward-Looking Information			3
PART I
Item 1.	Description of Business		4
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		24
Item 2.	Properties		25
Item 3.	Legal Proceedings		25
Item 4.	Mine Safety Disclosures		25
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
Item 6.	Selected Financial Data		27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		35
Item 8.	Financial Statements and Supplemental Data		35
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		36
Item 9A.	Controls and Procedures		36
Item 9B.	Other Information		36
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		37
Item 11.	Executive Compensation		37
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		37
Item 13.	Certain Relationships and Related Transactions, and Director Independence		37
Item 14.	Principal Accountant Fees and Services		37
PART IV
Item 15.	Exhibits, Financial Statements and Schedules		38
Signatures			42

2

CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION

All statements, other than statements of historical fact, included in this Form 10-K, including without limitation the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” are, or may be deemed to be, forward-looking statements. Such forward-looking statements involve assumptions, known and unknown risks, uncertainties and other factors, which may cause the actual results, performance or achievements of CAMAC Energy Inc. and its subsidiaries and joint-ventures (collectively, the “Company”), to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements contained in this Form 10-K.

In our capacity as Company management, we may from time to time make written or oral forward-looking statements with respect to our long-term objectives or expectations which may be included in our filings with the Securities and Exchange Commission (the “SEC”), reports to stockholders and information provided on our web site.

The words or phrases “will likely,” “are expected to,” “is anticipated,” “is predicted,” “forecast,” “estimate,” “project,” “plans to continue,” “believes,” or similar expressions identify “forward-looking statements.”  Such forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from historical earnings and those presently anticipated or projected.  We wish to caution you not to place undue reliance on any such forward-looking statements, which speak only as of the date made.  We are calling to your attention important factors that could affect our financial performance and could cause actual results for future periods to differ materially from any opinions or statements expressed with respect to future periods in any current statements.

The following list of important factors may not be all-inclusive, and we specifically decline to undertake an obligation to publicly revise any forward-looking statements that have been made to reflect events or circumstances after the date of such statements or to reflect the occurrence of anticipated or unanticipated events.  Among the factors that could have an impact on our ability to achieve expected operating results and growth plan goals and/or affect the market price of our stock are:

● Limited operating history, operating revenue or earnings history.

● Ability to raise capital to fund our current and future operations, including participation in the Oyo Field development and  other oil and gas leases we may participate in, on terms and conditions acceptable to the Company.

● Ability to develop oil and gas reserves.

● Dependence on key personnel, technical services and contractor support.

● Fluctuation in quarterly operating results.

● Possible significant influence over corporate affairs by significant stockholders.

● Ability to enter into definitive agreements to formalize foreign energy ventures and secure necessary exploitation rights.

● Ability to successfully integrate and operate acquired or newly formed entities and multiple foreign energy ventures and subsidiaries.

● Competition from large petroleum companies and other energy interests.

● Changes in laws and regulations that affect our operations and the energy industry in general.

● Risks and uncertainties associated with exploration, development and production of oil and gas, and drilling and production risks.

● Expropriation and other risks associated with foreign operations.

● Risks associated with anticipated and ongoing third party pipeline construction and transportation of oil and gas.

● The lack of availability of oil and gas field goods and services.

● Environmental risks and changing economic conditions.

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PART I

ITEM 1.  DESCRIPTION OF BUSINESS

General

Throughout this Annual Report on Form 10-K, the terms “we,” “us,” “our,” “Company,” and “our Company” refer to CAMAC Energy Inc. (“CAMAC”), formerly Pacific Asia Petroleum, Inc. (“PAP”), a Delaware corporation, and its present and former subsidiaries.

CAMAC is engaged in the exploration, development, and production of oil and gas outside the United States, and through other ventures in which it may participate. Members of the Company’s senior management team have experience in the fields of international business development, geology, petroleum engineering, strategy, government relations and finance.  Members of the Company’s management team previously held positions in oil and gas development and screening roles with domestic and international energy companies and will seek to utilize their experience, expertise and contacts to create value for shareholders. The Company’s focus is oil and gas exploration and production operations, which are managed geographically.  Our current operations are in Nigeria, Kenya and The Gambia. Our shares are traded on the on the NYSE MKT under the symbol “CAK”.

In August 2012, the Company divested its wholly-owned Hong Kong subsidiary Pacific Asia Petroleum Limited (“PAPL”) for cash consideration of $2.5 million and 9.6 million fully paid ordinary shares, net of selling expenses, of Leyshon Resources Limited (“Leyshon”), a natural resources mining company based in Beijing, China.  The Leyshon shares had a fair market value of $1.9 million, and have since been sold.

PAPL held the Company’s interest in the Zijinshan production sharing contract relating to the Zijinshan Block in the Shanxi Province of China. Since 2008, the Company engaged in exploration activities on this Block in search of coalbed methane and other gas.  The Company made a strategic decision to monetize this asset and withdraw from activity in China in order to focus its efforts and capital resources on its core Africa activities.

As a result of the above transaction, the Company is reporting Asia operations for all presented periods in discontinued operations and, as such, the financial statement information provided in this report for continuing operations for the years ended December 31, 2012 and 2011 are presented in one reportable segment.

Available Information

We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (“Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street NE, Washington, DC 20549-0213. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

We also make available, free of charge on or through our Internet website (http://www.camacenergy.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our website.

In addition, we have adopted a Code of Ethics and Business Conduct that applies to all of our employees, including our chief executive officer, principal financial officer and principal accounting officer. The text of the Code of Ethics and Business Conduct has been posted on the Corporate Governance section of our website. Additionally, the Code of Ethics and Business Conduct is available in print to any person who requests the information. Individuals wishing to obtain this printed material should submit a request to CAMAC Energy Inc., 1330 Post Oak Boulevard, Suite 2250, Houston, TX 77056, Attention: Investor Relations.

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Executive Summary of 2012

Nigeria - Oyo Field Production Sharing Contract Interest

In December 2009, Nigerian Agip Exploration Limited (“NAE”), a subsidiary of Italy's ENI SpA, and CAMAC Energy Holdings Limited (“CEHL”) announced that they had commenced production of the Oyo Field, offshore Nigeria. 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.  Some of the associated gas has been re-injected into the Oyo Field reservoir by a third well, to minimize flaring and to maximize oil recovery.

Through December 31, 2012, the Company incurred a total of $59.7 million in costs relative to the workover to reduce gas production rising from well #5 in the Oyo Field, offshore Nigeria, with the objective of increasing crude oil production from this well.  By joint agreement with Allied Energy Plc. (“Allied”), a related party, the Company has committed to pay for the workover. To the extent the Company 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 Production Sharing Contract (“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. As of December 31, 2012, $40.4 million of these costs have been recovered as revenue and we expect to recover the remainder as revenue in future liftings.  In connection with funding for part of these costs prior to receiving cost recovery, the Company entered into a Promissory Note and Guaranty Agreement with a related party, which is discussed below under “Promissory Note and Guaranty Agreement.” The remainder is being funded using available cash and the future Oyo Field lifting proceeds.

The workover on well #5 in the Oyo Field initially reduced the amount of gas and water production; however, the oil production rate did not significantly improve.  The current water cut is approximately 27% with the gas production fairly stabilized over time.

Well #6 in the Oyo Field currently produces at a water cut of approximately 81%. The Company continues to evaluate the viability of placing this well on a gas lift to increase the oil rate.

Based on the production history of the Oyo Field, the 2011 completed study by Netherland, Sewell & Associates Inc., and validated by a recent in-house simulation study, the Company believes that three additional development wells will be required to recover all economically recoverable reserves in the Central West block, in which the Oyo Field is located.  Three additional wells will also be required to recover the possible reserves from the Central Eastern block.  The Company is continuing to explore options for marketing Oyo Field gas to third party gas processing and transportation facilities.

Allied has informed the Company that it plans to drill a new well in the Oyo Field commencing in mid 2013.  The new well, Oyo #7, will be designed to both increase the current oil production levels and test the prospective resource potential of the deeper Miocene reservoir in the field.

Nigeria - OML 120/121 Transaction

In April 2010, the Company acquired from affiliates of CEHL their interests relating to the Oyo Field (the “Oyo Contract Rights”) in the OML 120/121 PSC in exchange for cash and shares of common stock of the Company.

In December 2010, the Company entered into a Purchase and Continuation Agreement (the “Purchase Agreement”) with CEHL and such affiliates, pursuant to which the Company agreed to acquire certain of the remainder of the affiliates’ interest (the “OML 120/121 Transaction”) in the OML 120/121 PSC (the “Non-Oyo Contract Rights”).  In exchange for the Non-Oyo Contract Rights, the Company agreed to an option-based consideration structure and paid $5.0 million in cash to Allied , an affiliate of CEHL, upon the closing of the OML 120/121 Transaction in February 2011. The Company has the option to elect to retain the Non-Oyo Contract Rights upon payment of additional consideration to Allied upon the achievement of certain milestones relating to exploration and production outside of the Oyo Field.

If any of the milestones are reached and the Company elects not to retain the Non-Oyo Contract Rights at that time, then all the Non-Oyo Contract Rights will automatically revert back to CEHL without any compensation due to the Company and with CEHL retaining all consideration paid by the Company to date.  As of December 31, 2012, none of the milestones had been reached.

Dr. Kase Lawal, the Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is a director of each of CEHL, CAMAC International (Nigeria) Limited (“CINL”), and Allied.  Dr. Lawal also owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CEHL.  As a result, Dr. Lawal may be deemed to have an indirect material interest in the transactions contemplated by the OML 120/121 PSC.  Chairman Lawal recused himself from participating in the consideration and approval by the Company’s Board of Directors of the OML 120/121 Transaction.

5

Promissory Note and Guaranty Agreement

On June 6, 2011, CAMAC Petroleum Limited (“CPL”), a wholly owned subsidiary of the Company, executed a Promissory Note (the “Promissory Note”) in favor of Allied (the “Lender”). Under the terms of the Promissory Note, the Lender agreed to make loans to CPL, from time to time and pursuant to requests by CPL, in an aggregate sum of up to $25.0 million. Interest accrues on outstanding principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum.  CPL may prepay and re-borrow all or a portion of such amount from time to time.  Pursuant to the initial terms of the Promissory Note, the unpaid aggregate outstanding principal amount of all loans, was to mature on June 6, 2013.  Subsequently, in August 2012 the Promissory note was amended to extend the maturity date to October 15, 2013, and then amended again in March 2013 to extend the maturity date to July 15, 2014.  The Company has irrevocably, unconditionally and absolutely guaranteed all of CPL’s obligations under the Promissory Note.   As of December 31, 2012, $0.9 million was outstanding.

Dr. Kase Lawal, the Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is a director of each of CEHL, CINL, and the Lender.  Dr. Lawal also owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CEHL, and CINL and the Lender are each wholly-owned subsidiaries of CEHL. As a result, Dr. Lawal is deemed to have an indirect material interest in the transaction contemplated by the Promissory Note. Dr. Lawal fully disclosed the material facts as to his relationship to the Lender prior to Board approval.

Award of Kenya Exploration Blocks

In May 2012, the Company, through an indirect wholly owned subsidiary, entered into four production sharing contracts (“Kenya PSCs”) with the Government of the Republic of Kenya, covering previously awarded exploration Blocks L1B and L16, and new offshore exploration Blocks L27 and L28.  For all of the blocks, the Company will be the operator, with the government having the right to participate up to 20%, either directly or through an appointee, in any area subsequent to declaration of a commercial discovery.  The Company is responsible for all exploration expenditures.

The Kenya PSCs for Blocks L1B and L16 each provide for an initial exploration period of two years with specified minimum work obligations during that period.  Prior to the end of the initial exploration period, the Company will acquire and interpret gravity and magnetic data and acquire, process and interpret 2D seismic data.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploratory well on each block in each such additional period.

The Kenya PSCs for Blocks L27 and L28 each provide for an initial exploration period of three years with specified minimum work obligations during that period.  Prior to the end of the initial exploration period, the Company will conduct for each block a regional geological study and acquire, process and interpret 3D seismic data.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploratory well on each block, in each such additional period.

In addition to the minimum work obligations, each of the Kenya PSC’s require annual surface rental payments, training fund payments and contributions to local community development projects.  All of the Kenya PSCs also include customary provisions including but not limited to governing law, confidentiality, force majeure, arbitration, and abandonment and decommissioning costs.

Award of The Gambia Offshore Exploration Blocks

In May 2012, the Company, through an indirect wholly owned subsidiary, signed two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia (the “Licenses”), for previously awarded exploration blocks A2 and A5 (the “Blocks”).  For both Blocks, the Company will be the operator, with the Gambia National Petroleum Company (“GNPC”) having the right to elect to participate up to a 15% interest, following approval of a development and production plan. The Company is responsible for all expenditures prior to such approval even if the GNPC elects to participate.

The Licenses for both Blocks provide for an initial exploration period of four years with specified work obligations during that period.  Prior to the end of the initial exploration period, the Company will conduct for each Block a regional geological study, acquire, process and interpret 3D seismic data, drill one exploration well to the total depth of 5,000 meters below mean sea level and evaluate drilling results, with the first two work obligations due prior to the end of the second year.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploration well in each additional period for each Block.

In addition to the minimum work obligations, the Licenses require annual rental payments and training and resource fees.  Each of the Licenses also include customary provisions including but not limited to governing law, confidentiality, force majeure, arbitration, and abandonment and decommissioning costs.

6

Operations

Africa - OML 120/121 Production Sharing Contract

In December 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.  Some of the associated gas has been re-injected into the Oyo Field reservoir by a third well, to minimize flaring and to maximize oil recovery.

In June 2012, NAE completed the previously announced sale of its 40% working interest in OML 120/121 to Allied, an affiliate of CEHL.

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 and CINL, 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.

As Nigerian crude oil is readily marketable in international markets we are not dependent upon a single or a small number of customers.

The allocation between the parties of oil production is governed by the OML 120/121 PSC, available crude oil is allocated to four categories of oil: royalty oil (“Royalty Oil”), cost oil (“Cost Oil”), tax oil (“Tax Oil”) and profit oil (“Profit Oil”), in that order.  Proceeds from available crude oil are first used to pay royalty (“Royalty Oil”), recover Operating Costs and Capital Cost (“Cost Oil”) and pay tax (“Tax Oil”). The rest of the proceeds are distributed as Profit Oil to Contractors and First Party as shown in the chart below.  Prior to Allied’s acquisition of NAE in June 2012, the Company received the share allocable to Allied for the Oyo Contract Rights and would have received Allied’s share for the Non-Oyo Contract Rights. The complete OML 120/121 PSC was filed as Annex E to the Company’s proxy filed with the SEC on March 19, 2010.

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Profit oil is allocated to the parties according to the following schedule:

*Petroleum profit tax of 50% plus education tax of 2%, chargeable on the total remainder oil after deduction of amortization and investment allowance.

**Y-Factor:  NAE and Allied will share the Profit Oil to Contractor based on their contribution on Capital Costs and Non-Capital Costs.

***Through June 2012; Allied thereafter.

8

Reserves

The information included in this Annual Report on Form 10-K about our rights to proved reserves represents evaluations prepared by Gaffney, Cline & Associates (“GCA”), an independent petroleum engineering and geoscience advisory firm.  GCA has prepared evaluations on 100 percent of our right to proved reserves and the estimates of proved crude oil reserves attributable to our net interests in oil and gas properties as of December 31, 2012. The scope and results of GCA’s procedures are summarized in a letter which is included as an exhibit to this Annual Report on Form 10-K.  For further information on reserves, including information on future net cash flows and the standardized measure of discounted future net cash flows, please refer to the “Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)” within Part II, Item 8 of the Notes To Consolidated Financial Statements of  this report.

Internal Controls for Reserve Estimation

Our policies regarding internal controls over the recording of reserve estimation require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles.  The reserve estimates prepared by GCA are reviewed and approved by our management. The process performed by GCA to prepare reserve amounts includes the estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, before income tax.  In the conduct of their preparation of the reserve estimates, GCA did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its work, something came to its attention which brought into question the validity or sufficiency of any such information or data, GCA did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.

Technologies Used in Reserves Estimates

Proved reserves are those quantities of oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our independent petroleum consultants employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

● the quality and quantity of available data and the engineering and geological interpretation of that data;

● estimates regarding the amount and timing of future operating costs, taxes, development costs and workovers,  and our estimated participation  in funding of  future operating costs and capital expenditures, and ability to raise money to fund these costs, all of which may vary considerably from actual results;

● the accuracy of various mandated economic assumptions such as the future prices of oil and natural gas; and

● the judgment of the persons preparing the estimates.

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.

Qualifications of Reserves Preparers and Auditors

We obtain services of contracted reservoir engineers with extensive industry experience who meet the professional qualifications of reserves estimators and reserves auditors as defined by the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” approved by the Board of the Society of Petroleum Engineers in 2001 and revised in 2007.

The reserves estimates shown herein have been independently prepared by GCA, a leading international petroleum engineering consultancy. Within GCA the technical person primarily responsible for preparing the estimates set forth in the GCA reserves report incorporated herein is Mr. Mike Holmgren. Mr. Holmgren has been practicing consulting petroleum engineering at GCA since 2007. He is a Registered Professional Engineer in the State of Texas (License No. 37132) and has over 44 years of practical experience in petroleum engineering, with over 15 years of experience in the estimation and evaluation of reserves.

9

We have on staff a Reservoir Engineering Advisor and VP, Exploration with extensive industry experience who meets the professional qualifications of reserves estimators and reserves auditors as defined by the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” approved by the Board of the Society of Petroleum Engineers in 2001 and revised in 2007.

Our Reservoir Engineering Advisor, Mr. Lanre Dipeolu and Vice President, Exploration, Mr. James Deckelman are primarily responsible for the coordination of the third-party reserves report provided by GCA.  Mr. Lanre Dipeolu has over 28 years of experience in the oil industry and holds a BSc. in Petroleum Engineering from University of Ibadan, Nigeria and a MBA from Herriot Watt University, Edinburgh, United Kingdom. He is a member of the Society of Petroleum Engineers. Mr. Deckelman has over 25 years of international industry experience, has authored more than 15 technical publications, and holds a Bachelor of Arts Degree in Geology from Miami University and a Master of Science Degree in Geology from Utah State University.

Summary of Crude Oil Reserves

All of our rights to oil and gas reserves are located in Africa.  Unaudited information regarding the estimated net quantities of all our proved reserves and the standardized measure of discounted future net cash flows from the reserves is presented in the “Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)” within Part II, Item 8 of the Notes To Consolidated Financial Statements of this report.  The reserves estimates have been prepared by GCA and were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”).  Reserves 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.

Set forth below is a summary of our oil and gas net proved reserves and PV-10 as of December 31, 2012 and 2011, respectively.

	December 31, 2012				December 31, 2011
	Crude Oil		PV-10		Crude Oil		PV-10
	(MBbls)		(Thousands)(1)		(MBbls)		(Thousands)(1)
Proved
Developed		55				92
Undeveloped		3,043				2,571
Total Proved		3,098	$	80,542		2,663	$	74,263

(1) Present Value Discounted at 10% (“PV-10”) is a Non-GAAP (Generally Accepted Accounting Principles) measure that differs from the GAAP measure “standardized measure of discounted future net cash flows” in that PV-10 is calculated without regard to future income taxes. Management believes that the presentation of PV-10 value is relevant and useful to our investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, management uses, and believes the industry generally uses, the PV-10 measure in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and gas properties.

PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For presentation of the standardized measure of discounted future net cash flows, please refer to the “Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)” within Part II, Item 8 of the Notes To Consolidated Financial Statements of  this report.

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The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows as of December 31, 2012 and 2011 respectively.

	As of December 31,
	2012			2011
	(Thousands)
Present value of estimated future net cash flows (PV10)	$	80,542		$	74,263
Future income taxes, discounted at 10%		(14,830	)		(12,576	)
Standardized measure of discounted future net cash flows	$	65,712		$	61,687

Development of Proved Undeveloped Reserves

Under current development plans, all proved undeveloped reserves as of December 31, 2012, are expected to be developed within five years from the date of initial recognition of these reserves.

Oil and Gas Production, Prices and Production Costs — Significant Fields

The Oyo Field in Nigeria contains our entire total proved reserves as of December 31, 2012, 2011 and 2010, respectively.  Our share of average daily net production (excluding royalty) was 401 barrels per day in 2012, 923 barrels per day in 2011 and 396 barrels per day in 2010.  The weighted average sales price was $112.60 per barrel in 2012, $112.91 per barrel in 2011 and $85.16 per barrel in 2010.  Production cost per barrel was $6.34 per barrel in 2012, $8.61 per barrel in 2011 and $34.54 per barrel in 2010, excluding the workover expense.

Drilling Activity

During 2012 and 2011, the Company committed to 100% funding of the workover performed on well # 5 in the Oyo Field, Nigeria, which commenced in 2010 and was completed in 2011.  In 2012 and 2011 there were no new development or exploratory wells completed in the Company’s Nigeria interests in OML 120/121, including the Oyo Field.

Present Activities

Allied has informed the Company that it plans to drill a new well in the Oyo Field commencing in mid 2013.  The new well, Oyo #7, will be designed to both increase the current oil production levels and test the prospective resource potential of the deeper Miocene reservoir in the field.

Delivery Commitments

As of December 31, 2012, the Company had no delivery commitments.

Productive Wells

At December 31, 2012, the Company had rights to an interest in two gross productive wells in Nigeria. The number of net productive wells (net economic interest) in Nigeria at a particular date under our Production Sharing Contract is affected by our percentage of Cost Oil and Profit Oil realized in each lifting. This percentage has varied significantly between 2012 and 2011 and is expected to continue to vary for the foreseeable future as the Company has the right, but is not required, to fund up to 30% of the expenditures on the OML 120/121 Production Sharing Contract.  Therefore, a calculation of net productive wells interest for a particular year-end is not meaningful.

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Acreage

Interests in developed and undeveloped acreage follow:

	December 31, 2012
	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Kenya						9,121,482		9,121,482		9,121,482		9,121,482
Gambia						658,822		658,822		658,822		658,822
Nigeria		8,600		5,200		434,900		260,900		443,500		266,100
Total		8,600		5,200		10,215,204		10,041,204		10,223,804		10,046,404

The Company has no acreage on which leases are scheduled to expire within the three years after December 31, 2012.

Regulation

General

Our operations and our ability to finance and fund our growth strategy are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:

●   change in governments;

●   civil unrest;

●   price and currency controls;

●   limitations on oil and natural gas production;

●   tax, environmental, safety and other laws relating to the petroleum industry;

●   changes in laws relating to the petroleum industry;

●   changes in administrative regulations and the interpretation and application of such rules and regulations;  and

●   changes in contract interpretation and policies of contract adherence.

In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed, sometimes retroactively, for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and our potential for economic loss.

Competition

The Company competes with numerous large international oil companies and smaller oil companies that target opportunities in markets similar to the Company’s, including the natural gas and petroleum markets. Many of these companies have far greater economic, political and material resources at their disposal than the Company.  The Company’s management team has prior experience in the fields of petroleum engineering, geology, field development and production, operations, international business development, and finance and experience in management and executive positions with international energy companies.  Nevertheless, the markets in which we operate and plan to operate are highly competitive and the Company may not be able to compete successfully against its current and future competitors.  See Part I, Item 1A. Risk Factors - Risks Related to the Company’s Industry - for risk factors associated with competition in the oil and gas industry.

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 years ended December 31, 2012 and 2011, respectively, we did not have any significant expenditures relating to environmental and government regulation.

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Employees

At December 31, 2012, the Company had 19 full-time employees in the United States and 16 full-time employees in Africa.

During 2013, the Company expects to hire additional personnel in certain operational and other areas as required for its expansion efforts, and to maintain focus on its then-existing and new projects. The number and skill sets of individual employees will be primarily dependent on the relative rates of growth of the Company’s different projects, and the extent to which operations and development are executed internally or contracted to outside parties. In order for us to attract and retain quality personnel, we will have to offer competitive salaries to future employees.

Subject to the availability of sufficient working capital and assuming initiation of additional projects, the Company currently plans to further increase full-time staffing to a level adequate to execute the Company’s growth plans. As we continue to expand, we will incur additional cost for personnel.

Intellectual Property

As of December 31, 2012, the Company owned no significant rights to intellectual property.

ITEM  1A.  RISK FACTORS

The Company’s operations and its securities are subject to a number of risks. The Company has described below all the material risks that are known to the Company that could materially impact the Company’s financial results of operations or financial condition. If any of the following risks actually occur, the business, financial condition or operating results of the Company and the trading price or value of its securities could be materially adversely affected.

Risks Related to the Company’s Business

The Company’s limited operating history makes it difficult to predict future results and raises substantial doubt as to its ability to successfully develop profitable business operations.

The Company’s limited operating history makes it difficult to evaluate its current business and prospects or to accurately predict its future revenue or results of operations, and raises substantial doubt as to its ability to successfully develop profitable business operations beyond the Oyo Field interest rights we acquired in April 2010 (the Oyo Contract Rights) and the Non-Oyo Contract Rights acquired in February 2011. We had no previous operating history in the Africa area. The Company’s revenue and income potential are unproven. As a result of its early stage of operations, and to keep up with the frequent changes in the energy industry, it is necessary for the Company to analyze and revise its business strategy on an ongoing basis. Companies in early stages of operations are generally more vulnerable to risks, uncertainties, expenses and difficulties than more established companies.

The Company was a development stage company and may continue to incur losses for a significant period of time.

The Company was until recently a development stage company with minimal revenues.  In April 2010, we acquired the Oyo Contract Rights from CEHL Group and, as a result of this acquisition, we ceased reporting as a development stage company and now we are an operating company generating  revenues.  We expect to continue to incur significant expenses relating to our identification of new ventures and investment costs relating to these ventures. Additionally, fixed commitments, including salaries and fees for employees and consultants, rent and other contractual commitments may be substantial and are likely to increase as additional ventures are entered into and personnel are retained. Energy ventures, such as oil well drilling projects, generally require a significant period of time before they produce resources and in turn generate profits. The Oyo  and Non-Oyo Contract Rights may or may not result in net earnings in excess of our losses on other ventures under development or in the start-up phase. We may not achieve or sustain profitability on a quarterly or annual basis, or at all.

The Company’s ability to diversify risks by participating in multiple projects and joint ventures depends upon its ability to raise capital and the availability of suitable prospects, and any failure to raise needed capital and secure suitable projects would negatively affect the Company’s ability to operate.

The Company’s business strategy includes spreading the risk of oil and natural gas exploration, development and drilling, and ownership of interests in oil and natural gas properties, by participating in multiple projects and joint ventures.  If the Company is unable to secure sufficient attractive projects as a result of its inability to raise sufficient capital or otherwise, the average quality of the projects and joint venture opportunities may decline and the risk of the Company’s overall operations could increase.

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The loss of key employees could adversely affect the Company’s ability to operate.

The Company believes that its success depends on the continued service of its key employees, as well as the Company’s ability to hire additional key employees, when and as needed. Each of the Company’s Senior Vice Presidents has the right to terminate his employment at any time without penalty under his employment agreement. The unexpected loss of the services of  any of these key employees, or the Company’s failure to find suitable replacements within a reasonable period of time thereafter, could have a material adverse effect on the Company’s ability to execute its business plan and therefore, on its financial condition and results of operations.

The Company may not be able to raise the additional capital necessary to execute its business strategy, which could result in the curtailment or cessation of the Company’s operations.

The Company will need to raise substantial additional funds to fully fund its existing operations, consummate all of its current asset transfer and acquisition opportunities currently contemplated and for the development, production, trading and expansion of its business. The Company has available a Promissory Note (term credit facility) of up to $25 million from an affiliated company. This facility provides for an annual interest rate based on 30 day Libor plus two percentage points with all amounts due and payable by July 15, 2014. The Company has no other current arrangements with respect to additional sources of financing, if needed. If additional sources of financing are needed it may not be available on commercially reasonable terms on a timely basis, or at all. The inability to obtain additional financing, when needed, would have a negative effect on the Company, including possibly requiring it to curtail or cease operations. If any future financing involves the sale of the Company’s equity securities, the shares of Common Stock held by its stockholders could be substantially diluted. If the Company borrows money or issues debt securities, it will be subject to the risks associated with indebtedness, including the risk that interest rates may fluctuate and the possibility that it may not be able to pay principal and interest on the indebtedness when due.

Insufficient funds will prevent the Company from implementing its business plan and will require it to delay, scale back, or eliminate certain of its programs or to license to third parties rights to commercialize rights in fields that it would otherwise seek to develop itself.

Failure by the Company to generate sufficient cash flow from operations could eventually result in the cessation of the Company’s operations and require the Company to seek outside financing or discontinue operations.

The Company’s business activities require substantial capital from outside sources as well as from internally-generated sources. The Company’s ability to finance a portion of its working capital and capital expenditure requirements with cash flow from operations will be subject to a number of variables, such as:

· the level of production from existing wells;

● prices of oil and natural gas;

● the success and timing of development of proved undeveloped reserves;

● cost overruns;

● remedial work to improve a well’s producing capability;

● direct costs and general and administrative expenses of operations;

● reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells;

● indemnification obligations of the Company for losses or liabilities incurred in connection with the Company’s activities; and

● general economic, financial, competitive, legislative, regulatory and other factors beyond the Company’s control.

The Company might not generate or sustain cash flow at sufficient levels to finance its business activities. When and if the Company generates significant revenues, if such revenues were to decrease due to lower oil and natural gas prices, decreased production or other factors, and if the Company were unable to obtain capital through reasonable financing arrangements, such as a credit line, or otherwise, its ability to execute its business plan would be limited and it could be required to discontinue operations.

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The Company’s failure to capitalize on existing definitive production agreements and/or enter into additional agreements could result in an inability by the Company to generate sufficient revenues and continue operations.

The Company has active interests in definitive production contracts for the Oyo and Non-Oyo Contract Rights. The Company has entered into definitive exploration agreements with Kenya and The Gambia. The Company’s ability to consummate one or more additional ventures is subject to, among other things, (i) the amount of capital the Company raises in the future; (ii) the availability of land for exploration and development in the geographical regions in which the Company’s business is focused; (iii) the nature and number of competitive offers for the same projects on which the Company is bidding; and (iv) approval by government and industry officials. The Company may not be successful in executing definitive agreements in connection with any other ventures, or otherwise be able to secure any additional ventures it pursues in the future. Failure of the Company to capitalize on its existing contracts and/or to secure one or more additional business opportunities would have a material adverse effect on the Company’s business and results of operations, and could result in the cessation of the Company’s business operations.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. A significant percentage of our total estimated proved reserves at December 31, 2012 were proved undeveloped reserves which ultimately may be less than currently estimated.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities.  In the case of production sharing contracts, the quantities allocable to a part-interest owner’s share are affected by the assumptions of that owner’s future participation in funding of operating and capital costs. Actual future production, prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from estimates. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed.  In addition, estimates of proved reserves reflect production history, results of exploration and development, prevailing prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

The Company’s oil and gas operations will involve many operating risks that can cause substantial losses.

The Company expects to produce, transport and market potentially toxic materials, and purchase, handle and dispose of other potentially toxic materials in the course of its business. The Company’s operations will produce byproducts, which may be considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or as a result of new findings on the effects the Company’s operations on human health or the environment. Additionally, the Company’s oil and gas operations may also involve one or more of the following risks:

● fires;

● explosions;

● blow-outs;

● uncontrollable flows of oil, gas, formation water, or drilling fluids;

● natural disasters;

● pipe or cement failures;

● casing collapses;

● embedded oilfield drilling and service tools;

● abnormally pressured formations;

● damages caused by vandalism and terrorist acts; and

● environmental hazards such as oil spills, natural gas leaks, pipeline ruptures and discharges of toxic gases.

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In the event that any of the foregoing events occur, the Company could incur substantial losses as a result of (i) injury or loss of life; (ii) severe damage or destruction of property, natural resources or equipment; (iii) pollution and other environmental damage; (iv) investigatory and clean-up responsibilities; (v) regulatory investigation and penalties; (vi) suspension of its operations; or (vii) repairs to resume operations. If the Company experiences any of these problems, its ability to conduct operations could be adversely affected. Additionally, offshore operations are subject to a variety of operating risks, such as capsizing, collisions and damage or loss from typhoons or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production.

The Company may not be able to manage our anticipated growth.

Subject to our receipt of additional capital, we plan to significantly expand operations to accommodate additional development projects and other opportunities. This expansion may strain our management, operations, systems and financial resources. We may need to hire additional personnel in certain operational and other areas during 2013 and future years.

We will depend on the Operating Contractor under the OML 120/121 PSC, which may result in operating costs, methods and timing of operations and expenditures beyond our control, and potential delays or the discontinuation of operations and production.

The Operating Contractor under the OML 120/121 PSC currently manages all of the physical development and operations under the OML 120/121 PSC, including, but not limited to, the timing of drilling, production and related operations, the timing and amount of operational costs, the technology and service providers employed.  We would be materially adversely affected if the Operating Contractor does not properly and efficiently manage operational and production matters, or becomes unable or unwilling to continue in that capacity under the OML 120/121 PSC.

The Company will be dependent upon others for the storage and transportation of oil and gas, which could result in significant operational costs to the Company and depletion of capital.

The Company does not own storage or transportation facilities and, therefore, will depend upon third parties to store and transport all of its oil and gas resources when and if produced. The Company will likely be subject to price changes and termination provisions in any contracts it may enter into with these third-party service providers. The Company may not be able to identify such third-parties for any particular project. Even if such sources are initially identified, the Company may not be able to identify alternative storage and transportation providers in the event of contract price increases or termination. In the event the Company is unable to find acceptable third-party service providers, it would be required to contract for its own storage facilities and employees to transport the Company’s resources. The Company may not have sufficient capital available to assume these obligations, and its inability to do so could result in the cessation of its business.

An interruption in the supply of materials, resources and services the Company plans to obtain from third party sources could limit the Company’s operations and cause unprofitability.

Once it has identified, financed, and acquired projects, the Company will need to obtain other materials, resources and services, including, but not limited to, specialized chemicals and specialty muds and drilling fluids, pipe, drill-string, geological and geophysical mapping and interruption services. There may be only a limited number of manufacturers and suppliers of these materials, resources and services. These manufacturers and suppliers may experience difficulty in supplying such materials, resources and services to the Company sufficient to meet its needs or may terminate or fail to renew contracts for supplying these materials, resources or services on terms the Company finds acceptable including, without limitation, acceptable pricing terms. Any significant interruption in the supply of any of these materials, resources or services, or significant increases in the amounts the Company is required to pay for these materials, resources or services, could result in a lack of profitability, or the cessation of operations, if unable to replace any material sources in a reasonable period of time.

The Company does not presently carry liability insurance and business interruption insurance policies in Africa and will be at risk of incurring personal injury claims for its employees and subcontractors, and incurring business interruption loss due to theft, accidents or natural disasters.

The Company does not presently carry any policies of insurance in Africa to cover the risks discussed above.  In the event that the Company were to incur substantial liabilities or business interruption losses with respect to one or more incidents, this could adversely affect its operations and it may not have the necessary capital to pay its portion of such costs and maintain business operations.

16

Our business partner, CEHL Group, is a related party, and our executive chairman and CEO is a principal owner and one of the directors of CEHL, which may result in real or perceived conflicts of interest.

Our majority shareholder, CAMAC Energy Holdings Limited, is one of the entities constituting our business partner, CEHL Group.  Dr. Kase Lawal, the Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is a director of each of CEHL, CINL, and Allied, also entities constituting CEHL Group. Dr. Lawal also owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CEHL, and CINL and Allied are each wholly-owned subsidiaries of CEHL.  As a result, Dr. Lawal may be deemed to have an indirect material interest in any transactions with CEHL including the agreements entered into with CEHL in April 2010, the OML 120/121 Transaction and the Promissory Note with Allied of June 6, 2011.  As a result, Dr. Lawal may be deemed to have an indirect material interest in the above agreements.  These relationships may result in conflicts of interest. We may not be able to prove that these agreements are equivalent to arm’s length transactions.  Should our transactions not provide the value equivalent of arm’s length transactions, our results of operations may suffer and we may be subject to costly shareholder litigation.

If we lose our status as an indigenous Nigerian oil and gas operator, we would no longer be eligible for preferential treatment in the acquisition of oil and gas assets and oil and gas licensing rounds in Nigeria.

We are considered an indigenous Nigerian oil and gas operator by virtue of our majority stockholder, CEHL, which is an indigenous Nigerian oil and gas company.  This status makes us eligible for preferential treatment under the Nigerian Content Development Act with respect to the acquisition of oil and gas assets and in oil and gas licensing rounds in Nigeria.  If CEHL were to lose its status as an indigenous Nigerian oil and gas company due to its affiliation with our U.S. based company or otherwise, or if CEHL Limited’s majority interest in us were to be diluted or reduced due to additional issuances of equity by the Company, CEHL sale or transfer of its interest in the Company or otherwise, we may lose our status as an indigenous Nigerian oil and gas operator.  As a result, we would lose one of our key advantages in the Nigerian oil and gas market and our results of operations could materially suffer.

Applicable Nigerian income tax rates could adversely affect the value of the OML 120/121 asset, including the Oyo Field.

Income derived from the Oyo Contract Rights and Non-Oyo Contract Rights, and CPL, as acquiring subsidiary in these transactions, are subject to the jurisdiction of the Nigerian taxing authorities.  The Nigerian government applies different tax rates upon income derived from Nigerian oil operations ranging from 50% to 85%, based on a number of factors.  The final determination of the tax liabilities with respect to the OML 120/121 PSC involves the interpretation of local tax laws and related authorities. In addition, changes in the operating environment, including changes in tax law and currency/repatriation controls, could impact the determination of tax liabilities with respect to the OML 120/121 PSC for a tax year.  While we believe the tax rate applicable to the OML 120/121 PSC is 52%, the actual applicable rate could be higher, which could result in a material decrease in the profits allocable to the Company under the OML 120/121 PSC.

The passage into law of the Nigerian Petroleum Industry Bill could create additional fiscal and regulatory burdens on the parties to the OML 120/121 PSC, which could have a material adverse effect on the profitability of the production.

A Petroleum Industry Bill (“PIB”) is currently undergoing legislative process at the Nigerian National Assembly. To date, the PIB has failed to pass the Nigerian Senate.  The draft PIB seeks to introduce significant changes to legislation governing the oil and gas sector in Nigeria, including new fiscal regulatory and tax obligations and expanded fiscal and regulatory oversight that may impose additional operational and regulatory burdens on the operating contractor under the OML 120/121 PSC and impact the economic benefits anticipated by the parties to the OML 120/121 PSC.  Any such fiscal and regulatory changes could have a negative impact on the profits allocable to the Company under the OML 120/121 PSC.

OML 120/121 is subject to the instability of the Nigerian Government and instability in the country of Nigeria.

The government of Nigeria originally granted the rights to OML 120/121 PSC to CEHL. The government and country of Nigeria have historically experienced instability, which is out of management’s control. The Company’s ability to exploit its interests in this area pursuant to the OML 120/121 PSC may be adversely impacted by unanticipated governmental action. In addition, the OML 120/121 PSC’s financial viability may also be negatively affected by changing economic, political and governmental conditions in Nigeria. Moreover, we operate in a sector of the economy that is likely to be adversely impacted by the effects of political instability, terrorist or other attacks, war or international hostilities.

OML 120/121 is located in an area where there are high security risks, which could result in harm to the Oyo Field operations and our interest in the Oyo Field and the remainder of OML 120/121.

The Oyo Field is located approximately 75 miles off the Southern Nigerian coast in deep-water.  There are some risks inherent to oil production in Nigeria. Since December 2005, Nigeria has experienced increased pipeline vandalism, kidnappings and militant takeovers of oil facilities in the Niger Delta. The Movement for the Emancipation of the Niger Delta (MEND) is the main group attacking oil infrastructure for political objectives, claiming to seek a redistribution of oil wealth and greater local control of the sector. Additionally, kidnappings of oil workers for ransom are common. Security concerns have led some oil services firms to pull out of the country and oil workers unions to threaten strikes over security issues. The instability in the Niger Delta has caused shut-in production and several companies to declare force majeure on oil shipments.

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Despite undertaking various security measures and being situated 75 miles offshore the Nigerian coast, theFPSO vessel  currently being used for storing petroleum production inthe OyoField may become subject to terrorist acts and other acts of hostility like piracy. Such actions could adverselyimpactour overall business, financial condition and operations. Our facilities are subject to these substantial security risks and our financial condition and results of operations may materially suffer as a result.

Maritime disasters and other operational risks may adversely impact our reputation, financial condition and results of operations.

The operation of the FPSO vessel has an inherent risk of maritime disaster, environmental mishaps, cargo and property losses or damage and business interruptions caused by, among others:

● mechanical failure;

● damages requiring dry-dock repairs;

● human error;

● labor strikes;

● adverse weather conditions;

● vessel off hire periods;

● regulatory delays; and

● political action, civil conflicts, terrorism and piracy in countries where vessel operations are conducted, vessels are registered or from which spare parts and provisions are sourced and purchased.

Any of these circumstances could adversely affect the operation of the FPSO vessel, and result in loss of revenues or increased costs and adversely affect our profitability. Terrorist acts and regional hostilities around the world in recent years have led to increase in insurance premium rates and the implementation of special “war risk” premiums for certain areas. Such increases in insurance rates may adversely affect our profitability with respect to the Oyo Field asset.

 A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations.

The prices received for Oyo Field production under the OML 120/121 PSC will heavily influence our revenue, profitability, access to capital and future rate of growth. Oil is a commodity and, therefore, its price is subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil has been volatile. This market will likely continue to be volatile in the future. The prices received for production under the OML 120/121 PSC and the levels of its production depend on numerous factors beyond our and operator’s control. These factors include the following:

● changes in global supply and demand for oil;

● the actions of the Organization of Petroleum Exporting Countries;

● the price and quantity of imports of foreign oil;

● political and economic conditions, including embargoes, in oil producing countries or affecting other oil-producing activity;

● the level of global oil exploration and production activity;

● the level of global oil inventories;

● weather conditions;

● technological advances affecting energy consumption;

● domestic and foreign governmental regulations;

● proximity and capacity of oil pipelines and other transportation facilities; and

● the price and availability of alternative fuels.

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Lower oil prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil that the operator can produce economically under the OML 120/121 PSC with respect to the Oyo Field. A substantial or extended decline in oil prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Risks Related to the Company’s Industry

The Company may not be successful in finding, acquiring, or developing sufficient petroleum reserves, and if it fails to do so, the Company will likely cease operations.

The Company will be operating primarily in the petroleum extractive business; therefore, if it is not successful in finding crude oil and natural gas sources with good prospects for future production, and exploiting such sources, its business will not be profitable and it may be forced to terminate its operations. Exploring and exploiting oil and gas or other sources of energy entails significant risks, which risks can only be partially mitigated by technology and experienced personnel. The Company or any ventures it acquires or participates in may not be successful in finding petroleum or other energy sources; or, if it is successful in doing so, the Company may not be successful in developing such resources and producing quantities that will be sufficient to permit the Company to conduct profitable operations. The Company’s future success will depend in large part on the success of its drilling programs and creating and maintaining an inventory of projects. Creating and maintaining an inventory of projects depends on many factors, including, among other things, obtaining rights to explore, develop and produce hydrocarbons in promising areas, drilling success, and ability to bring long lead-time, capital intensive projects to completion on budget and schedule, and efficient and profitable operation of mature properties. The Company’s inability to successfully identify and exploit crude oil and natural gas sources would have a material adverse effect on its business and results of operations and would, in all likelihood, result in the cessation of its business operations.

In addition to the numerous operating risks described in more detail in this report, exploring and exploitation of energy sources involve the risk that no commercially productive oil or gas reservoirs will be discovered or, if discovered, that the cost or timing of drilling, completing and producing wells will not result in profitable operations. The Company’s drilling operations may be curtailed, delayed or abandoned as a result of a variety of factors, including:

● adverse weather conditions;

● unexpected drilling conditions;

● pressure or irregularities in formations;

● equipment failures or accidents;

● inability to comply with governmental requirements;

● shortages or delays in the availability of drilling rigs and the delivery of equipment; and

● shortages or unavailability of qualified labor to complete the drilling programs according to the business plan schedule.

The energy market in which the Company operates is highly competitive and the Company may not be able to compete successfully against its current and future competitors, which could seriously harm the Company’s business.

Competition in the oil and gas industry is intense, particularly with respect to access to drilling rigs and other services, the acquisition of properties and the hiring and retention of technical personnel. The Company expects competition in the market to remain intense because of the increasing global demand for energy, and that competition will increase significantly as new companies enter the market and current competitors continue to seek new sources of energy and leverage existing sources. Many of the Company’s competitors, including large oil companies, have an established presence in the areas we do business and have longer operating histories, significantly greater financial, technical, marketing, development, extraction and other resources and greater name recognition than the Company does. As a result, they may be able to respond more quickly to new or emerging technologies, changes in regulations affecting the industry, newly discovered resources and exploration opportunities, as well as to large swings in oil and natural gas prices. In addition, increased competition could result in lower energy prices, and reduced margins and loss of market share, any of which could harm the Company’s business. Furthermore, increased competition may harm the Company’s ability to secure ventures on terms favorable to it and may lead to higher costs and reduced profitability, which may seriously harm its business.

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The Company’s business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile energy prices, which volatility could adversely affect its ability to operate profitably.

The Company’s business depends on the level of activity in the oil and gas exploration, development and production in markets worldwide. Oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic and weather-related factors significantly affect this level of activity. Oil and gas prices are extremely volatile and are affected by numerous factors, including:

● the domestic and foreign supply of oil and natural gas;

● the ability of the Organization of Petroleum Exporting Countries, commonly called “OPEC,” to set and maintain production levels and pricing;

● the price and availability of alternative fuels;

● weather conditions;

● the level of consumer demand;

● global economic conditions;

● political conditions in oil and gas producing regions; and

● government regulations.

Within the 12 months ending December 31, 2012, light crude oil futures have ranged from approximately $75 per barrel to over $100 per barrel, and may continue to fluctuate significantly in the future.

If the Company does not hedge its exposure to reductions in oil and gas prices, it may be subject to the risk of significant reductions in prices; alternatively, use by the Company of oil and gas price hedging contracts could limit future revenues from price increases.

To date, the Company has not entered into any hedging transactions but may do so in the future.  In the event that the Company chooses not to hedge its exposure to reductions in oil and gas prices by purchasing futures and by using other hedging strategies, it could be subject to significant reduction in prices which could have a material negative impact on its profitability. Alternatively, the Company may elect to use hedging transactions with respect to a portion of its oil and gas production to achieve more predictable cash flow and to reduce its exposure to price fluctuations. The use of hedging transactions could limit future revenues from price increases and could also expose the Company to adverse changes in basis risk, the relationship between the price of the specific oil or gas being hedged and the price of the commodity underlying the futures contracts or other instruments used in the hedging transaction. Hedging transactions also involve the risk that the counterparty does not satisfy its obligations.

The Company may be required to take non-cash asset write-downs if oil and natural gas prices decline or if downward revisions in net proved reserves occur, which could have a negative impact on the Company’s earnings.

Under applicable accounting rules, the Company may be required to write down the carrying value of oil and natural gas properties if oil and natural gas prices decline or if there are substantial downward adjustments to its estimated proved reserves, increases in its estimates of development costs or deterioration in its exploration results. Accounting standards require the Company to review its long-lived assets for possible impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable over time. In such cases, if the asset’s estimated undiscounted future cash flows are less than its carrying amount, impairment exists. Any impairment write-down, which would equal the excess of the carrying amount of the assets being written down over their fair value, would have a negative impact on the Company’s earnings, which could be material.

Risks Related to International Operations

The Company’s international operations will subject it to certain risks inherent in conducting business operations in Nigeria and other foreign countries, including political instability and foreign government regulation, which could significantly impact the Company’s ability to operate in such countries and impact the Company’s results of operations.

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The Company conducts substantially all of its business in Africa.  The Company’s present and future international operations in foreign countries are, and will be, subject to risks generally associated with conducting businesses in foreign countries, such as:

● foreign laws and regulations that may be materially different from those of the United States;

● changes in applicable laws and regulations;

● challenges to, or failure of, title;

● labor and political unrest;

● foreign currency fluctuations;

● changes in foreign economic and political conditions;

● export and import restrictions;

● tariffs, customs, duties and other trade barriers;

● difficulties in staffing and managing foreign operations;

● longer time periods and difficulties in collecting accounts receivable and enforcing agreements;

● possible loss of properties due to nationalization or expropriation; and

● limitations on repatriation of income or capital.

Specifically, foreign governments may enact and enforce laws and regulations requiring increased ownership by businesses and/or state agencies in energy producing businesses and the facilities used by these businesses, which could adversely affect the Company’s ownership interests in then existing ventures. The Company’s ownership structure may not be adequate to accomplish the Company’s business objectives in Nigeria or in any other foreign jurisdiction where the Company may operate. Foreign governments also may impose additional taxes and/or royalties on the Company’s business, which would adversely affect the Company’s profitability and value of our foreign assets, including the rights to interests in OML 120/121 PSC.   In certain locations, governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the Company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a foreign government and the Company or other governments may adversely affect its operations. These developments may, at times, significantly affect the Company’s results of operations, and must be carefully considered by its management when evaluating the level of current and future activity in such countries.

The future success of the Company’s operations may also be adversely affected by risks associated with international activities, including economic and labor conditions, political instability, risk of war, expropriation, repatriation, termination, renegotiation or modification of existing contracts, tax laws (including host-country import-export, excise and income taxes and United States taxes on foreign subsidiaries) and changes in the value of the U.S. dollar versus the local currencies in which future oil and gas producing activities may be denominated in certain cases. Changes in exchange rates may also adversely affect the Company’s future results of operations and financial condition.  Realization of any of these factors could materially and adversely affect our financial position, results of operations and cash flows.

Compliance and enforcement of environmental laws and regulations, including those related to climate change, may cause the Company to incur significant expenditures and require resources, which it may not have.

Extensive national, regional and local environmental laws and regulations in Africa are expected to have a significant impact on the Company’s operations. These laws and regulations set various standards regulating certain aspects of health and environmental quality, which provide for user fees, penalties and other liabilities for the violation of these standards. As new environmental laws and regulations are enacted and existing laws are repealed, interpretation, application and enforcement of the laws may become inconsistent. Compliance with applicable local laws in the future could require significant expenditures, which may adversely affect the Company’s operations. The enactment of any such laws, rules or regulations in the future may have a negative impact on the Company’s projected growth, which could in turn decrease its projected revenues or increase its cost of doing business.

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A foreign government could change its policies toward private enterprise or even nationalize or expropriate private enterprises, which could result in the total loss of the Company’s investment in that country.

The Company’s business is subject to significant political and economic uncertainties and may be adversely affected by political, economic and social developments in Africa or in any other foreign jurisdiction in which it operates.

Changes in policies, laws and regulations or in their interpretation or the imposition of confiscatory taxation, restrictions on currency conversion, restrictions or prohibitions on dividend payments to stockholders, devaluations of currency or the nationalization or other expropriation of private enterprises could have a material adverse effect on the Company’s business. Nationalization or expropriation could even result in the loss of all or substantially all of the Company’s assets and in the total loss of your investment in the Company.

The continued existence of official corruption and bribery in Africa, and the inability or unwillingness of Nigerian authorities to combat such corruption, may negatively impact our ability to fairly and effectively compete in the Nigerian oil and gas  market.

Official corruption and bribery remain a serious concern in Nigeria.  The 2012 Transparency International report ranks Nigeria 139 out of 174 countries in terms of corruption perceptions.  In an attempt to combat corruption in the oil and gas sector, the National Assembly passed the Nigeria Extractive Industries Transparency Initiative Act 2007.  This action permitted Nigeria to become a candidate country under the Extractive Industries Transparency Initiative (“EITI”), the first step in bringing transparency to all material oil, gas and mining payments to the Government of Nigeria.  In addition, Nigeria has amended its banking laws to permit the government to bring corrupt bank officials to justice.  Several notable cases have been brought, but, to date, few significant cases have been successful and bank regulatory oversight remains a concern.  Thus, increased diligence may be required in working with or through Nigerian banks or with Nigerian governmental authorities, and interactions with government officials may need to be monitored.  To the extent that such efforts to increase transparency are unsuccessful, and any competitors utilize the existence of corruptive practices in order to secure an unfair advantage, our financial condition and results of operations may suffer.

If relations between the United States and Africa were to deteriorate, investors might be unwilling to hold or buy the Company’s stock and its stock price may decrease.

At various times during recent years, the United States has had significant disagreements over political, economic and security issues with Nigeria.  Additional controversies may arise in the future between the United States and these two countries. Any political or trade controversies between the United States and these two countries, whether or not directly related to the Company’s business, could adversely affect the market price of the Company’s Common Stock.

The Company’s stockholders may not be able to enforce United States civil liabilities claims.

Many of the Company’s assets are, and are expected to continue to be, located outside the U.S. and held through one or more wholly-owned and majority-owned subsidiaries incorporated under the laws of foreign jurisdictions.  A substantial part of the Company’s operations are, and are expected to continue to be, conducted in Africa.  In addition, some of the Company’s directors and officers, including directors and officers of its subsidiaries, may be residents of countries other than the U.S. All or a substantial portion of the assets of these persons may be located outside the U.S. As a result, it may be difficult for shareholders to effect service of process within the U.S. upon these persons. In addition, there is uncertainty as to whether the courts of Africa would recognize or enforce judgments of U.S. courts obtained against the Company or such persons predicated upon the civil liability provisions of the securities laws of the U.S. or any state thereof, or be competent to hear original actions brought in these countries against the Company or such persons predicated upon the securities laws of the U.S. or any state thereof.

Risks Related to the Company’s Stock

CAMAC Energy Holdings Limitedis our controlling stockholder, and it may take actions that conflict with the interests of the other stockholders.

Following our acquisition of the Oyo Contract Rights, CEHL beneficially owned approximately 62.74% of our outstanding shares of Common Stock and continues to own a majority interest at present.  CEHL controls the power to elect our directors, to appoint members of management and to approve all actions requiring the approval of the holders of our Common Stock, including adopting amendments to our Certificate of Incorporation and approving mergers, acquisitions or sales of all or substantially all of our assets, subject to certain restrictive covenants. The interests of CEHL as our controlling stockholder could conflict with your interests as a holder of Company Common Stock. For example, CEHL as our controlling stockholder may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its equity investment, even though such transactions might involve risks to you, as minority holders of the Company.

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The market price of the Company’s stock may be adversely affected by a number of factors related to the Company’s performance, the performance of other energy-related companies and the stock market in general.

The market prices of securities of energy companies are extremely volatile and sometimes reach unsustainable levels that bear no relationship to the past or present operating performance of such companies.

Factors that may contribute to the volatility of the trading price of the Company’s Common Stock include, among others:

● the Company’s quarterly results of operations;

● the variance between the Company’s actual quarterly results of operations and predictions by stock analysts;

● financial predictions and recommendations by stock analysts concerning energy companies and companies competing in the Company’s market in general, and concerning the Company in particular;

● public announcements of regulatory changes or new ventures relating to the Company’s business, new products or services by the Company or its competitors, or acquisitions, joint ventures or strategic alliances by the Company or its competitors;

● public reports concerning the Company’s services or those of its competitors;

● the operating and stock price performance of other companies that investors or stock analysts may deem comparable to the Company;

● large purchases or sales of the Company’s Common Stock;

● investor perception of the Company’s business prospects or the oil and gas industry in general; and

● general economic and financial conditions.

In addition to the foregoing factors, the trading prices for equity securities in the stock market in general, and of energy-related companies in particular, have been subject to wide fluctuations that may be unrelated to the operating performance of the particular company affected by such fluctuations. Consequently, broad market fluctuations may have an adverse effect on the trading price of the Common Stock, regardless of the Company’s results of operations.

The limited market for the Company’s Common Stock may adversely affect trading prices or the ability of a shareholder to sell the Company’s shares in the public market at or near ask prices or at all if a shareholder needs to liquidate its shares.

The market price for shares of the Company’s Common Stock has been, and is expected to continue to be, very volatile.  Numerous factors beyond the Company’s control may have a significant effect on the market price for shares of the Company’s Common Stock, including the fact that the Company is a small company that is relatively unknown to stock analysts, stock brokers, institutional investors and others in the investment community that generate or influence sales volume.  Even if we came to the attention of such persons, they tend to be risk-averse and may be reluctant to follow an unproven, early stage company such as the Company or purchase or recommend the purchase of its shares until such time as the Company becomes more seasoned and viable. There may be periods of several days or more when trading activity in the Company’s shares is minimal as compared to a seasoned issuer which has a large and steady volume of trading activity that will generally support continuous sales without an adverse effect on share price. Due to these conditions, investors may not be able to sell their shares at or near ask prices or at all if investors need money or otherwise desire to liquidate their shares.

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The Company’s issuance of Preferred Stock could adversely affect the value of the Company’s Common Stock.

The Company’s Amended and Restated Certificate of Incorporation authorizes the issuance of up to 50 million shares of Preferred Stock, which shares constitute what is commonly referred to as “blank check” Preferred Stock.  This Preferred Stock may be issued by the Board of Directors from time to time on any number of occasions, without stockholder approval, as one or more separate series of shares comprised of any number of the authorized but unissued shares of Preferred Stock, designated by resolution of the Board of Directors, stating the name and number of shares of each series and setting forth separately for such series the relative rights, privileges and preferences thereof, including, if any, the: (i) rate of dividends payable thereon; (ii) price, terms and conditions of redemption; (iii) voluntary and involuntary liquidation preferences; (iv) provisions of a sinking fund for redemption or repurchase; (v) terms of conversion to Common Stock, including conversion price; and (vi) voting rights. The designation of such shares could be dilutive of the interest of the holders of our Common Stock. The ability to issue such Preferred Stock could also give the Company’s Board of Directors the ability to hinder or discourage any attempt to gain control of the Company by a merger, tender offer at a control premium price, proxy contest or otherwise.

The Common Stock may be deemed “penny stock” and therefore subject to special requirements that could make the trading of the Company’s Common Stock more difficult than for stock of a company that is not “penny stock”.

The Company’s Common Stock may be deemed to be a “penny stock” as that term is defined in Rule 3a51-1 promulgated under the Securities Exchange Act of 1934. Penny stocks are stocks (i) with a price of less than five dollars per share; (ii) that are not traded on a “recognized” national exchange; (iii) whose prices are not quoted on the NASDAQ automated quotation system (NASDAQ-listed stocks must still meet requirement (i) above); or (iv) of issuers with net tangible assets of less than $2,000,000 (if the issuer has been in continuous operation for at least three years) or $5,000,000 (if in continuous operation for less than three years), or with average revenues of less than $6,000,000 for the last three years.

Section 15(g) of the Exchange Act, and Rule 15g-2 promulgated thereunder, require broker-dealers dealing in penny stocks to provide potential investors with a document disclosing the risks of penny stocks and to obtain a manually signed and dated written receipt of the document before effecting any transaction in a penny stock for the investor’s account. Moreover, Rule 15g-9 promulgated under the Exchange Act requires broker-dealers in penny stocks to approve the account of any investor for transactions in such stocks before selling any penny stock to that investor. This procedure requires the broker-dealer to (i) obtain from the investor information concerning his or her financial situation, investment experience and investment objectives; (ii) reasonably determine, based on that information, that transactions in penny stocks are suitable for the investor and that the investor has sufficient knowledge and experience as to be reasonably capable of evaluating the risks of penny stock transactions; (iii) provide the investor with a written statement setting forth the basis on which the broker-dealer made the determination in (ii) above; and (iv) receive a signed and dated copy of such statement from the investor, confirming that it accurately reflects the investor’s financial situation, investment experience and investment objectives. Compliance with these requirements may make it more difficult for investors in the Common Stock to resell their shares to third parties or to otherwise dispose of them.

The Company’s executive officers, directors and major stockholders, including CAMAC Energy Holdings Limited, hold a controlling interest in the Company’s Common Stock and may be able to prevent other stockholders from influencing significant corporate decisions.

The executive officers, directors and holders of 5% or more of the outstanding Common Stock, if they were to act together, would be able to control all matters requiring approval by stockholders, including the election of Directors and the approval of significant corporate transactions. This concentration of ownership may also have the effect of delaying, deterring or preventing a change in control and may make some transactions more difficult or impossible to complete without the support of these stockholders.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None

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ITEM 2.  PROPERTIES

The Company has two primary leased office facilities: Houston, Texas (the “Houston Facility”) and Nairobi, Kenya (the “Kenya Facility”).  The Company also utilizes office space in Lagos, Nigeria under short-term arrangements with an affiliated company.

The Houston Facility covers approximately 7,800 square feet of office space and is under a lease which commenced on  October 1, 2012 and ends on October 31, 2019.  Rental expense is currently $14,500 per month plus allocated share of operating expenses.

The Kenya Facility covers approximately 5,420 square feet of office space and is under lease which commenced on November 1, 2012 and ends November 30, 2017.  Rental expense is currently $6,000 per month plus service charges.

The Company does not foresee significant difficulty in renewing or replacing either lease under current market conditions, or in adding additional space when required.

ITEM 3.  LEGAL PROCEEDINGS

In June 2011, Abiola Lawal, former Executive Vice President and Chief Financial Officer of the Company, filed a lawsuit in Harris County, Texas District Court against the Company, alleging breach of contract and wrongful termination in connection with his termination from the Company. In September 2011, the Court issued an order staying the proceedings pending arbitration in view of the mandatory arbitration clause in the plaintiff’s employment agreement. In October 2011, the plaintiff issued a written demand for arbitration making the same allegations as the stayed lawsuit. The arbitration hearing was scheduled to commence in late October 2012.   On October 19, 2012, a settlement agreement was reached resolving the matters described above.  The settlement will have no material effect on our consolidated financial position or our net income or loss.

From time to time we may be involved in various legal proceedings and claims in the ordinary course of our business. As of December 31, 2012, and through the filing date of this report, we do not believe the ultimate resolution of such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or our net income or loss.

ITEM 4.   MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information for Common Stock

Our Common Stock is currently listed on the NYSE MKT under the symbol “CAK”. It commenced listing on the NYSE MKT on November 5, 2009 under the symbol “PAP”.  Prior to being listed on the NYSE MKT, the Common Stock was quoted on the OTC Bulletin Board under the symbol “PFAP.OB” between May 8, 2008 and November 4, 2009.

The following table sets forth the range of the high and low sales prices per share of our Common Stock for the periods indicated:

Period	High		Low
2012
First quarter	$	1.05	$	0.77
Second quarter	$	1.04	$	0.57
Third quarter	$	0.65	$	0.45
Fourth quarter	$	0.80	$	0.38
2011
First quarter	$	2.00	$	1.37
Second quarter	$	2.02	$	1.19
Third quarter	$	1.36	$	0.60
Fourth quarter	$	1.23	$	0.50

Common Stock Warrants and Options

As of  March 22, 2013, the Company had warrants outstanding to purchase (i) an aggregate of  4,659,551 shares of Common Stock at a price per share of $2.62; (ii) an aggregate of 279,573 shares of Common Stock at a price per share of $2.75; (iii) an aggregate of 3,658,770 shares of Common Stock at a price per share of $4.50; (iv) an aggregate of  150,000 shares of Common Stock at a price per share of  $5.00; and (v) an  aggregate of 124,408 shares of Common Stock at a price per share of $5.28.

As of March 22, 2013, an aggregate of 3,553,485 shares of Common Stock were issuable upon exercise of outstanding stock options.

Holders

As of March 22, 2013, there were 63 registered holders of record of our Common Stock, and there are an estimated 6,000 beneficial owners of our common stock, including shares held in street name.  

Dividend Policy

The Company has not, to date, paid any cash dividends on its Common Stock. The Company has no current plans to pay dividends on its Common Stock and intends to retain earnings, if any, for working capital purposes and capital expenditures. Any future determination as to the payment of dividends on the Common Stock will depend upon the results of operations, capital requirements, the financial condition of the Company and other relevant factors.

Our Board of Directors has complete discretion on whether to pay dividends. Even if our Board of Directors decides to pay dividends, the form, frequency and amount will depend upon our future operations and earnings, capital requirements and surplus, general financial condition, contractual restrictions and other factors that the Board of Directors may deem relevant.

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Recent Sales of Unregistered Securities

None.

Stock Repurchases

The Company did not repurchase any shares of its Common Stock during the quarter ended December 31, 2012.

ITEM 6.  SELECTED FINANCIAL DATA

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this Item.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Our Business

CAMAC Energy Inc. is engaged in the exploration, development, and production of oil and gas outside the United States, directly and through joint ventures and other ventures in which it may participate.    Currently the Company has rights to interests in OML 120/121 oil and gas leases in deep water offshore Nigeria and has recently acquired exploratory acreage in Kenya and The Gambia.

The Company was originally incorporated in Delaware on December 12, 1979 as Gemini Marketing Associates Inc., subsequently changed its name to Pacific East Advisors, Inc., and on May 7, 2007 consummated a reverse merger involving predecessor company Inner Mongolia Production Company, LLC ("IMPCO") and Advanced Drilling Services, LLC ("ADS"), in connection with which the Company changed its name to Pacific Asia Petroleum, Inc. The Company’s name was changed to CAMAC Energy Inc. upon the acquisition of certain rights to interests in oil and gas properties located offshore Nigeria in April 2010.  The Company’s corporate headquarters is located in Houston, Texas.

In August 2012, the Company divested its wholly-owned Hong Kong subsidiary Pacific Asia Petroleum Limited (“PAPL”) for cash consideration of $2.5 million and 9.6 million fully paid ordinary shares, net of selling expenses, of Leyshon Resources Limited (“Leyshon”), a natural resources mining company based in Beijing, China.  The Leyshon shares had a fair market value of $1.9 million, and have since been sold.

As a result of the above transaction, the Company is reporting Asia operations for all presented periods in discontinued operations and, as such, the financial statement information provided in this report for continuing operations for the years ended December 31, 2012 and 2011 are presented in one reportable segment.

Nigeria - Oyo Field Production Sharing Contract Interest

In December 2009, Nigerian Agip Exploration Limited (“NAE”), a subsidiary of Italy's ENI SpA, and CAMAC Energy Holdings Limited (“CEHL”) announced that they had commenced production of the Oyo Field, offshore Nigeria. 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.  Some of the associated gas has been re-injected into the Oyo Field reservoir by a third well, to minimize flaring and to maximize oil recovery.

Through December 31, 2012, the Company incurred a total of $59.7 million in costs relative to the workover to reduce gas production rising from well #5 in the Oyo Field, offshore Nigeria, with the objective of increasing crude oil production from this well.  By joint agreement with Allied Energy Plc. (“Allied”), a related party, the Company has committed to pay for the workover. To the extent the Company 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 Production Sharing Contract (“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. As of December 31, 2012, $40.4 million of these costs have been recovered as revenue and we expect to recover the remainder as revenue in future liftings.  In connection with funding for part of these costs prior to receiving cost recovery, the Company entered into a Promissory Note and Guaranty Agreement with a related party, which is discussed below under “Promissory Note and Guaranty Agreement.” The remainder is being funded using available cash and the future Oyo Field lifting proceeds.

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The workover on well #5 in the Oyo Field initially reduced the amount of gas and water production; however, the oil production rate did not significantly improve.  The current water cut is approximately 27% with the gas production fairly stabilized over time.

Well #6 in the Oyo Field currently produces at a water cut of approximately 81%. The Company continues to evaluate the viability of placing this well on a gas lift to increase the oil rate.

Based on the production history of the Oyo Field, the 2011 completed study by Netherland, Sewell & Associates Inc. (“NSAI”), and validated by a recent in-house simulation study, the Company believes that three additional development wells will be required to recover all economically recoverable reserves in the Central West block, in which the Oyo Field is located.  Three additional wells will also be required to recover the possible reserves from the Central Eastern block.  The Company is continuing to explore options for marketing Oyo Field gas to third party gas processing and transportation facilities.

Allied has informed the Company that it plans to drill a new well in the Oyo Field commencing in mid 2013.  The new well, Oyo #7, will be designed to both increase the current oil production levels and test the prospective resource potential of the deeper Miocene reservoir in the field.

Nigeria - OML 120/121 Transaction

In April 2010, the Company acquired from affiliates of CAMAC Energy Holdings Limited (“CEHL”) certain rights to their interests relating to the Oyo Field (the “Oyo Contract Rights”) in the OML 120/121 PSC in exchange for cash and shares of common stock of the Company.

In December 2010, the Company entered into a Purchase and Continuation Agreement (the “Purchase Agreement”) with CEHL and such affiliates, pursuant to which the Company agreed to acquire certain rights of the remainder of the affiliates’ interest (the “OML 120/121 Transaction”) in the OML 120/121 PSC (the “Non-Oyo Contract Rights”).  In exchange for the Non-Oyo Contract Rights, the Company agreed to an option-based consideration structure and paid $5.0 million in cash to Allied, an affiliate of CEHL, upon the closing of the OML 120/121 Transaction in February 2011. The Company has the option to elect to retain the Non-Oyo Contract Rights upon payment of additional consideration to Allied upon the achievement of certain milestones relating to exploration and production outside of the Oyo Field.

If any of the milestones are reached and the Company elects not to retain the Non-Oyo Contract Rights at that time, then all the Non-Oyo Contract Rights will automatically revert back to CEHL without any compensation due to the Company and with CEHL retaining all consideration paid by the Company to date.  As of December 31, 2012, none of the milestones had been reached.

Dr. Kase Lawal, the Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is a director of each of CEHL, CAMAC International (Nigeria) Limited (“CINL”) and Allied.  Dr. Lawal also owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CEHL.  As a result, Dr. Lawal may be deemed to have an indirect material interest in the transaction contemplated by the OML 120/121 PSC.  Chairman Lawal recused himself from participating in the consideration and approval by the Company’s Board of Directors of the OML 120/121 Transaction.

Promissory Note and Guaranty Agreement

On June 6, 2011, CAMAC Petroleum Limited (“CPL”), a wholly owned subsidiary of the Company, executed a Promissory Note (the “Promissory Note”) in favor of Allied (the “Lender”). Under the terms of the Promissory Note, the Lender agreed to make loans to CPL, from time to time and pursuant to requests by CPL, in an aggregate sum of up to $25.0 million. Interest accrues on outstanding principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum.  CPL may prepay and re-borrow all or a portion of such amount from time to time.  Pursuant to the initial terms of the Promissory Note, the unpaid aggregate outstanding principal amount of all loans, was to mature on June 6, 2013.  Subsequently, in August 2012 the Promissory note was amended to extend the maturity date to October 15, 2013, and then amended again in March 2013 to extend the maturity date to July 15, 2014.  The Company has irrevocably, unconditionally and absolutely guaranteed all of CPL’s obligations under the Promissory Note.   As of December 31, 2012, $0.9 million was outstanding.

Dr. Kase Lawal, the Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is a director of each of CEHL, CINL, and the Lender.  Dr. Lawal also owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CEHL, and CINL and the Lender are each wholly-owned subsidiaries of CEHL. As a result, Dr. Lawal is deemed to have an indirect material interest in the transaction contemplated by the Promissory Note. Dr. Lawal fully disclosed the material facts as to his relationship to the Lender prior to Board approval.

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Kenya

In May 2012, the Company, through an indirect wholly owned subsidiary, entered into four production sharing contracts (“Kenya PSCs”) with the Government of the Republic of Kenya, covering previously awarded exploration Blocks L1B and L16, and new offshore exploration Blocks L27 and L28.  For all of the blocks, the Company will be the operator, with the government having the right to participate up to 20%, either directly or through an appointee, in any area subsequent to declaration of a commercial discovery.  The Company is responsible for all exploration expenditures.

The Kenya PSCs for Blocks L1B and L16 each provide for an initial exploration period of two years with specified minimum work obligations during that period.  Prior to the end of the initial exploration period, the Company will acquire and interpret gravity and magnetic data and acquire, process and interpret 2D seismic data.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploratory well on each block in each such additional period.

The Kenya PSCs for Blocks L27 and L28 each provide for an initial exploration period of three years with specified minimum work obligations during that period.  Prior to the end of the initial exploration period, the Company will conduct for each block a regional geological study and acquire, process and interpret 3D seismic data.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploratory well on each lock, in each such additional period.

In addition to the minimum work obligations, each of the Kenya PSC’s require annual surface rental payments, training fund payments and contributions to local community development projects.  All of the Kenya PSCs also include customary provisions including but not limited to governing law, confidentiality, force majeure, arbitration, and abandonment and decommissioning costs.

The Gambia

In May 2012, the Company, through an indirect wholly owned subsidiary, signed two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia (the “Licenses”), for previously awarded exploration blocks A2 and A5 (“the Blocks”).  For both Blocks, the Company will be the operator, with the Gambia National Petroleum Company (“GNPC”) having the right to elect to participate up to a 15% interest, following approval of a development and production plan. The Company is responsible for all expenditures prior to such approval even if the GNPC elects to participate.

The Licenses for both Blocks provide for an initial exploration period of four years with specified work obligations during that period.  Prior to the end of the initial exploration period, the Company will conduct for each Block a regional geological study, acquire, process and interpret 3D seismic data, drill one exploration well to the total depth of 5,000 meters below mean sea level and evaluate drilling results, with the first two work obligations due prior to the end of the second year.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploration well in each additional period for each Block.

In addition to the minimum work obligations, the Licenses require annual rental payments and training and resource fees.  Each of the Licenses also include customary provisions including but not limited to governing law, confidentiality, force majeure, arbitration, and abandonment and decommissioning costs.

Plan of Operation

The following describes in general terms the Company’s plan of operation and development strategy for the twelve-month period ending December 31, 2013 (the “Next Year”). During the Next Year, the Company plans to focus its efforts toward realizing and maximizing value in OML 120/121 as a whole (including the Oyo Field) in coordination with the operating contractor and pursuing further additions to its exploration portfolio in East and West Africa. We are limited in our ability to grow by the availability of capital for our businesses and each project. The Company’s ability to successfully consummate any of its projects, including the projects described above, is contingent upon the making of any required deposits, obtaining the necessary governmental approvals and executing binding agreements to obtain the rights we seek within limited timeframes.

Additionally, the Company plans to continue significant efforts on developing corporate infrastructure, accounting controls, policies and procedures, and establishing foreign and domestic human and operational resources necessary to integrate, support and maximize its contract rights acquired from CEHL.

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The Company has a Promissory Note (term credit facility) of up to $25 million from an affiliated company.  At December 31, 2012 there was a principal balance of $0.9 million borrowed under this facility.  The credit facility provides for an annual interest rate based on 30 day Libor plus two percentage points with all amounts due and payable no later than July 15, 2014.  Because the costs of  the workover on well # 5 in the Oyo Field are being recovered as Cost Oil revenues under the OML 120/121 PSC, any loan balances on this facility will be repaid within the terms of the borrowings.  The portion of the workover funded from the Company’s own cash is also recoverable as Cost Oil revenues, subject to future production levels, and after future recovery will be available for future operations.

The Company has assembled a management team with experience in the fields of international business development, geology, petroleum engineering, strategy, government relations and finance.  Members of the Company’s management team previously held positions in oil and gas development and screening roles with domestic and international energy companies and will seek to utilize their experience, expertise and contacts to create value for shareholders.

Among the general strategies we use are:

● Identifying and capitalizing on opportunities that play to the expertise of our management team;

● Leveraging our productive asset base and capabilities to develop additional value;

● Actively managing our assets and ongoing operations while attempting to limit capital exposure;

● Enlisting external resources and talent as necessary to operate/manage our properties during peak operations;

● Implementing an exit strategy with respect to each project with a view to maximizing asset values and returns; and

● Leveraging our rights of first refusal on CEHL projects to preview and negotiate additional value-added projects from its project pipeline.

With respect to specific geographical areas our strategies include:

● Continue development of Oyo Field to extract value while maximizing economic return;

● Execute the successful exploration and development of additional prospects in OML 120/121;

● Utilize our existing presence through our Nigerian subsidiary to acquire additional Nigeria oil and gas assets;

● Continue the exploration and development of Kenya and The Gambia blocks; and

● Continue to pursue further additions to its exploration portfolio in East and West Africa. 

Results of Operations – Continuing Operations

In 2010, the Company commenced recording revenues from operations and ceased reporting as a development stage company and commenced reporting as an operating company. We may experience fluctuations in operating results due to a variety of factors, including changes in daily crude oil production volumetric rates, changes in crude oil sales prices per barrel, our ability to obtain additional financing in a timely manner and on terms satisfactory to us, our ability to successfully develop our business model, the amount and timing of operating costs and capital expenditures relating to the expansion of our business, operations and infrastructure and the implementation of marketing programs, key agreements, and strategic alliances, and general economic conditions specific to our industry. The Company’s focus continues to be the development of new energy ventures, directly and through other partnerships in which it may participate that will provide value to its stockholders.

As a result of limited capital resources since our inception, the Company has relied on the issuance of equity securities as a means of compensating employees and non-employees for services. The Company enters into equity compensation agreements with non-employees if it is in the best interest of the Company and in accordance with applicable federal and state securities laws. In order to conserve its limited operating capital resources, the Company anticipates continuing to compensate employees and non-employees partially with equity compensation for services during the next year.  This policy may have a material effect on the Company’s results of operations during the next year.

In August 2012, the Company divested its wholly-owned Hong Kong subsidiary PAPL for cash consideration of $2.5 million and 9.6 million fully paid ordinary shares, net of selling expenses, of Leyshon, a natural resources mining company based in Beijing, China.  The Leyshon shares had a fair market value of $1.9 million, and have since been sold.

PAPL held the Company’s interest in the Zijinshan production sharing contract relating to the Zijinshan Block in the Shanxi Province of China. Since 2008, the Company engaged in exploration activities on this Block in search of coalbed methane and other gas.  The Company made a strategic decision to monetize this asset and withdraw from activity in China in order to focus its efforts and capital resources on its core Africa activities.

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As a result of the above transaction, the Company is reporting Asia operations for all presented periods in discontinued operations and, as such, the financial statement information provided in this report for continuing operations for the years ended December 31, 2012 and 2011 are presented in one reportable segment.

Africa Operations

As of December 31, 2012, our Africa operations, which commenced in April 2010, were comprised of an economic interest in the OML 120/121 PSC in offshore Nigeria, of which the Oyo Field portion had active crude oil production.  The Oyo Field commenced crude oil production in December 2009, and the Company acquired its economic interest on April 7, 2010 from CEHL Group.  Under the structure of the OML 120/121 PSC (capitalized terms as defined in the agreement), crude oil produced is allocated among Royalty Oil (for royalties payable to the Nigerian government), Cost Oil (for recovery of capital and operating costs), Tax Oil (for income taxes payable to the Nigerian government), and Profit Oil which is allocated 100% to the operating interest owners.  Through December 31, 2012 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.  There are also certain pre-OML 120/121 PSC costs incurred which may ultimately qualify for inclusion in the cost base for recovery as Cost Oil upon approval by the applicable Nigerian authorities.  A portion of these costs would be allocable to the Company’s interest.  To date, two oil producing wells (wells #5 and #6) have been drilled and are in production.  The present development plan provides for at least two additional oil producing wells which if successful would result in increased production rates for the field and additional revenues and cash flows.

The Company reports its share of net production barrels in the period physically produced and reports sales revenue for the related barrels only when a lifting (sale) occurs.  Production for the entire field is stored in a FPSO vessel until sufficient tanker-size quantity is available for lifting.  The exact timing of liftings is affected by the rate of daily production.  For production not yet sold, our net share is estimated from total field production for the respective period multiplied by our applicable percentage of total proceeds we received in the latest lifting settlement prior to the date of production. The Company’s share of net production (which excludes royalties and the share of the other partner) from two oil producing wells averaged 401 barrels per day for year 2012 and 923 barrels per day for the year 2011. During both 2012 and 2011, the gross production rate decreased as compared to initial rates, due to increased gas intrusion in well #5 and increased water production principally in well #6. The total gross production from the Oyo Field was approximately 1,010,000, barrels for year 2012 and approximately 1,356,000 barrels for year 2011, including royalty barrels. The Company’s share of net production, which excludes royalty barrels and the share of the other partner, was approximately 147,000 barrels for year 2012 and approximately 337,000 barrels for year 2011.  Average revenue per barrel on crude oil sold in the years ended December 31, 2012 and 2011 was $112.60 and $112.91, respectively.

Through December 31, 2012, the Company incurred a total of $59.7 million in costs relative to the workover to reduce gas production rising from well #5 in the Oyo Field, offshore Nigeria, with the objective of increasing crude oil production from this well.  By joint agreement with Allied, a related party, the Company has committed to pay for the workover. To the extent the Company 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. As of December 31, 2012, $40.4 million of these costs have been recovered as revenue and we expect to recover the remainder as revenue in future liftings.  In connection with funding for part of these costs prior to receiving cost recovery, the Company entered into a Promissory Note and Guaranty Agreement with a related party, which is discussed under “Promissory Note and Guaranty Agreement” within Part I, Item 1 of this document. The remainder is being funded using available cash and the future Oyo Field lifting proceeds.

The Company recognizes crude oil revenue at time of sale to the customer, which can result in Cost Oil revenue recognition in a later period than the associated recoverable expense. At present, sales do not occur every month because of cargo size requirements. For future periods, net operating income or loss for Africa also will be affected by changes in the overall level of production in the Oyo Field, fluctuations in the market prices realized, changes in our percentage share of crude oil sales, and levels of our operating expenses, including operating expenses chargeable to the OML 120/121 PSC that result in recovery as Cost Oil. The Company is currently dependent on this field as our only present source of revenues.

In June 2012, NAE completed the previously announced sale of its 40% working interest in OML 120/121 to Allied, an affiliate of the Company.  Allied has informed the Company that it plans to drill a new well in the Oyo Field commencing in mid 2013.  The new well, Oyo #7, will be designed to both increase the current production levels and test the prospective resource potential of the deeper Miocene reservoir in the field.

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On January 7, 2013, we announced that Allied had signed a Deed of Assignment (“Deed”) with Transocean Ltd. (“Transocean”) and Nigerian Petroleum Development Corporation Limited (“NPDC”) for the Sedneth 701 semi-submersible drilling rig to carry out the drilling of the Oyo #7 well.

Consolidated Statements of Operations

Comparison of 2012 and 2011

Our revenues in 2012 were $16,624,000 as compared to $37,922,000 for 2011. The $21,298,000 decrease was primarily due to lower Cost Oil recovery (cost recovery of workover costs incurred on well #5 in the Oyo Field) in 2012 compared to 2011 and  lower Profit Oil sales volumes sold in the current period.  During 2012 and 2011, the average gross production from the Oyo Field was 2,759 and 3,714 barrels per day, respectively, and the Company’s share of average daily net production was 401 and 923 barrels per day, respectively. The revenue per barrel on crude oil sold during 2012 and 2011 was $112.60 and $112.91, respectively.

Lease operating expenses consist of personnel costs and contractor charges directly associated with the production of oil.  Our lease operating expenses in 2012 were $326,000, as compared to $30,882,000 for 2011. The $30,556,000 decrease was primarily due to lower workover costs of $28,977,000 related to well #5 in the Oyo Field and lower technical services cost of $1,653,000.  The technical services agreement related to the Oyo Field operations was terminated as of March 31, 2011.

Exploratory expenses consist of salaries and personnel costs related to exploration activities, drilling costs for unsuccessful wells, costs for acquisition of seismic data and lease related costs (surface fees, seismic data, training and community) charged to expense.  Our exploratory expenses in 2012 were $3,236,000 as compared to $890,000 for 2011. The $2,346,000 increase was due to higher lease related costs of  $1,398,000 related to our recent Kenya and Gambia lease acquisitions, higher salaries and benefits expense of $515,000  and higher other costs of $433,000.

Depreciation, depletion and amortization expenses consist of depletion of oil reserves and depreciation of leasehold improvements, furniture and fixtures and computer equipment. Our depreciation, depletion and amortization expenses in 2012 were $10,750,000 as compared to $13,477,000 for 2011. The $2,727,000 decrease was primarily due to lower sales volumes in 2012, primarily related to the timing of liftings and lower production volumes, partially offset by an increased depletion rate in the current period.

General and administrative expenses consist primarily of salaries and related personnel costs of executive management, finance, accounting, legal and human resources, accounting and legal services, consulting projects and insurance. Our general and administrative expenses in 2012 were $10,998,000 as compared to $13,336,000 for 2011. The $2,338,000 decrease was primarily due to lower salaries and benefits expense of $1,390,000, primarily due to officer resignations in the prior period, and lower stock-based compensation of $1,745,000, partially offset by higher legal costs of $425,000 and higher other costs of $372,000.

Liquidity and Capital Resources

As of December 31, 2012, the Company had cash and cash equivalents of $3,806,000, accounts receivable of $6,103,000 and current liabilities of $17,882,000.

The following table provides summarized statements of net cash flows for the years ended December 31, 2012 and 2011:

	Years Ended December 31,
	2012			2011
	(In thousands)
Net cash used in operating activities	$	(5,897	)	$	(14,654	)
Net cash provided by (used in) investing activities	$	1,219		$	(6,860	)
Net cash (used in) provided  by financing activities	$	(5,125	)	$	6,177
Effect of exchange rate changes on cash	$	(17	)	$	45
Net decrease in cash and cash equivalents	$	(9,820	)	$	(15,292	)

Net cash used in operating activities was $5,897,000 in 2012, as compared to $14,654,000 in 2011.  The decrease of net cash used in operating activities of $8,757,000 was principally due to cash payments related to the workover of well #5 in the Oyo Field in the prior period, and by the current period decrease in net loss before non-cash expenses (primarily dry hole costs, depreciation, depletion, amortization and stock-based compensation) and before the gain on divestiture.

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Net cash provided by investing activities was $1,219,000 in 2012, as compared to net cash used in investing activities of $6,860,000 in 2011.  The change in net cash used in investing activities was partially due to the $5,000,000 payment related to the OML 120/121 PSC in the prior period, offset by the current period The Gambia and Kenya lease bonus payments of $3,240,000, less net cash proceeds of $2,364,000 from the divestiture of China and $1,966,000 from the sale of long-term investments.

Net cash used in financing activities was $5,125,000 in 2012, as compared to net cash provided by financing activities of $6,177,000 in 2011. The change in net cash used in financing activities was primarily due to the excess of payments greater than proceeds from the Promissory Note during the current period.  At December 31, 2012, the Company had the ability to borrow $24,128,000 under the $25,000,000 Promissory Note.

On June 6, 2011, CPL, a wholly owned subsidiary of the Company, executed a Promissory Note in favor of Allied. Under the terms of the Promissory Note, the Lender agreed to make loans to CPL, from time to time and pursuant to requests by CPL, in an aggregate sum of up to $25.0 million. Interest accrues on outstanding principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum.  CPL may prepay and re-borrow all or a portion of such amount from time to time.  Pursuant to the initial terms of the Promissory Note, the unpaid aggregate outstanding principal amount of all loans, was to mature on June 6, 2013.  Subsequently, in August 2012 the Promissory note was amended to extend the maturity date to October 15, 2013, and then amended again in March 2013 to extend the maturity date to July 15, 2014.  The Company has irrevocably, unconditionally and absolutely guaranteed all of CPL’s obligations under the Promissory Note.   As of December 31, 2012, $0.9 million was outstanding.

Our future working capital requirements and long-term capital requirements will depend upon numerous factors, including progress of our exploration and development programs on existing assets, acquisitions of new exploration and development opportunities, market developments, and the status of our competitors.

As of December 31, 2012, the Company incurred $59.7 million in expenses on the workover to reduce gas production arising from well #5 in the Oyo Field, with the objective of improving the crude oil production rate per day.  By agreements involving Allied, the Company will pay for the workover.  As of December 31, 2012, $44.1 million of this amount had been paid.

Based upon current cash flow projections, management believes that the Company will have sufficient capital resources to meet projected cash flow requirements for the next twelve months from the date of filing this report, assuming no additional participation in Oyo Field operating and development costs through such date.

Our ability to execute our business plan will also depend on whether we are able to raise additional funds through equity, debt financing or strategic alliances. Such additional funds may not become available on acceptable terms, if at all, and any additional funding obtained may not be sufficient to meet our needs in the long-term. Through December 31, 2012, substantially all of our capital had been raised through private placements and registered direct offerings of equity instruments.  

Critical Accounting Policies and Estimates

The discussion and analysis of our plan and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The consolidated financial statements include the accounts of CAMAC Energy Inc. and its wholly owned and  majority owned direct and indirect subsidiaries in the respective periods. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates based on assumptions. Estimates affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenues and expenses during the reporting periods.  Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in preparation of consolidated financial statements are appropriate, actual results could differ from those estimates.  Estimates that may have a significant effect include oil and natural gas reserve quantities, and depletion and amortization relating to oil and natural gas properties, and income taxes.  The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, more experience is acquired, additional information is obtained and our operating environment changes.

Property, Plant and Equipment

The Company follows the “successful efforts” method of accounting of its costs of acquisition, exploration and development of oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred.  Drilling costs of exploratory wells are capitalized pending determination that proved reserves have been found. If the determination is dependent upon the results of planned additional wells and require additional capital expenditures to develop the reserves, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well as a producing well, and additional wells are underway or firmly planned to complete the evaluation of the well.  Exploratory wells not meeting the criteria for continued capitalization are expensed when such a determination is made. Other exploration costs are expensed as incurred.

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Depreciation, depletion and amortization for productive oil and gas properties are recorded on a unit-of-production basis.  For other depreciable property, depreciation is recorded on a straight line basis over the estimated useful life of the assets which ranges between three to five years or the lease term. Repairs and maintenance costs are charged to expense as incurred.

The Company’s long-lived assets (other than financial instruments) by geographic area were as follows:

	As of December 31,
	2012		2011
	(In thousands)
Property, plant and equipment, net
United States	$	418	$	243
Outside United States		188,668		195,979
Total	$	189,086	$	196,222

Impairment of Long-Lived Assets

The Company reviews its long-lived assets in property, plant and equipment for impairment in accordance with ASC Topic 360, (Property, Plant and Equipment). Review for impairment of long-lived assets occurs whenever changes in circumstances indicate that the carrying amount of assets may not be fully recoverable.  Possible indicators of impairment include current period losses combined with a history of losses, significant downward oil and gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable. An impairment loss is recognized for assets to be held and used when the estimated undiscounted future cash flows expected to result from the asset including ultimate disposition are less than its carrying amount. In the case of oil and gas properties, the Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts.  Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset.  Our cash flow projections into the future include assumptions on variables such as future sales, sales prices, operating costs, economic conditions, market competition and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount over the fair value of the assets.

Asset Retirement Obligations

The Company accounts for asset retirement obligations in accordance with ASC Topic 410 (Asset Retirement and Environmental Obligations), which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. ASC 410 requires the Company to record a liability for the present value using a credit-adjusted risk free interest rate of the estimated site restoration costs with a corresponding increase to the carrying amount of the related long-lived assets. As a result of the lack of capital deployed on a historical basis, to date the Company has not recorded any future asset retirement obligations.

Revenues

Revenues are recognized when the earnings process is complete, an exchange transaction has taken place and excludes royalties. An exchange transaction may be a physical sale, the providing of services, or an exchange of rights and privileges.  The recognition criteria are satisfied when there exists a signed contract with defined pricing, delivery and acceptance (as defined in the contract) of the product or service have occurred, there is no significant uncertainty of collectability, and the amount is not subject to refund. Oil revenue is recognized using the sales method for our share of Cost Oil and Profit Oil for each crude oil lifting in Nigeria.

Income Taxes

The Company provides for income taxes using the asset and liability method of accounting for income taxes in accordance with ASC Topic 740 (Income Taxes). Under the asset and liability method, deferred tax assets and liabilities are recognized for temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting purposes and for operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be fully realized.

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The Company evaluates any tax deduction and tax refund positions in a two-step process.  The first step is to determine whether it is more likely than not that a tax position will be sustained.  If that test is met, the second step is to determine the amount of benefit to recognize in the consolidated financial statements.

The Company’s continuing practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of other income (expense) in its Consolidated Statements of Operations. As of December 31, 2012, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.

Stock-Based Compensation

The Company recognizes all stock-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their grant-date fair values in accordance with ASC Topic 718-10 (Stock Compensation). The Company values its stock options awarded using the Black-Scholes option pricing model, and the restricted stock is valued at the grant date closing market price. Compensation expense for stock options and restricted stock is recorded over the vesting period on a straight line basis. Stock-based compensation paid to non-employees in vested stock is valued at the fair value at the applicable measurement date and charged to expense as services are rendered.

Net Earnings (Loss) Per Common Share

The Company computes earnings or loss per share under ASC Topic 260 (Earnings per Share). Net earnings or loss per common share is computed by dividing net earnings or loss by the weighted average number of shares of common stock and applicable dilutive common stock equivalents outstanding during the year. Dilutive common stock equivalents consist of shares issuable upon the exercise of the Company's stock options, unvested restricted stock, and warrants (calculated using the treasury stock method).  Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase earnings per share or decrease net loss per share) are excluded from diluted earnings (loss) per share.

Recently Issued Accounting Standards Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (“FASB”) issued ASU 2011-11 regarding disclosure requirements for assets and liabilities that have been offset in the balance sheet.  The scope includes financial instruments and derivative instruments that are either (i) presently offset as permitted under existing accounting principles for offsetting of financial instruments and derivatives in certain cases or (ii) subject to an enforceable master netting agreement or similar agreement whether or not they have been offset.  The new disclosures related to offsetting include the gross amounts, amounts offset and net amounts as recorded.  For amounts subject to enforceable master netting agreements, disclosure is required for the amounts of financial instruments and other derivative instruments not offset, amounts related to financial collateral, and the net amounts.   The ASU is effective for annual and interim periods beginning on or after January 1, 2013 and requires retrospective application for comparative prior periods presented.  At December 31, 2012, the Company did not have any transactions of the types subject to this ASU.

Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements other than the operating leases disclosed above.

Inflation

It is the opinion of the Company that inflation has not had a material effect on its operations.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this Item.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

The Company’s Financial Statements and the accompanying Notes that are filed as part of this Annual Report are listed under Part IV, Item 15. Exhibits, Financial Statements and Schedules, and are set forth immediately following the signature

pages of this Form 10-K.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including its Chief Executive Officer (“CEO”) and Principle Financial Officer (“PFO”), as appropriate, to allow timely decisions regarding required disclosure.

Management of the Company, with the participation of its CEO and PFO, evaluated the effectiveness of the Company’s disclosure controls and procedures. Based on their evaluation, as of the end of the period covered by this Form 10-K, the Company’s CEO and PFO have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective.

Management’s Report On Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, our principal executive and principal financial officers and is effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles (“GAAP”) and includes those policies and procedures that:

● Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets,

● Provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and directors of the Company, and

● Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. Our system contains self-monitoring mechanisms, and actions are taken to correct deficiencies as they are identified.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012, based on the criteria described in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

Based on this assessment, management, including the Company’s CEO and PFO, concluded that our internal control over financial reporting was effective as of December 31, 2012.

Changes in Internal Control Over Financial Reporting

No change in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended December 31, 2012, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.   OTHER INFORMATION

None.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE

The information required by this item is incorporated herein by reference to the 2013 Proxy Statement or Form 10-K/A which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.

ITEM 11.  EXECUTIVE COMPENSATION

Information called for by Item 11 of Form 10-K will be set forth in the 2013 Proxy Statement or Form 10-K/A, which is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance under Equity Compensation Plans

The following table includes the information as of December 31, 2012 for our equity compensation plans:

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)			Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)
Equity compensation plans approved by security holders (1) (2)		3,128,466	$	0.98	(3)		9,246,515
			$	3.93	(4)

(1)   Includes the 2007 Stock Plan and 2009 Equity Incentive Plan.

(2)   Includes  remaining warrants exercisable for 553,481 shares of Common Stock, originally issued in 2007  and 2010 to placement agents, for which issuance was approved by stockholders of the Company.

(3)   The weighted average exercise price of stock options.

(4)   The weighted average exercise price of stock warrants.

Other information called for by Item 12 of Form 10-K will be set forth in the 2013 Proxy Statement or Form 10-K/A , which is incorporated herein by reference.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information called for by Item 13 of Form 10-K will be set forth in the 2013 Proxy Statement or Form 10-K/A ,which is incorporated herein by reference.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information called for by Item 14 of Form 10-K will be set forth in the 2013 Proxy Statement or Form 10-K/A, which is incorporated herein by reference.

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PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES

(a) Documents filed as part of this Annual Report:

The following is an index of the financial statements, schedules and exhibits included in this Form 10-K or incorporated herein by reference.

(1)	Consolidated Financial Statements
	Reports of Independent Registered Public  Accounting Firms
	Consolidated Balance Sheets at  December 31, 2012 and 2011
	Consolidated Statements of Operations for the  years ended December 31, 2012 and 2011
	Consolidated Statements of Comprehensive Income (Loss) for the  years ended December 31, 2012 and 2011
	Consolidated Statements of Equity for the years ended December 31, 2012 and 2011
	Consolidated Statements of  Cash Flows for  the years ended December 31, 2012 and 2011
	Notes to Consolidated Financial  Statements
(2)	Consolidated Financial Statement  Schedules
	Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)
	Schedules not included have been omitted because they are not applicable or the required information is shown in the consolidated financial statement or notes.
(3)	Exhibits

The following exhibits are filed with the report:

Exhibit Number	Description
2.1	Amended and Restated Agreement and Plan of Merger and Reorganization, dated February 12, 2007, as amended on April 20, 2007, by and among the Company, IMPCO and IMPCO Merger Sub (incorporated by reference to Exhibit 10.16 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).
2.2	Agreement and Plan of Merger, dated July 1, 2008, by and among Pacific Asia Petroleum, Inc., Navitas Corporation and Navitas LLC (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K (No. 000-52770) filed on July 8, 2008).
2.3	Amended and Restated Agreement and Plan of Merger and Reorganization, dated February 12, 2007, as amended on April 20, 2007, by and among the Company, ADS and ADS Merger Sub (incorporated by reference to Exhibit 10.15 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).
3.1	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).
3.2	Bylaws of the Company (incorporated by reference to Exhibit 3.2 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).
3.3	Certificate of  Amendment to Amended and Restated Certificate of Incorporation, filed April 7, 2010 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on April 13, 2010).
3.4	Amended and Restated Bylaws of the Company as of April 11, 2011 (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed on May 3, 2011).
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).
4.2	Form of Common Stock Warrant (incorporated by reference to Exhibit 4.2 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).
4.3	Company 2007 Stock Plan (incorporated by reference to Exhibit 10.1 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). *
4.4	Company 2009 Equity Incentive Plan (incorporated by reference to Registration Statement on Form S-8 (No. 333-175294) filed on July 1, 2011).*
4.5	Form of Series A Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 12, 2010).
4.6	Form of Series C Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on March 3, 2010).

38

4.7	Registration Rights Agreement, by and between the Company and CAMAC Energy Holdings Limited, dated April 7, 2010 (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on April 13, 2010).
4.8	Form of Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on December 23, 2010).
4.9	Registration Rights Agreement, dated as of February 15, 2011, by and among CAMAC Energy Inc., CAMAC Energy Holdings Limited, Allied Energy Plc, and CAMAC International (Nigeria) Limited (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 16, 2011).
10.1	Form of Securities Purchase Agreement, dated February 10, 2010 (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 12, 2010).
10.2	Company 2007 Stock Plan form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). *
10.3	Company 2007 Stock Plan form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). *
10.4	Form of Indemnification Agreement for Officers.*
10.5	Form of Indemnification Agreement for Directors.*
10.6	Company 2009 Equity Incentive Plan form of Stock Option Agreement (incorporated by reference to Exhibit 10.5 of our Annual Report on Form 10-K (No. 001-34525) filed on March 2, 2010).*
10.7	Company 2009 Equity Incentive Plan form of Restricted Shares Grant Agreement (incorporated by reference to Exhibit 10.6 of our Annual Report on Form 10-K (No. 001-34525) filed on March 2, 2010). *
10.8	Purchase and Sale Agreement, dated November 18, 2009, by and among the Company, CAMAC Energy Holdings Limited, CAMAC International (Nigeria) Limited, and Allied Energy Plc. (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K (No. 001-34525) filed on November 23, 2009).
10.9	Form of Securities Purchase Agreement, dated  March 2, 2010 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 10-K filed March 3, 2010).
10.10	Agreement Novating Production Sharing Contract, by and among Allied Energy Plc, CAMAC International (Nigeria) Limited, Nigerian AGIP Exploration Limited, and CAMAC Petroleum Limited, dated April 7, 2010 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K dated April 13, 2010).
10.11	The Oyo Field Agreement, by and among Allied Energy Plc, CAMAC Energy Holdings Limited and CAMAC Petroleum Limited, dated April 7, 2010 (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on April 13, 2010).
10.12	The Right of First Refusal Agreement, by and among the Company, CAMAC Energy Holdings Limited, CAMAC International (Nigeria) Limited, and Allied Energy Plc, dated April 7, 2010 (incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed on April 13, 2010).
10.13	Employment Agreement, dated September 21, 2010, by and between Byron A. Dunn and the Company (incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010).*
10.14	Employment Offer Letter, dated September 1, 2010, by and between Abiola L. Lawal and the Company (incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010).*

* Indicates a management contract or compensatory plan or arrangement.

39

10.15	Purchase and Continuation Agreement, dated December 10, 2010, by and among CAMAC Energy Inc., CAMAC Petroleum Limited, CAMAC Energy Holdings Limited, Allied Energy Plc, and CAMAC International (Nigeria) Limited (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on December 13, 2010).
10.16	Form of Securities Purchase Agreement (incorporated by reference to Exhibit 10.1 of our Current Report filed on December 23, 2010).
10.17	Limited Waiver Agreement Related to Purchase and Continuation Agreement, dated as of February 15, 2011, by and among CAMAC Energy Inc., CAMAC Petroleum Inc., CAMAC Energy Holdings Limited, Allied Energy Plc, and CAMAC International (Nigeria) Limited (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on February 16, 2011).
10.18	Second Agreement Novating Production Sharing Contract, dated as of February 15, 2011, by and among Allied Energy Plc, CAMAC International (Nigeria) Limited, Nigerian AGIP Exploration Limited, and CAMAC Petroleum Limited (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on February 16, 2011).
10.19	Amended and Restated Oyo Field Agreement Hereby Renamed OML 120/121 Management Agreement, dated as of February 15, 2011, by and among CAMAC Petroleum Limited, CAMAC Energy Holdings Limited, and Allied Energy Plc (incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed on February 16, 2011).
10.20	Amended and Restated Employment Agreement effective March 8, 2011, by and between Abiola L. Lawal and the Company (incorporated by reference to Exhibit 10.37 of our Annual Report on Form 10-K filed on March 11, 2011).*
10.21	Separation Agreement and General Release of Claims effective April 11, 2011 by and between Mr. Byron  Dunn and the Company (incorporated by reference to Exhibit 10.5 of our Quarterly Report on Form 10-Q  filed on May 3, 2011).*
10.22	Promissory Note Agreement dated June 6, 2011 by and among CAMAC Petroleum Limited and Allied Energy Plc. (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on June 9, 2011).
10.23	Guaranty Agreement dated June 6, 2011 by and among CAMAC Energy Inc. and Allied Energy Plc. (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on June 9, 2011).
10.24	Executive Employment Agreement dated June 6, 2011 by and between Edward G. Caminos and the Company (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on June 6, 2011).*
10.25	Executive Employment Agreement dated June 6, 2011 by and between Alan W. Halsey and the Company (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on June 6, 2011).*
10.26	Executive Employment Agreement dated September 1, 2011 by and between Nicholas J. Evanoff and the Company (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on September 7, 2011).*
10.27	Executive Employment Agreement dated September 1, 2011 by and between Babatunde Omidele and the Company (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on September 7, 2011).*
10.28	Separation Agreement and General Release of Claims effective February 14, 2012 by and between Mr. Alan W. Halsey and the Company (incorporated by reference to Exhibit 10.45 of our Annual Report on Form 10-K filed on March 15, 2012).*
10.29	Separation Agreement and General Release of Claims effective February 23, 2012 by and between Mr. Edward G. Caminos and the Company (incorporated by reference to Exhibit 10.46 of our Annual Report on Form 10-K filed on March 15, 2012).*
10.30	Executive Consulting Agreement effective March 1, 2012 by and between Earl W. McNiel and the Company (incorporated by reference to Exhibit 10.47 of our Annual Report on Form 10-K filed on March 15, 2012).*

* Indicates a management contract or compensatory plan or arrangement.

40

10.31	Production Sharing Contract, by and between the Government of the Republic of Kenya and CAMAC Energy Kenya Limited, dated May 10, 2012, relating to Block L1B (incorporated by reference to Exhibit 10.4 of our Form 10-Q filed on May 9, 2012).
10.32	Production Sharing Contract, by and between the Government of the Republic of Kenya and CAMAC Energy Kenya Limited, dated May 10, 2012, relating to Block L16 (incorporated by reference to Exhibit 10.5 of our Form 10-Q filed on May 9, 2012).
10.33	Production Sharing Contract, by and between the Government of the Republic of Kenya and CAMAC Energy Kenya Limited, dated May 10, 2012, relating to Block L27 (incorporated by reference to Exhibit 10.6 of our Form 10-Q filed on May 9, 2012).
10.34	Production Sharing Contract, by and between the Government of the Republic of Kenya and CAMAC Energy Kenya Limited, dated May 10, 2012, relating to Block L28 (incorporated by reference to Exhibit 10.7 of our Form 10-Q filed on May 9, 2012).
10.35	Petroleum (Exploration, Development and Production) License, by and between the Republic of The Gambia and CAMAC Energy A2 Gambia Ltd., dated May 24, 2012, relating to Block A2 (incorporated by reference to Exhibit 10.8 of our Form 10-Q filed on May 9, 2012).
10.36	Petroleum (Exploration, Development and Production) License, by and between the Republic of The Gambia and CAMAC Energy A5 Gambia Ltd., dated May 24, 2012, relating to Block A5 (incorporated by reference to Exhibit 10.9 of our Form 10-Q filed on May 9, 2012).
10.37	Share Sale and Purchase Agreement, by and between Leyshon Resources Limited and CAMAC Energy Inc., dated July 22, 2012 (incorporated by reference to Exhibit 10.1 of our Form 10-Q filed on November 9, 2013).
10.38	Executive Employment Agreement dated February 27, 2013 by and between Earl W. McNiel and the Company.*
10.39	Amended and Extended Maturity Date of the Promissory Note dated June 6, 2011, amended August 3, 2012, by and among CAMAC Petroleum Limited and Allied Energy Plc..
10.40	Amended and Extended Maturity Date of the Promissory Note dated June 6, 2011, amended March 25, 2013, by and among CAMAC Petroleum Limited and Allied Energy Plc..
10.41	Technical Services Agreement, by and between Allied Energy Plc and CAMAC Petroleum Limited, dated January 10, 2013.
21.1	Subsidiaries of the Company
23.1	Consent of Grant Thornton LLP, Independent Registered Public Accounting Firm, filed herewith.
23.2	Consent of RBSM LLP, Independent Registered Public Accounting Firm, filed herewith.
23.3	Consent of  Gaffney, Cline & Associates
31.1	Certification of Chief Executive Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principle Financial and Accounting Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principle Financial and Accounting Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Report of Gaffney, Cline & Associates
101. INS	XBRL Instance Document.
101. SCH	XBRL Schema Document.
101. CAL	XBRL Calculation Linkbase Document.
101. DEF	XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	XBRL Label Linkbase Document.
101. PRE	XBRL Presentation Linkbase Document.

* Indicates a management contract or compensatory plan or arrangement.

41

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: April 15, 2013

CAMAC Energy Inc.
By:	/s/ Dr. Kase Lukman Lawal
	Dr. Kase Lukman Lawal
	Chief Executive Officer
	(Principal Executive Officer)
By:	/s/ Earl W. McNiel
	Earl W. McNiel
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

	Title	Date
/s/ DR.KASE LUKMAN LAWAL	Director and Chief Executive Officer	April 15, 2013
Dr. Kase Lukman Lawal	(Principal Executive Officer)
/s/ EARL W. MCNIEL	Senior Vice President and Chief Financial Officer	April 15, 2013
Earl W. McNiel	(Principal Financial Officer)
/s/ JEFFREY S. COURTRIGHT	Vice President, Controller and Treasurer	April 15, 2013
Jeffrey S. Courtright	(Principal Accounting Officer)
/s/ DR. LEE PATRICK BROWN	Director	April 15, 2013
Dr. Lee Patrick Brown
/s/ WILLIAM J. CAMPBELL	Director	April 15, 2013
William J. Campbell
/s/ J KENT FRIEDMAN	Director	April 15, 2013
J. Kent Friedman
/s/ JOHN HOFMEISTER	Director	April 15, 2013
John Hofmeister
/s/ IRA WAYNE MCCONNELL	Director	April 15, 2013
Ira Wayne McConnell
/s/ HAZEL O'LEARY	Director	April 15, 2013
Hazel O'Leary

42

GRANT THORNTON LLP

CERTIFIED PUBLIC ACCOUNTANTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

CAMAC Energy, Inc.

We have audited the accompanying consolidated balance sheet of CAMAC Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for the year ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of CAMAC Energy, Inc. and subsidiaries as of December 31, 2012, and the results of their operations and their cash flows for the year ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Houston, Texas

April 15, 2013

43

RBSM LLP

CERTIFIED PUBLIC ACCOUNTANTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

CAMAC Energy Inc.

Houston, TX

              We have audited the accompanying consolidated balance sheet of CAMAC Energy Inc. and its subsidiaries (the “Company”) as of December 31, 2011, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based upon our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. An audit includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audit provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of CAMAC Energy Inc. and its subsidiaries as of December 31, 2011 and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ RBSM LLP

New York, New York

March 15, 2012

44

CAMAC ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except for share and per share data)

	As of December 31,
	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	3,806		$	13,626
Accounts receivable		6,103			18,939
Other current assets		1,013			1,641
Current assets of discontinued operations		-			73
Total current assets		10,922			34,279
Property, plant and equipment, net:
Oil and gas properties (successful efforts method of accounting), net		188,630			195,979
Property, plant and equipment, other, net		456			243
Total property, plant and equipment, net		189,086			196,222
Other assets		11			169
Noncurrent assets of discontinued operations		36			200
Total Assets	$	200,055		$	230,870
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	15,112		$	35,305
Accrued expenses		2,770			3,563
Current liabilities of discontinued operations		-			791
Total current liabilities		17,882			39,659
Long-term note payable - related party		872			6,000
Other long-term liabilities		55			-
Total Liabilities		18,809			45,659
Commitments and Contingencies
Equity
Stockholders' equity - CAMAC Energy Inc.
Preferred stock $0.001 par value - 50,000,000 shares authorized,
none issued and outstanding		-			-
Common stock $0.001 par value - 300,000,000 shares authorized,
156,095,346 and 155,385,563 shares issued and outstanding as
of December 31, 2012 and December 31, 2011, respectively		156			155
Paid-in capital		462,801			461,157
Accumulated deficit		(281,929	)		(275,838	)
Accumulated other comprehensive income (loss)		224			(265	)
Total stockholders' equity - CAMAC Energy Inc.		181,252			185,209
Noncontrolling interests of discontinued operations		(6	)		2
Total Equity		181,246			185,211
Total Liabilities and Equity	$	200,055		$	230,870

The accompanying notes are an integral part of these consolidated financial statements.

45

CAMAC ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except for share and per share amounts)

			Years Ended December 31,
			2012			2011
Continuing Operations
	Crude oil sales, net of royalties		$	16,624		$	37,922
	Operating costs and expenses:
		Lease operating expenses and production costs		326			30,882
		Exploratory expenses		3,236			890
		Depreciation, depletion and amortization		10,750			13,477
		General and administrative expenses		10,998			13,336
	Total operating costs and expenses			25,310			58,585
	Operating loss			(8,686	)		(20,663	)
	Other expense, net			(582	)		(328	)
	Loss from continuing operations before income taxes			(9,268	)		(20,991	)
	Income tax expense			-			-
	Net loss from continuing operations			(9,268	)		(20,991	)
Discontinued Operations
	Net loss from discontinued operations, net of tax			(991	)		(4,012	)
	Gain on divestiture, net			4,160			-
	Net income (loss) from discontinued operations			3,169			(4,012	)
	Net loss			(6,099	)		(25,003	)
		Net loss attributable to noncontrolling interests - discontinued operations		8			90
	Net loss attributable to CAMAC Energy Inc.		$	(6,091	)	$	(24,913	)
Net (loss) income per common share attributable to CAMAC Energy Inc. - basic
	Continuing operations		$	(0.06	)	$	(0.14	)
	Discontinued operations		$	0.02		$	(0.03	)
	Total		$	(0.04	)	$	(0.16	)
Net (loss) income per common share attributable to CAMAC Energy Inc. - diluted
	Continuing operations		$	(0.06	)	$	(0.14	)
	Discontinued operations		$	0.02		$	(0.03	)
	Total		$	(0.04	)	$	(0.16	)
Weighted average common shares outstanding:
	Basic			155,813			154,556
	Diluted			155,813			154,556

The accompanying notes are an integral part of these consolidated financial statements.

46

CAMAC ENERGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

		Years Ended December 31,
		2012			2011
Net loss		$	(6,099	)	$	(25,003	)
Other comprehensive income (loss):
	Foreign currency adjustments		94			(31	)
	Unrealized gain (loss) on investments, net of taxes		395			(114	)
Total other comprehensive income (loss)			489			(145	)
Comprehensive loss			(5,610	)		(25,148	)
	Comprehensive loss attributable to noncontrolling interests		8			88
Comprehensive loss attributable to CAMAC Energy Inc.		$	(5,602	)	$	(25,060	)

The accompanying notes are an integral part of these consolidated financial statements.

47

CAMAC ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

											Accumulated
					Additional						Other						Total
	Common Stock				Paid-in			Accumulated			Comprehensive			Noncontrolling			Stockholders'
	Shares		Amount		Capital			Deficit			Income (Loss)			Interest			Equity
At December 31, 2010		153,612	$	154	$	458,523		$	(250,925	)	$	(120	)	$	(643	)	$	206,989
Stock issued for services		840		1		706			-			-			-			707
Exercise of warrants and options		323		-		177			-			-			-			177
Vesting of restricted stock		611		-		-			-			-			-			-
Stock-based employee compensation						2,484			-			-			-			2,484
Adjustments to noncontrolling interest						(733	)		-			-			735			2
Net loss						-			(24,913	)		-			(90	)		(25,003	)
Other comprehensive income (loss):
Foreign currency adjustments						-			-			(31	)		-			(31	)
Unrealized loss on investments, net of taxes						-			-			(114	)		-			(114	)
At December 31, 2011		155,386	$	155	$	461,157		$	(275,838	)	$	(265	)	$	2		$	185,211
Exercise of warrants and options		7		-		3			-			-			-			3
Vesting of restricted stock		514		1		-												1
Contingent consideration stock issued		188		-		890												890
Stock-based employee compensation						739			-			-			-			739
Net loss						-			(6,091	)		-			(8	)		(6,099	)
Other comprehensive income (loss):
Foreign currency adjustments						12			-			94			-			106
Unrealized gain on investments, net of taxes						-			-			395			-			395
At December 31, 2012		156,095	$	156	$	462,801		$	(281,929	)	$	224		$	(6	)	$	181,246

The accompanying notes are an integral part of these consolidated financial statements.

48

CAMAC ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2012			2011
Operating activities
Net loss	$	(6,099	)	$	(25,003	)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization		10,758			13,530
Stock-based compensation		739			2,484
Currency transaction loss (gain)		22			(31	)
Dry hole costs		(37	)		2,176
Gain on divestiture, net		(4,160	)		-
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		12,836			(8,528	)
Decrease in other current assets		649			1,841
Decrease in inventories		-			72
(Decrease) increase in accounts payable		(20,772	)		35,834
Increase (decrease) in accrued expenses		112			(37,029	)
Other		55			-
Net cash used in operating activities		(5,897	)		(14,654	)
Investing activities
Capital expenditures		(3,576	)		(7,159	)
Proceeds on divestiture, net		2,364			-
Net sales of available for sale securities		-			256
Decrease in other assets		465			43
Proceeds on long-term investments		1,966			-
Net cash provided by (used in) investing activities		1,219			(6,860	)
Financing activities
Proceeds from long-term note payable - related party		5,000			31,000
Payments of long-term note payable - related party		(10,128	)		(25,000	)
Proceeds from exercise of warrants and stock options		3			177
Net cash (used in) provided by financing activities		(5,125	)		6,177
Effect of exchange rate on cash and cash equivalents		(17	)		45
Net decrease in cash and cash equivalents		(9,820	)		(15,292	)
Cash and cash equivalents at beginning of period		13,626			28,918
Cash and cash equivalents at end of period	$	3,806		$	13,626
Supplemental disclosure of cash flow information
Cash paid for:
Interest, net	$	117		$	120
Contingent consideration stock	$	890		$	-
Supplemental disclosure of non-cash investing and financing activities:
Nonsubsidiary common stock received as partial proceeds for divestiture, net	$	1,877		$	-
Common stock issued for services	$	-		$	706

The accompanying notes are an integral part of these consolidated financial statements

49

CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. --- COMPANY DESCRIPTION

CAMAC Energy Inc. (the “Company” or “CAMAC”) is engaged in the exploration, development, and production of oil and gas outside the United States, directly and through joint ventures and other ventures in which it may participate. The Company’s name was changed from Pacific Asia Petroleum, Inc. (“PAP”) to CAMAC Energy Inc. upon the acquisition of oil and gas properties located offshore Nigeria in April 2010.

The Company operates in the upstream segment of the oil and gas industry in exploration and producing activities. The Company’s corporate headquarters is located in Houston, Texas and has offices in Nairobi, Kenya and Lagos, Nigeria.  The Company's principal assets include rights to interests in OML 120 and OML 121, offshore oil and gas leases in deep water Nigeria which include the currently producing Oyo Oilfield, and interests in six recently acquired exploration blocks in Kenya and Gambia.

NOTE 2. --- BASIS OF PRESENTATION AND LIQUIDITY

Basis of Presentation

The terms “we,” “us,” “our,” “Company,” and “our Company” refer to CAMAC and its subsidiaries and affiliates.

The accompanying consolidated financial statements include the accounts of the Company and its wholly owned and majority-owned direct and indirect subsidiaries and have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”).  All significant intercompany transactions and balances have been eliminated in consolidation. The consolidated financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial position and results of operations for the indicated periods. All such adjustments are of a normal recurring nature.

For year 2012, certain changes in presentation have been made in the consolidated financial statements, and prior periods included have been prepared with these reclasses for comparability. These include a change in accounting principle for the presentation of revenues to exclude royalties and taxes, with an offsetting decrease in costs and expenses, which was adopted effective December 31, 2011.

On January 1, 2012, the Company adopted Accounting Standards Update (“ASU”) 2011-05 amending Accounting Standards Codification (“ASC”) Topic 220 related to the presentation of comprehensive income, with the exception of the portions of ASU 2011-05 for which the effective date has been deferred by ASU 2011-12.  The Company is now presenting, in both interim and annual financial statements, items of net income (loss), other comprehensive income (loss) and total comprehensive income (loss) in two separate consecutive statements.

In July 2012, the Company signed a definitive share sale and purchase agreement to divest its interest in the Zijinshan Gas Block in China.  This transaction was completed on August 6, 2012.  The Company has classified the current and historical results of its China operations, including other inactive operations not involved in this sale, as discontinued operations, net of tax, in the accompanying consolidated statements of operations.  See Note 4 for more information regarding the sale.  Unless otherwise indicated, the information in these notes to the consolidated financial statements relates to the Company’s continuing operations.

Liquidity

The Company incurred a net loss attributable to CAMAC Energy Inc. of $6,091,000 for the year ended December 31, 2012 and at that date had an accumulated deficit of $281,929,000.  As of December 31, 2012, the Company has incurred $59.7 million in well workover expenses to reduce gas production from well #5 in the Oyo Field in order to improve the daily crude oil production rate from this well. Of this amount, $30.7 million was charged to expense in 2010, $28.9 million in 2011 and $0.1 million in 2012.  By agreements involving Allied Energy Plc, an affiliated company, the Company will pay for the workover.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

On June 6, 2011, CAMAC Petroleum Limited (“CPL”), a wholly owned subsidiary of the Company, executed a Promissory Note (the “Promissory Note”) in favor of Allied Energy Plc. (“Allied” or the “Lender”). Under the terms of the Promissory Note, the Lender agreed to make loans to CPL, from time to time and pursuant to requests by CPL, in an aggregate sum of up to $25.0 million. Interest accrues on outstanding principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum.  CPL may prepay and re-borrow all or a portion of such amount from time to time.  Pursuant to the initial terms of the Promissory Note, the unpaid aggregate outstanding principal amount of all loans, was to mature on June 6, 2013.  Subsequently, in August 2012 the Promissory note was amended to extend the maturity date to October 15, 2013, and then amended again in March 2013 to extend the maturity date to July 15, 2014.  The Company has irrevocably, unconditionally and absolutely guaranteed all of CPL’s obligations under the Promissory Note.   As of December 31, 2012, $0.9 million was outstanding.

Based upon current cash flow projections, management believes that the Company will have sufficient capital resources to meet projected cash flow requirements for the next twelve months from the date of filing this report, assuming no additional participation in Oyo Field operating and development costs through such date.

Our ability to execute our business plan will also depend on whether we are able to raise additional funds through equity, debt financing or strategic alliances. Such additional funds may not become available on acceptable terms, if at all, and any additional funding obtained may not be sufficient to meet our needs in the long-term. Through December 31, 2012, substantially all of our capital had been raised through private placements and registered direct offerings of equity instruments.  

NOTE 3. --- SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts and activities of the Company, subsidiaries in which the Company has a controlling financial interest, and entities for which the Company is the primary beneficiary.  All material intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates based on assumptions. Estimates affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenues and expenses during the reporting periods.  Accordingly, our accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in preparation of consolidated financial statements are appropriate, actual results could differ from those estimates.  Estimates that may have a significant effect include oil and natural gas reserve quantities, depletion and amortization relating to oil and natural gas properties, and income taxes.  The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, more experience is acquired, additional information is obtained and our operating environment changes.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand deposits and short-term investments with initial maturities of three months or less. The Company maintains its cash and cash equivalents in various financial institutions. The combined account balances at several institutions typically exceed Federal Deposit Insurance Corporation ("FDIC") insurance coverage and, as a result, there is a concentration of credit risk related to amounts on deposit in excess of FDIC insurance coverage. Management believes that this risk is not significant.

Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are accounted for at cost less allowance for doubtful accounts.  We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.  As of December 31, 2012 and 2011, no allowance for doubtful accounts was necessary.

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Property, Plant and Equipment

The Company follows the “successful efforts” method of accounting of its costs of acquisition, exploration and development of oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred.  Drilling costs of exploratory wells are capitalized pending determination that proved reserves have been found. If the determination is dependent upon the results of planned additional wells and require additional capital expenditures to develop the reserves, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well as a producing well, and additional wells are underway or firmly planned to complete the evaluation of the well.  Exploratory wells not meeting the criteria for continued capitalization are expensed when such a determination is made. Other exploration costs are expensed as incurred.

Depreciation, depletion and amortization for productive oil and gas properties are recorded on a unit-of-production basis.  For other depreciable property, depreciation is recorded on a straight line basis over the estimated useful life of the assets which ranges between three to five years or the lease term. Repairs and maintenance costs are charged to expense as incurred.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets in property, plant and equipment for impairment in accordance with ASC Topic 360, (Property, Plant and Equipment). Review for impairment of long-lived assets occurs whenever changes in circumstances indicate that the carrying amount of assets may not be fully recoverable.  Possible indicators of impairment include current period losses combined with a history of losses, significant downward oil and gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable. An impairment loss is recognized for assets to be held and used when the estimated undiscounted future cash flows expected to result from the asset including ultimate disposition are less than its carrying amount. In the case of oil and gas properties, the Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts.  Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset.  Our cash flow projections into the future include assumptions on variables such as future sales, sales prices, operating costs, economic conditions, market competition and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount over the fair value of the assets.

Asset Retirement Obligations

The Company accounts for asset retirement obligations in accordance with ASC Topic 410 (Asset Retirement and Environmental Obligations), which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. ASC 410 requires the Company to record a liability for the present value using a credit-adjusted risk free interest rate of the estimated site restoration costs with a corresponding increase to the carrying amount of the related long-lived assets. As a result of the lack of capital deployed on a historical basis, to date, the Company has not recorded any future asset retirement obligations.

Revenues

Revenues are recognized when the earnings process is complete and an exchange transaction has taken place. An exchange transaction may be a physical sale, the providing of services, or an exchange of rights and privileges.  The recognition criteria are satisfied when there exists a signed contract with defined pricing, delivery and acceptance (as defined in the contract) of the product or service have occurred, there is no significant uncertainty of collectability, and the amount is not subject to refund. Crude oil revenues are net of sales of royalty barrels. Oil revenue is recognized using the sales method for our share of Cost Oil and Profit Oil for each crude oil lifting in Nigeria.

Income Taxes

The Company provides for income taxes using the asset and liability method of accounting for income taxes in accordance with ASC Topic 740 (Income Taxes). Under the asset and liability method, deferred tax assets and liabilities are recognized for temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting purposes and for operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be fully realized.

The Company evaluates any tax deduction and tax refund positions in a two-step process.  The first step is to determine whether it is more likely than not that a tax position will be sustained.  If that test is met, the second step is to determine the amount of benefit to recognize in the consolidated financial statements.

The Company’s continuing practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of other income (expense) in its Consolidated Statements of Operations. As of December 31, 2012, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

Stock-Based Compensation

The Company recognizes all stock-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their grant-date fair values in accordance with ASC Topic 718-10  (Stock Compensation). The Company values its stock options awarded using the Black-Scholes option pricing model, and the restricted stock is valued at the grant date closing market price. Compensation expense for stock options and restricted stock is recorded over the vesting period on a straight line basis. Stock-based compensation paid to non-employees in vested stock is valued at the fair value at the applicable measurement date and charged to expense as services are rendered.

Net Earnings (Loss) Per Common Share

The Company computes earnings or loss per share under ASC Topic 260 (Earnings per Share). Net earnings or loss per common share is computed by dividing net earnings or loss by the weighted average number of shares of common stock and applicable dilutive common stock equivalents outstanding during the year. Dilutive common stock equivalents consist of shares issuable upon the exercise of the Company's stock options, unvested restricted stock, and warrants (calculated using the treasury stock method).  Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase earnings per share or decrease net loss per share) are excluded from diluted earnings (loss) per share.

New Accounting Pronouncements Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (“FASB”) issued ASU 2011-11 regarding disclosure requirements for assets and liabilities that have been offset in the balance sheet.  The scope includes financial instruments and derivative instruments that are either (i) presently offset as permitted under existing accounting principles for offsetting of financial instruments and derivatives in certain cases or (ii) subject to an enforceable master netting agreement or similar agreement whether or not they have been offset.  The new disclosures related to offsetting include the gross amounts, amounts offset and net amounts as recorded.  For amounts subject to enforceable master netting agreements, disclosure is required for the amounts of financial instruments and other derivative instruments not offset, amounts related to financial collateral, and the net amounts.   The ASU is effective for annual and interim periods beginning on or after January 1, 2013 and requires retrospective application for comparative prior periods presented.  At December 31, 2012, the Company did not have any transactions of the types subject to this ASU.

NOTE 4 – DISCONTINUED OPERATIONS

In August 2012, the Company divested its wholly-owned Hong Kong subsidiary Pacific Asia Petroleum Limited (PAPL) for cash consideration of $2.5 million and 9.6 million fully paid ordinary shares, net of selling expenses, of Leyshon Resources Limited (“Leyshon”), a natural resources mining company based in Beijing, China.  The Leyshon shares had a fair market value of $1.9 million, which have since been sold.

PAPL held the Company’s interest in the Zijinshan production sharing contract relating to the Zijinshan Block in the Shanxi Province of China. Since 2008, the Company engaged in exploration activities on this Block in search of coalbed methane and other gas.  The Company made a strategic decision to monetize this asset and withdraw from activity in China in order to focus its efforts and capital resources on its core Africa activities.

The Company has reclassified all assets, liabilities and the results of operations for Asia to discontinued operations for all periods presented.

Results of operations from discontinued operations are as follows:

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

	Years Ended December 31,
	2012			2011
	(In thousands)
Costs and expenses:
Exploratory expenses	$	204		$	2,545
Depreciation, depletion and amortization		8			53
General and administrative expenses		779			1,642
Other income		-			(228	)
Total costs and expenses		991			4,012
Loss before income taxes		(991	)		(4,012	)
Income tax expense		-			-
Net loss before noncontrolling interests		(991	)		(4,012	)
Noncontrolling interests		8			90
Net loss	$	(983	)	$	(3,922	)

Assets and liabilities of discontinued operations are as follows:

	December 31,		December 31,
	2012		2011
	(In thousands)
Other current assets	$	-	$	73
Property, plant and equipment, net		-		164
Other assets		36		36
Total assets	$	36	$	273
Accounts payable	$	-	$	592
Accrued expenses		-		199
Total liabilities	$	-	$	791

NOTE 5. -- ACQUISITIONS

Nigeria - OML 120/121 Transaction

In April 2010, the Company acquired from affiliates of CAMAC Energy Holdings Limited (“CEHL”) certain rights to their interests relating to the Oyo Field (the “Oyo Contract Rights”) in the OML 120/121 Production Sharing Contract (“OML 120/121 PSC”) in exchange for cash and shares of common stock of the Company.

In December 2010, the Company entered into a Purchase and Continuation Agreement (the “Purchase Agreement”) with CEHL and such affiliates, pursuant to which the Company agreed to acquire certain rights of the remainder of the affiliates’ interest (the “OML 120/121 Transaction”) in the OML 120/121 PSC (the “Non-Oyo Contract Rights”).  In exchange for the Non-Oyo Contract Rights, the Company agreed to an option-based consideration structure and paid $5.0 million in cash to Allied, an affiliate of CEHL, upon the closing of the OML 120/121 Transaction in February 2011. The Company has the option to elect to retain the Non-Oyo Contract Rights upon payment of additional consideration to Allied upon the achievement of certain milestones relating to exploration and production outside of the Oyo Field.

If any of the milestones are reached and the Company elects not to retain the Non-Oyo Contract Rights at that time, then all the Non-Oyo Contract Rights will automatically revert back to CEHL without any compensation due to the Company and with CEHL retaining all consideration paid by the Company to date.  As of December 31, 2012, none of the milestones had been reached.

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

Award of Kenya Exploration Blocks

In May 2012, the Company, through an indirect wholly owned subsidiary, entered into four production sharing contracts (“Kenya PSCs”) with the Government of the Republic of Kenya, covering previously awarded exploration Blocks L1B and L16, and new offshore exploration Blocks L27 and L28.  For all of the blocks, the Company will be the operator, with the government having the right to participate up to 20%, either directly or through an appointee, in any area subsequent to declaration of a commercial discovery.  The Company is responsible for all exploration expenditures.

The Kenya PSCs for Blocks L1B and L16 each provide for an initial exploration period of two years with specified minimum work obligations during that period.  Prior to the end of the initial exploration period, the Company will conduct for each block a regional geological study and acquire, process and interpret 3D seismic data.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploratory well on each block in each such additional period.

The Kenya PSCs for Blocks L27 and L28 each provide for an initial exploration period of three years with specified minimum work obligations during that period.  Prior to the end of the initial exploration period, the Company will conduct for each block a regional geological study and acquire, process and interpret 3D seismic data.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploratory well on each block, in each such additional period.

In addition to the minimum work obligations, each of the Kenya PSC’s require annual surface rental payments, training fund payments and contributions to local community development projects.  All of the Kenya PSCs also include customary provisions including but not limited to governing law, confidentiality, force majeure, arbitration, and abandonment and decommissioning costs.

Award of The Gambia Offshore Exploration Blocks

In May 2012, the Company, through an indirect wholly owned subsidiary, signed two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia (the “Licenses”), for previously awarded exploration blocks A2 and A5 (the “Blocks”).  For both Blocks, the Company will be the operator, with the Gambia National Petroleum Company (GNPC) having the right to elect to participate up to a 15% interest, following approval of a development and production plan. The Company is responsible for all expenditures prior to such approval even if the GNPC elects to participate.

The Licenses for both Blocks provide for an initial exploration period of four years with specified work obligations during that period.  Prior to the end of the initial exploration period, the Company will conduct for each Block a regional geological study, acquire, process and interpret 3D seismic data, drill one exploration well to the total depth of 5,000 meters below mean sea level and evaluate drilling results, with the first two work obligations due prior to the end of the second year.  The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploration well in each additional period for each Block.

In addition to the minimum work obligations, the Licenses require annual rental payments and training and resource fees.  Each of the Licenses also include customary provisions including but not limited to governing law, confidentiality, force majeure, arbitration, and abandonment and decommissioning costs.

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

NOTE 6. --- PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment were comprised of the following:

	December 31,		December 31,
	2012		2011
Oil and gas properties:	(In thousands)
Proved oil and gas properties	$	206,212	$	206,212
Less:  Accumulated depreciation, depletion and amortization		25,822		15,233
Proved oil and gas properties, net		180,390		190,979
Unproved oil and gas properties		8,240		5,000
Oil and gas properties, net		188,630		195,979
Property, plant and equipment, other		989		614
Less:  Accumulated depreciation		533		371
Property, plant and equipment, other, net		456		243
Total property, plant and equipment	$	189,086	$	196,222

NOTE 7.  --- LONG TERM NOTE PAYABLE – RELATED PARTY

On June 6, 2011, CPL, a wholly owned subsidiary of the Company, executed a Promissory Note in favor of Allied. Under the terms of the Promissory Note, the Lender agreed to make loans to CPL, from time to time and pursuant to requests by CPL, in an aggregate sum of up to $25.0 million. Interest accrues on outstanding principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum.  CPL may prepay and re-borrow all or a portion of such amount from time to time.  Pursuant to the initial terms of the Promissory Note, the unpaid aggregate outstanding principal amount of all loans, was to mature on June 6, 2013.  Subsequently, in August 2012 the Promissory note was amended to extend the maturity date to October 15, 2013, and then amended again in March 2013 to extend the maturity date to July 15, 2014.  The Company has irrevocably, unconditionally and absolutely guaranteed all of CPL’s obligations under the Promissory Note.   As of December 31, 2012, $0.9 million was outstanding.

NOTE 8. --- OPERATING SEGMENT DATA

The Company manages its operations on a geographical basis.  Historically, the Company reported two operating segments:  Africa and Asia.  In August 2012, the Company sold its principal China operations, which comprised the remaining portion of the Asia segment.  As a result, the Company is reporting Asia operations for all presented periods in discontinued operations and, as such, the financial statement information provided in this report for continuing operations for the years ended December 31, 2012 and 2011 are presented in one reportable segment.

NOTE 9. ---   INCOME TAXES

The Company’s subsidiaries outside the United States did not have any undistributed net earnings at December 31, 2012, due to accumulated net losses.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

Following is a reconciliation of the expected statutory U.S. Federal income tax provision to the actual income tax expense for the respective periods:

	Years Ended December 31,
	2012			2011
	(In thousands)
Net loss attributable to CAMAC Energy Inc. before income tax expense	$	(6,091	)	$	(24,913	)
Expected income tax provision at statutory rate of 35%	$	(2,132	)	$	(8,720	)
Increase (decrease) due to:
Foreign-incorporated subsidiaries		(4,463	)		4,102
Net losses not realizable currently for U.S. tax purposes		6,595			4,618
Total income tax expense	$	-		$	-

The Company records zero net deferred income tax assets and liabilities on the balance sheet on the basis that its overall net deferred income tax asset position is offset by a valuation allowance due to its net losses since inception for both book basis and tax basis and other considerations.

Deferred income tax assets by category are as follows:

	Years Ended December 31,
	2012			2011
	(In thousands)
Tax basis operating loss carryovers	$	20,471		$	16,898
Well workover		7,822			10,737
Other		481			106
		28,774			27,741
Valuation allowance		(28,774	)		(27,741	)
Net deferred income tax assets	$	-		$	-

The Company’s total tax basis loss carryovers at December 31, 2012 were $58,847,000.  Due to the significant change in ownership in 2010, the Company’s future use of its U.S. operating losses may be limited.

Tax years ended December 31, 2008 through 2012 remain open to examination under the applicable statute of limitations in the U.S. and state tax jurisdiction in which the Company files income tax returns.

For the year 2011 in the accompanying consolidated statements of operations, total net losses attributable to CAMAC Energy Inc., include a net charge of $508,000 to income tax expense representing adjustments between the original book basis income tax provision and the Company’s allocated share of the year 2010 Nigeria Petroleum Profits Tax return filed for the OML 120/121 PSC in September 2011. The adjustments recorded were based upon changes deemed more likely than not to be sustained. The Company also has unrecognized tax benefits of $2,435,000 related to the 2010 Nigeria Petroleum Profits Tax return for which the future realization is uncertain at present; accordingly, the tax benefit has been fully offset by a valuation allowance. Further, as part of the above adjustments, the Company has recorded approximately $624,000 in other current assets for excess 2010 Nigeria Petroleum Profits Tax paid into the escrow account of the OML 120/121 PSC.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

NOTE 10. ---  ACCOUNTS PAYABLE AND ACCRUED EXPENSES

As of December 31, 2012, the Company had approximately $15.1 million of approved and unpaid workover invoices related to Oyo Field well #5, and $19.3 million as of December 31, 2011.

Accrued expenses are as follows:

	December 31,		December 31,
	2012		2011
	(In thousands)
Accrued contingent consideration	$	-	$	890
Accrued professional fees		565		474
Accrued payroll and benefits		397		406
Accrued workover costs		538		1,367
Other		1,270		426
Total accrued expenses	$	2,770	$	3,563

NOTE 11. --- STOCK BASED COMPENSATION

Stock Options

Under the Company’s 2009 Equity Incentive Plan, the Company may issue stock, options or units to result in issuance of a maximum aggregate of 12,000,000 shares of Common Stock. Options awarded expire 10 years from date of grant or shorter term as fixed by the Board of Directors.  In 2012, the Company granted a total of 625,485 stock options with vesting periods from 3 years to 5 years.

A summary of stock option activity for the year ended December 31, 2012, is presented below.

	Shares Underlying Options			Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term (Years)
Stock Options
Outstanding at January 1, 2012		5,496,692		$	1.38		4.9
Granted		625,485		$	0.86		4.3
Exercised		(7,000	)	$	0.64
Forfeited		(3,540,192	)	$	1.58
Outstanding as of December 31, 2012		2,574,985		$	0.98		3.8
Expected to vest		2,574,985		$	0.98		3.8
Exercisable at December 31, 2012		729,501		$	1.25		3.6

The total intrinsic values of options outstanding and options exercisable were $0 at December 31, 2012.  The total intrinsic values realized by recipients on options exercised were $2,420 in 2012, and $242,000 in 2011.

The Company recorded compensation expense relative to stock options in 2012 and 2011 of $178,000 and $1,288,000, respectively.

The fair values of stock options used in recording compensation expense are computed using the Black-Scholes option pricing model.  The table below shows the weighted-average amounts for the assumptions used in the model for options awarded in each year under equity incentive plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

	2012			2011
Expected price volatility		120.5	%		103.7	%
Risk free interest rate (U.S. treasury bonds)		0.5	%		0.8	%
Expected annual dividend yield		-			-
Expected option term (years)		3.5			3.1
Grant date fair value per share	$	0.64		$	0.84

Restricted Stock Awards (“RSA”)

In addition to stock options, our 2009 Plan allows for the grant of restricted stock awards, or RSA. We determine the fair value of RSAs based on the market price of our common stock on the date of grant. Compensation cost for RSAs is recognized on a straight-line basis over the vesting or service period and is net of forfeitures.

A summary of restricted stock activity for the year ended December 31, 2012, is presented below.

	Shares			Weighted-Average Grant Date Fair Value
Restricted Stock
Nonvested at January 1, 2012		1,088,627		$	1.13
Granted		909,916		$	0.76
Vested		(514,192	)	$	1.10
Forfeited		(385,000	)	$	1.28
Nonvested as of December 31, 2012		1,099,351		$	0.78

The Company recorded compensation expense relative to RSA’s in 2012 and 2011 of $561,000 and $1,196,000, respectively.

The total grant date fair value of RSA shares that vested during 2012 was approximately $568,000.  As of December 31, 2012, there was approximately $857,000 of total unrecognized compensation cost related to nonvested RSAs, with $725,000, and $132,000 to be recognized during the years ended December 31, 2013 and 2014, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

NOTE 12. --- EARNINGS OR LOSS PER COMMON SHARE

Basic earnings or loss per common share (“EPS”) is computed by dividing net income or loss available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic and diluted EPS for years ended December 31, 2012 and 2011, respectively, were as follows:

	Years ended December 31,
	2012		2011
	(In thousands)
Basic		155,813		154,556
Diluted		155,813		154,556

The number of stock options, warrants issued in stock offerings and nonvested restricted stock excluded from dilutive shares outstanding in the above periods, as these potentially dilutive securities are anti-dilutive because the Company was in a loss position, were as follows:

	Years ended December 31,
	2012		2011
	(In thousands)
Stock options		2		98
Warrants issued in stock offerings		-		6
Nonvested restricted stock awards		327		65

NOTE 13. --- DEFINED CONTRIBUTION PLAN

In 2007 the Company adopted a defined contribution 401(k) Plan (“Plan”) for its U.S. employees.   The Plan provides for Company matching of 200% on up to the first 3% of salary contributed by employees. The Plan includes the option for employee contributions to be made from either pre-tax or after-tax basis income as elected by the employee. Company contributions are immediately vested to the employee.  Under the Plan, the Company’s cash contributions, including third party administration fees, were $130,000 and $121,000 in 2012 and 2011, respectively.  

NOTE 14. --- FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK

Fair Value of Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties.  The carrying amounts of the Company’s financial instruments for cash equivalents, long-term investments, accounts receivable, deposits, advances,  accounts payable, and accrued expenses and long-term debt at floating interest rates, approximate fair value at December 31, 2012 and 2011. The carrying amount for the investment in nonsubsidiary is fair value from a market price.  The recorded amounts for fair value of the Company’s securities, is presented below.

	Years ended December 31,
	2012		2011
	(In thousands)
Available for sale:
Investment in nonsubsidiary	$	-	$	158

Concentration of Credit Risk

The Company is currently not exposed to any concentration of credit risk.

60

CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

NOTE 15. – FAIR VALUE MEASUREMENTS

ASC 820, Fair Value Measurements and Disclosures , defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measurement fair value.

Fair value measurements are classified and disclosed in one of the following categories:

Level 1:  Unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2:  Unadjusted quoted prices for similar assets or liabilities, or unadjusted quoted prices for identical or similar assets or liabilities in markets that are not active, or inputs other than quoted prices that are observable for the asset or liability.

Level 3:  Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or  liability.

Investments in nonsubsidiaries are accounted for in other assets on the consolidated balance sheet.  The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, long-term investments, trade receivables, deposits, long-term advances, accounts payable, accrued expenses and long-term debt at floating interest rates approximate their fair values, principally due to the short-term nature, maturities or nature of interest rates of many of the above listed items.

Assets measured at fair value on a recurring basis – as of December 31:

	2012		Level 1		2011		Level 1
	(In thousands)
Investment in nonsubsidiary	$	-	$	-	$	158	$	158

NOTE 16. --- COMMITMENTS AND CONTINGENCIES

Lease Commitments

We rent office space and miscellaneous office equipment under non-cancelable operating leases.  Office rent expense, net of sublease income, for the years ended December 31, 2012 and 2011 was $539,000 and $544,000, respectively. At December 31, 2012, minimum future rental commitments for operating leases net of sublease income, were a total of $1,850,000 as follows:  $404,000 in 2013, $270,000 in 2014, $277,000 in 2015, $273,000 in 2016, $269,000 in 2017 and $357,000 in 2018 and thereafter.

Contingencies

In June 2011, Abiola Lawal, former Executive Vice President and Chief Financial Officer of the Company, filed a lawsuit in Harris County, Texas District Court against the Company, alleging breach of contract and wrongful termination in connection with his termination from the Company. In September 2011, the Court issued an order staying the proceedings pending arbitration in view of the mandatory arbitration clause in the plaintiff’s employment agreement. In October 2011, the plaintiff issued a written demand for arbitration making the same allegations as the stayed lawsuit. The arbitration hearing was scheduled to commence in late October 2012.   On October 19, 2012, a settlement agreement was reached resolving the matters described above.  The settlement will have no material effect on our consolidated financial position or our net income or loss.

From time to time we may be involved in various legal proceedings and claims in the ordinary course of our business. As of December 31, 2012, and through the filing date of this report, we do not believe the ultimate resolution of such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or our net income or loss.

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - continued

NOTE 17. --- RELATED PARTY TRANSACTIONS

In September 2012, the Company entered into a Technical Services Agreement (the “Agreement”) with Allied, whereby the Company agreed to provide services related to the Oyo Field within OML 120/121.  Within the terms of the Agreement, Allied agreed to pay the Company $150,000 per month.  The Agreement was finalized and executed January 10, 2013

During 2012, the Company made cash severance payments totaling an aggregate of $169,167 to two former executives pursuant to the terms of separation agreements entered into with each former executive.

On June 6, 2011, CPL, a wholly owned subsidiary of the Company, executed a Promissory Note in favor of Allied. Under the terms of the Promissory Note, the Lender agreed to make loans to CPL, from time to time and pursuant to requests by CPL, in an aggregate sum of up to $25.0 million. Interest accrues on outstanding principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum.  CPL may prepay and re-borrow all or a portion of such amount from time to time.  Pursuant to the initial terms of the Promissory Note, the unpaid aggregate outstanding principal amount of all loans, was to mature on June 6, 2013.  Subsequently, in August 2012 the Promissory note was amended to extend the maturity date to October 15, 2013, and then amended again in March 2013 to extend the maturity date to July 15, 2014.  The Company has irrevocably, unconditionally and absolutely guaranteed all of CPL’s obligations under the Promissory Note.   As of December 31, 2012, $0.9 million was outstanding.

Dr. Kase Lawal, the Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is a director of each of CEHL, CAMAC International (Nigeria) Limited (“CINL”), and Allied.  Dr. Lawal also owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CEHL.  As a result, Dr. Lawal may be deemed to have an indirect material interest in the transactions contemplated by the OML 120/121 Agreement.  Chairman Lawal recused himself from participating in the consideration and approval by the Company’s Board of Directors of the OML 120/121 Transaction.

The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates.  The following tables summarize related party transactions and balances for the respective periods.

	December 31, 2012		December 31, 2011
	(In thousands)
CEHL, accounts payable	$	9,783	$	162
CEHL, long-term note payable	$	872	$	6,000
	Years Ended December 31,
		2012		2011
	(In thousands)
CEHL, operating expenses, net	$	81	$	3,243
CEHL, interest on long-term note payable	$	122	$	120

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CAMAC ENERGY INC.

SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

The unaudited supplemental information on oil and gas exploration and production activities for 2012 and 2011 has been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932,  Extractive Activities—Oil and Gas.  Disclosures by geographic area include Africa and the United States.

Estimated Net Proved Crude Oil Reserves

The following estimates of the net proved crude oil reserves in Africa 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.

	Crude Oil
	(MBbls)
	Africa			Total
December 31, 2010		5,288			5,288
Revisions		(2,288	)		(2,288	)
Improved recovery		-			-
Purchases		-			-
Extensions and discoveries		-			-
Sales of minerals in place		-			-
Production		(337	)		(337	)
December 31, 2011		2,663			2,663
Revisions		582			582
Improved recovery		-			-
Purchases		-			-
Extensions and discoveries		-			-
Sales of minerals in place		-			-
Production		(147	)		(147	)
December 31, 2012		3,098			3,098
Developed reserves
December 31, 2010		387			387
December 31, 2011		92			92
December 31, 2012		55			55
Undeveloped reserves
December 31, 2010		4,901			4,901
December 31, 2011		2,571			2,571
December 31, 2012		3,043			3,043

Capitalized Costs

The Company follows the successful efforts method of accounting for capitalization of costs of oil and gas producing activities.  Capitalized costs include the cost of properties, equipment, and facilities for oil and gas producing activities. Capitalized costs for proved properties include costs for oil and gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. Amounts below include only activities classified as exploration and producing.

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CAMAC ENERGY INC.

SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

(In thousands)	Africa		Total
As of December 31, 2012
Proved properties	$	206,212	$	206,212
Unproved properties		8,240		8,240
Total gross		214,452		214,452
Less:  Accumulated depreciation, depletion and amortization		25,822		25,822
Net capitalized costs	$	188,630	$	188,630
As of December 31, 2011
Proved properties	$	206,212	$	206,212
Unproved properties		5,000		5,000
Total gross		211,212		211,212
Less:  Accumulated depreciation, depletion and amortization		15,233		15,233
Net capitalized costs	$	195,979	$	195,979

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds.  Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.  Costs associated with corporate activities are not included.

(In thousands)	Africa		United States		Total
Year ended December 31, 2012
Proved property acquisition	$	-	$	-	$	-
Unproved property acquisition		3,240		-		3,240
Exploration		1,775		1,461		3,236
Development		-		-		-
Total costs incurred	$	5,015	$	1,461	$	6,476
Year ended December 31, 2011
Proved property acquisition	$	-	$	-	$	-
Unproved property acquisition		5,000		-		5,000
Exploration		206		684		890
Development		-		-		-
Total costs incurred	$	5,206	$	684	$	5,890

64

CAMAC ENERGY INC.

SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

Results of Continuing Operations

Results of continuing operations for producing activities consist of all activities within the oil and gas exploration and production operations.

(In thousands)	Africa			United States			Total
Year ended December 31, 2012
Revenues	$	16,624		$	-		$	16,624
Production costs		(260	)		(7	)		(267	)
Exploratory expenses		(1,775	)		(1,461	)		(3,236	)
Depreciation, depletion and amortization		(10,595	)		-			(10,595	)
Other expenses		(59	)		-			(59	)
Results of operations before income taxes		3,935			(1,468	)		2,467
Income tax expense		-			-			-
Results of continuing operations	$	3,935		$	(1,468	)	$	2,467
Year ended December 31, 2011
Revenues	$	37,922		$	-		$	37,922
Production costs		(1,905	)		-			(1,905	)
Exploration expenses		(206	)		(684	)		(890	)
Depreciation, depletion and amortization		(13,316	)		-			(13,316	)
Other expenses		(28,977	)		-			(28,977	)
Results of operations before income taxes		(6,482	)		(684	)		(7,166	)
Income tax expense		-			-			-
Results of continuing operations	$	(6,482	)	$	(684	)	$	(7,166	)

Standardized Measure of Discounted Future Net Cash Flows

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, 2012) 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, 2012 and 2011, were $112.77 and $112.26 per barrel of crude oil, respectively, including differentials.  Amounts below for production sold and production costs exclude royalties.

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CAMAC ENERGY INC.

SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

(In thousands)	Africa			Total
As of December 31, 2012
Future cash inflows from production sold	$	349,345		$	349,345
Future production costs		(180,612	)		(180,612	)
Future development costs		(58,800	)		(58,800	)
Future income taxes		(19,886	)		(19,886	)
Future net cash flows before discount		90,047			90,047
Discount at 10% annual rate		(24,335	)		(24,335	)
Standardized measure of discounted future cash flows	$	65,712		$	65,712
As of December 31, 2011
Future cash inflows from production sold	$	298,936		$	298,936
Future production costs		(140,104	)		(140,104	)
Future development costs		(62,308	)		(62,308	)
Future income taxes		(16,212	)		(16,212	)
Future net cash flows before discount		80,312			80,312
Discount at 10% annual rate		(18,625	)		(18,625	)
Standardized measure of discounted future cash flows	$	61,687		$	61,687

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CAMAC ENERGY INC.

SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

Change in Standardized Measure of Discounted Future Net Cash Flows

The sources of change are explained below, discounted at a 10% annual rate.

(In thousands)	Africa			Total
Standardized measure, January 1, 2012	$	61,687		$	61,687
Sales/production net of production costs		(16,357	)		(16,357	)
Development costs incurred		-			-
Purchases of reserves		-			-
Sales of reserves		-			-
Net change in sale prices and production costs on future production		(40,435	)		(40,435	)
Changes in estimated future development costs		8,433			8,434
Extensions, discoveries and improved recovery		-			-
Revisions of previous quantity estimates		47,662			47,662
Accretion of discount		5,717			5,717
Net change in income tax		(995	)		(995	)
Standardized measure, December 31, 2012	$	65,712		$	65,712
Standardized measure, January 1, 2011		95,696			95,696
Sales/production net of production costs		(35,617	)		(35,617	)
Development costs incurred		-			-
Purchases of reserves		-			-
Sales of reserves		-			-
Net change in sale prices and production costs on future production		136,097			136,097
Changes in estimated future development costs		(9,989	)		(9,989	)
Extensions, discoveries and improved recovery		-			-
Revisions of previous quantity estimates		(139,203	)		(139,203	)
Accretion of discount		10,417			10,417
Net change in income tax		4,286			4,286
Standardized measure, December 31, 2011	$	61,687		$	61,687

	Africa
Sales revenue per barrel of crude oil:
2012	$	112.60
2011	$	112.91
2010	$	85.16
Production costs per barrel of net crude oil production:
2012	$	6.34
2011	$	8.61
2010	$	34.54

67