Erin Energy Corp. - FORM 10-K

Attached files

file	filename
EX-23.2 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Erin Energy Corp.	cak_ex232.htm
EX-20.1 - SUBSIDIARIES OF THE COMPANY - Erin Energy Corp.	cak_ex211.htm
EX-32.1 - CERTIFICATION - Erin Energy Corp.	cak_ex321.htm
EX-32.2 - CERTIFICATION - Erin Energy Corp.	cak_ex322.htm
EX-31.2 - CERTIFICATION - Erin Energy Corp.	cak_ex312.htm
EX-31.1 - CERTIFICATION - Erin Energy Corp.	cak_ex311.htm
EX-99.1 - Erin Energy Corp.	cak_ex991.htm
EX-23.1 - CONSENT OF RBSM LLP - Erin Energy Corp.	cak_ex231.htm
EX-1.37 - AMENDED AND RESTATED EMPLOYMENT AGREEMENT - Erin Energy Corp.	cak_ex1037.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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

For the fiscal year ended December 31, 2010

¨ 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)

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

1330 Post Oak Blvd., Suite 2575, Houston, TX 77056

(Address of Principal Executive Office) (Zip Code)

(713) 797-2940

(Registrant’s telephone number, including area code)

———————

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

None

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

Common Stock, $0.001 par value.

———————

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 ¨ 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. ¨

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”, “non-accelerated filer” and ”smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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 equity held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2010) was approximately $225,191,980 (based on $3.73 per share, the last price of the common stock as reported on the NYSE Amex on such date). For purposes of the foregoing calculation only, all directors, executive officers and 10% beneficial owners have been deemed affiliates. As of March 7, 2011, there were 153,773,599 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 June 24, 2011 are incorporated by reference in Part III of this report.

CAMAC Energy Inc.

(Formerly Pacific Asia Petroleum, Inc.)

FORM 10-K

TABLE OF CONTENTS

		Page

	PART I

Cautionary Statement Relevant to Forward-Looking Information
Certain Defined Terms
Item 1.	Description of Business		4
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		32
Item 2.	Properties		32
Item 3.	Legal Proceedings		32
Item 4.	Removed and Reserved		32
	PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		33
Item 6.	Selected Financial Data		37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		52
Item 8.	Financial Statements and Supplemental Data		53
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		87
Item 9A.	Controls and Procedures		87
Item 9B.	Other Information		89
	PART III

Item 10.	Directors, Executive Officers and Corporate Governance		90
Item 11.	Executive Compensation		90
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		90
Item 13.	Certain Relationships and Related Transactions, and Director Independence		90
Item 14.	Principal Accountant Fees and Services		90
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		91
	Signatures

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” and “Description of Business,” 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. (formerly Pacific Asia Petroleum, Inc. ) and its subsidiaries and joint-ventures, (i) Pacific Asia Petroleum, Limited, (ii) Inner Mongolia Production Company (HK) Limited, (iii) Pacific Asia Petroleum (HK) Limited, (iv) Inner Mongolia Sunrise Petroleum Co. Ltd., (v) Pacific Asia Petroleum Energy Limited, (vi) Beijing Dong Fang Ya Zhou Petroleum Technology Service Company Limited, and (vii) CAMAC Petroleum Limited (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 in 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 operations 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 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.

CERTAIN DEFINED TERMS

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, including Pacific Asia Petroleum, Limited (“PAPL”), Pacific Asia Petroleum Energy Limited (“PAPE”), Inner Mongolia Production Company (HK) Limited (“IMPCO HK”), Pacific Asia Petroleum (HK) Limited (“PAP HK”), Inner Mongolia Sunrise Petroleum Co. Ltd. (“IMPCO Sunrise”), Beijing Dong Fang Ya Zhou Petroleum Technology Service Company Limited (“Dong Fang”), and CAMAC Petroleum Limited (“CPL”) and collectively, the “Company”. References to "CAMAC" as a corporate entity refer to CAMAC Energy Inc. (formerly Pacific Asia Petroleum, Inc.) prior to the mergers of Inner Mongolia Production Company LLC ("IMPCO") and Advanced Drilling Services, LLC ("ADS") into wholly-owned subsidiaries of CAMAC Energy Inc. However, historical financial results presented herein are those of IMPCO from inception on August 25, 2005 to May 6, 2007, and the consolidated entity CAMAC Energy Inc. from May 7, 2007 forward, which is considered to be the continuation of IMPCO as CAMAC Energy Inc. for accounting purposes.

PART I

ITEM 1. DESCRIPTION OF BUSINESS

General

CAMAC is a publicly traded company which seeks to develop new energy ventures outside the U.S., directly and through joint ventures and other partnerships 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 and the People’s Republic of China. The second quarter 2010 was our first reporting period out of the development stage company basis. Our shares are traded on the on the NYSE Amex under the symbol “CAK”.

Our executive offices are located at 1330 Post Oak Boulevard, Suite 2575, Houston, Texas 77056 and our telephone number is (713) 797-2940.

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 2575, Houston TX 77056, Attention: Investor Relations.

Executive Summary of 2010

Oyo Field Production Sharing Contract Interest

On November 18, 2009, the Company entered into the Purchase and Sale Agreement with CAMAC Energy Holdings Limited and certain of its affiliates (collectively “CEHL”) pursuant to which the Company agreed to acquire all of CEHL’s interest in a Production Sharing Contract (the “OML 120/121 PSC”) with respect to the oilfield asset known as the Oyo Field (the “Oyo Contract Rights”) and agreed to the related transactions contemplated thereby, including the election of certain directors of the Company. The OML 120/121 PSC governing the Oyo Field is by and among Allied Energy Plc. (“Allied”), an affiliate of CEHL, CAMAC International (Nigeria) Limited (“CINL”), an affiliate of CEHL, and Nigerian Agip Exploration Limited (“NAE”).

As consideration for the Oyo Contract Rights, on April 7, 2010 the Company paid CAMAC Energy Holdings Limited $32 million in cash consideration (the “Cash Consideration”) and issued to CAMAC Energy Holdings Limited 89,467,120 shares of Company Common Stock, par value $0.001, representing approximately 62.74% of the Company’s issued and outstanding Common Stock at closing (the “Consideration Shares”). In addition, if certain issued and outstanding warrants and options exercisable for an aggregate of 7,991,948 shares of Company Common Stock were exercised following the closing, the Company was obligated to issue up to an additional 13,457,188 Consideration Shares to CAMAC Energy Holdings Limited to maintain CAMAC Energy Holdings Limited’s approximately 62.74% interest in the Company. As of December 31, 2010 the maximum potential additional Consideration Shares issuable had been reduced to 7,484,983 due to expiration of certain unexercised warrants. As additional Cash Consideration, the Company agreed to pay CAMAC Energy Holdings Limited $6.84 million on the earlier of sufficient receipt of oil proceeds from the Oyo Field or six months from the closing date. This amount was paid in July 2010.

In February and March 2010, the Company raised $37.5 million in two registered direct offerings (described below), $32 million of which proceeds were used by the Company to satisfy the cash purchase price requirement under the Purchase and Sale Agreement, as amended.

Registered Direct Offerings of Securities

In year 2010, the Company completed three registered direct offerings for combined sales of Company Common Stock and warrants, under which the following securities were issued:

February 16, 2010:

-5,000,000 shares of Common Stock at $4.00 per share – aggregate proceeds of $20 million

-Warrants to purchase 2,000,000 shares of Common Stock at $4.50 per share, expiring August 2013

-Warrants to purchase 2,000,000 shares of Common Stock at $4.00 per share, expired November 2010

-Placement agent warrants to purchase 150,000 shares of Common Stock at $5.00 per share, expiring February 2015

March 5, 2010:

-4,146,922 shares of Common Stock at $4.22 per share – aggregate proceeds of $17.5 million

-Warrants to purchase 1,658,769 shares of Common Stock at $4.50 per share, expiring September 2013

-Warrants to purchase 1,658,769 shares of Common Stock at $4.12 per share, expired December 2010

-Placement agent warrants to purchase 124,408 shares of Common Stock at $5.275 per share, expiring February 2015

December 28, 2010:

-9,319,102 shares of Common Stock at $2.20 per share – aggregate proceeds of $20.5 million

-Warrants to purchase 4,659,551 shares of Common Stock at $2.20 per share, increased to $2.62 per share 31 days after the closing, expiring December 2015

-Placement agent warrants to purchase 279,573 shares of Common Stock at $2.75 per share, expiring February 2015

Net proceeds from the February and March 2010 offerings have been used by the Company for working capital purposes, and to fund the Company’s acquisition from CEHL of the Oyo Contract Rights in April 2010. Net proceeds from the December 2010 offering will be used to fund a portion of the cost of the workover on well #5 in the Oyo Field and for working capital purposes.

OML 120/121 Transaction

On December 13, 2010, the Company entered into a Purchase and Continuation Agreement (the “Purchase Agreement”) with CEHL, superseding earlier related agreements. Pursuant to the Purchase Agreement, the Company agreed to acquire CEHL’s full remaining interest (the “OML 120/121 Transaction”) in the OML 120/121 PSC (the “Non-Oyo Contract Rights”). In April 2010 the Company had acquired from CEHL the Oyo Contract Rights in the OML 120/121 PSC. The OML 120/121 Transaction closed on February 15, 2011. Upon consummation of the acquisition of the Non-Oyo Contract Rights under the Purchase Agreement, the Company acquired CEHL’s full interest in the OML 120/121 PSC.

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 upon the closing of the OML 120/121 Transaction on February 15, 2011. The Company has the option to elect to retain the Non-Oyo Contract Rights upon payment of additional consideration to Allied as follows:

a.	First Milestone: Upon commencement of drilling of the first well outside of the Oyo Field under the PSC, the Company may elect to retain the Non-Oyo Contract Rights upon payment to CEHL of $5 million (either in cash, or at Allied’s option, in shares);

Second Milestone: Upon discovery of hydrocarbons outside of the Oyo Field under the PSC in sufficient quantities to warrant the commercial development thereof, the Company may elect to retain the Non-Oyo Contract Rights upon payment to CEHL of $5 million (either in cash, or at Allied’s option, in shares);

Third Milestone: Upon the approval by the Management Committee (as defined in the PSC) of a Field Development Plan with respect to the development of non-Oyo Field areas under the PSC, as approved by the Company, the Company may elect to retain the Non-Oyo Contract Rights upon payment to Allied of $20 million (either in cash, or at Allied’s option, in shares); and

Fourth Milestone: Upon commencement of commercial hydrocarbon production outside of the Oyo Field under the PSC, the Company may elect to retain the Non-Oyo Contract Rights (with no additional milestones or consideration required thereafter following payment in full of the following consideration) upon payment to Allied, at Allied’s option of (i) $25 million in shares, or (ii) $25 million in cash through payment of up to 50% of the Company’s net cash flows received from non-Oyo Field production under the PSC.

If any of the above 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.

The Purchase Agreement contained the following conditions to the closing of the Transaction: (i) CPL, CAMAC International (Nigeria) Limited (“CINL”), Allied, and Nigerian Agip Exploration Limited (“NAE”) must enter into a Novation Agreement in a form satisfactory to the Company and CEHL and that contains a waiver by NAE of the enforcement of Section 8.1(e) of the OML 120/121 PSC (providing for the continued waiver by NAE of its entitlement to “profit oil” in favor of Allied), and that notwithstanding anything to the contrary contained in the OML 120/121 PSC, the profit sharing allocation set forth in the OML 120/121 PSC shall be maintained after the consummation of the OML 120/121 Transaction; (ii) the Company, and CEHL must enter into a registration rights agreement with respect to any shares issued by the Company to Allied at its election as consideration upon the occurrence of any of the above-described milestone events, in a form satisfactory to the Company and CEHL; and (iii) the Oyo Field Agreement, dated April 7, 2010, by and among the Company, CEHL and Allied, must be amended in order to remove certain indemnities with respect to Non-Oyo Operating Costs (as defined therein). In addition, CEHL must deliver the certain data and certain equipment to the Company in as-is condition. The Company agreed to limited waivers of certain of these closing conditions under the Limited Waiver Agreement. See Note 20 to our consolidated financial statements for more information regarding the Limited Waiver Agreement.

Dr. Kase Lawal, the Company’s Non-Executive Chairman and member of the Board of Directors, is a director of each of CEHL, 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 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.

Oyo Field Well #5 Workover

During December 2010 and January 2011, the Company incurred approximately $55 million in total costs relative to the workover to reduce gas production rising from the #5 well in the Oyo Field with the objective of increasing crude oil production from this well. By joint agreement with Allied, the Company will pay for the workover. To the extent the Company funds these costs, it will be 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. We expect to recover these costs as revenue in 2011and 2012.

Operations

Africa - OML 120/121 Production Sharing Contract

On December 15, 2009, NAE, a subsidiary of Italy's ENI SpA, and CEHL announced that they had commenced production of the Oyo Field. The Oyo Field has been producing from two subsea wells in a water depth of greater than 300 meters, which are connected to the Armada Perdana Floating Production Storage and Offloading (“FPSO”) vessel. The FPSO has a treatment capacity of 40,000 barrels of liquids per day, with gas treatment and re-injection facilities, and is capable of storing up to one million barrels of crude oil. The first lifting (sale) of crude oil was in February 2010. The associated gas has been largely re-injected into the Oyo Field reservoir by a third well, to minimize flaring and to maximize oil recovery. During December 2010 and January 2011, the Company incurred approximately $55 million in costs relative to the workover to reduce gas production rising from the #5 well in the Oyo Field with the objective of increasing crude oil production from this well. By joint agreement with Allied, the Company will pay for the workover. We expect to recover these costs as revenue in 2011 and 2012.

On July 22, 2005, a Production Sharing Contract (the “OML 120/121 PSC”) was signed among CEHL affiliates (including Allied) and NAE. Pursuant to the OML 120/121 PSC, NAE assumed the rights and obligations as the Operating Contractor to the petroleum operations in the Oyo field and was assigned an undivided 40% interest, with Allied retaining an undivided 60% interest. However, these percentages are not indicative of the actual allocation of proceeds from production of oil or other hydrocarbons under the Oyo Contract Rights and the recently acquired 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. The parties to the OML 120 /121 PSC are represented by the above chart.

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. The allocation procedure is shown in the chart below. The Company receives the share allocable to Allied for the Oyo Contract Rights and will receive Allied’s share for the Non-Oyo Contract Rights. The complete Production Sharing Contract was filed as Annex E to the Company’s proxy filed with the SEC on March 19, 2010.

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.

Nigeria Oil Industry

Nigeria is classified as an emerging market with its abundant supply of resources, developing financial, legal, communications, transport sectors and stock exchange (the Nigerian Stock Exchange), which is the second largest in Africa. Nigeria was ranked 33rd in the world in terms of Gross Domestic Product as of 2009. Nigeria is the United States' largest trading partner in sub-Saharan Africa and supplies a fifth of the U.S.’s imported oil . It has the sixth-largest trade surplus with the U.S. of any country worldwide. Nigeria is currently the 42nd-largest export market for U.S. goods and the 14th-largest exporter of goods to the U.S. The U.S. is the country's largest foreign investor. The bulk of economic activity is centered in four main cities: Lagos, Kaduna, Port Harcourt, and Abuja. Beyond these four economic centers, development is marginal.

According to the Oil and Gas Journal, Nigeria had an estimated 37.2 billion barrels of proven oil reserves as of January 2010. The majority of reserves are found along the country’s Niger River Delta and offshore in the Bight of Benin, the Gulf of Guinea and the Bight of Bonny. Current exploration activities are mostly focused in the deep and ultra-deep offshore with some activities in the Chad basin, located in northeast 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.

Nigeria is an important oil supplier to the United States. A significant portion of the country’s oil production is exported to the United States and the light, sweet quality crude is a preferred gasoline feedstock. Consequently, disruptions to Nigerian oil production impacts trading patterns and refinery operations in North America and often affect world oil market prices.

In 2009, total oil production in Nigeria was slightly over 2.2 million barrels of oil per day (“bbl/d”), making it the largest oil producer in Africa. Crude oil production averaged 1.8 million bbl/d for the year. Recent offshore oil developments combined with the restart of some shut-in onshore production have boosted crude production to an average of 2.35 million bbl/d for the second quarter of 2010.

Asia - Zijinshan Production Sharing Contract

In 2007, we entered into a production sharing contract with China United Coalbed Methane Co., Ltd., (“CUCBM”) for exclusive rights to a large contract area located in the Shanxi Province of China (the “CUCBM Contract Area”), for the exploitation of gas resources (the “Zijinshan PSC”). CUCBM is owned 50/50 by China Coal Energy Group and China National Petroleum Corporation (“CNPC” and “PetroChina”). In 2008, PetroChina withdrew from the CUCBM partnership. As a result, 50% of the assets, including Zijinshan PSC, have become the asset of PetroChina. The change of ownership of these assets is subject to Chinese Government approval. The approval was formally granted in December 2010. Currently, a modification to the Zijinshan PSC has been proposed to formalize the change of partnership from CUCBM to PetroChina. Upon signing of the modification agreement, the Zijinshan PSC will be administrated by PetroChina Coal Bed Methane Corporation which is a wholly owned subsidiary of PetroChina (“PCCBM”). The Zijinshan PSC covers an area of approximately 175,000 acres (“Zijinshan Block”). The Zijinshan PSC has a term of 30 years and was approved in 2008 by the Ministry of Commerce of China.The Zijinshan PSC provides, among other things, that PAPL, following approval of the Zijinshan PSC by the Ministry of Commerce of China, has a minimum commitment for the first three years to drill three exploration wells and to carry out 50 km of 2-D seismic data acquisition and in the fourth and fifth years to drill four pilot development wells (in each case subject to PAPL’s right to terminate the Zijinshan PSC). That five year period constitutes the exploration period, which is subject to extension. After the exploration period, but before commencement of the development and production period, PCCBM will have the right to acquire a 40% participating interest and work jointly and pay its participating share of costs to develop and produce gas. The Zijinshan PSC provides for cost recovery and profit sharing from production under a specified formula after commencement of production.

The Zijinshan PSC area is in close proximity to the major West-East and the Ordos-Beijing gas pipelines which link the gas reserves in China’s western provinces to the markets of Beijing and the Yangtze River Delta, including Shanghai.

During 2009, the Company completed seismic data acquisition operations on the Zijinshan Block and spent approximately $1.5 million to shoot 162 kilometers of seismic under the work program. Based on the seismic interpretation, four potential well locations were identified. A regional environmental impact assessment study has also been completed. Following completion of a site-specific environmental impact study, the Company spudded well ZJS 001 on September 30, 2009. This well intersected 4/5 coal seams in the Shanxi formation and 8/9 coal seams in the Taiyuan formation as anticipated. The well reached total depth in mid-November 2009. Core samples have undergone laboratory testing, including tests for gas content, gas saturation and coal characteristics. Based on the results of these tests, the Company agreed to a planned 2010 work program to include further technical studies related to the CUCBM Contract Area and drilling at least two additional wells there. Drilling commenced on well ZJS 002 in August and was completed on the downthrown block in November 2010. Mud logs during drilling confirmed the presence of gas at several intervals ranging in depth from 1,471 to 1,742 meters. However, no flow tests were conducted due to the deteriorated hole condition, and therefore all exploratory costs were expensed.

Further drilling and analysis will be necessary to determine whether the Zijinshan Block contains sufficient quantities of gas that are commercially recoverable under existing economic and operating conditions. Drilling of well ZJS 003 on the larger upthrown block is now planned for the first half of 2011, with an additional two wells planned for later in 2011. There have been no proved reserves assigned to the Zijinshan PSC to date.

Enhanced Oil Recovery and Production (“EORP”)

In May and June 2009, the Company entered into certain agreements with Mr. Li Xiangdong (“LXD”) and Mr. Ho Chi Kong (“HCK”), pursuant to which the parties in September 2009 formed a Chinese joint venture company, Dong Fang. Dong Fang is 75.5% owned by PAPE and 24.5% owned by LXD, and LXD agreed to assign certain pending patent rights related to chemical enhanced oil recovery thereto. PAPE is 70% owned by the Company and 30% owned by Best Source Group Holdings Limited, a company designated by HCK for his interest.

In late 2009, the Company commenced limited EORP operations in the Liaoning Province through the treatment of three pilot test wells in the Liaohe Oilfield utilizing the chemical treatment technology acquired by Dong Fang. Results of these efforts, which resulted in incremental production, have been evaluated by the Company.

In the fourth quarter of 2010, the Company decided it would explore all alternatives including the potential sale of the EORP business due to the lack of progress in establishing a significant business and the likelihood that further progress will be difficult to achieve under the existing local operating environment. The assets of the EORP operations are not material in terms of the Company’s total assets and the minority interest is reflected as a noncontrolling interest in our consolidated financial statements. All active operations have ceased, including consideration of the Chifeng agreement area in Inner Mongolia for a possible EORP project. In February 2011, the Board of Directors of Dong Fang approved dissolution of Dong Fang, the operating company.

China Oil and Gas Industry

China is the world's most populous country and has a rapidly growing economy. China is also the world’s second largest petroleum consumer. According to the Energy Information Agency (“EIA”), in 2009, Chinese consumption for petroleum reached 8.2 million bbl/d, with only 4.0 million bbl/d of total oil production, making China a net importer of 4.2 million bbl/d. Since 2000, China’s oil imports tripled, growing from 1.4 million bbl/d to 4.2 million bbl/d in 2009.

Natural gas represents a particularly under-utilized energy source in China, supplying only 3% of the country’s energy needs (EIA), compared with 23% globally and in the U.S. We believe that its low emissions, combined with the low cost and high efficiency of gas turbines, make gas an attractive fuel for meeting China’s future electric power demand. This will be particularly important in light of China's newly-announced goal of reducing the carbon-intensity of its economy by 40-45% by 2020, compared to 2005, in light of the much lower emissions from gas-fired power plants relative to those burning coal. The Chinese government has indicated that it would like to expand gas use significantly. China’s domestic natural gas production increased to 2.9 trillion cubic feet in 2009 (EIA) and is planned to double to 5.7 trillion cubic feet by 2015 (China Daily, quoting an official of the Ministry of Land and Resources).

The government of China has taken a number of steps to encourage the exploitation of oil and gas within its own borders to meet the growing demand for oil and to try to reduce its dependency on foreign oil. Notably, the government has reduced complicated restrictions on foreign ownership of oil exploitation projects and has passed legislation encouraging foreign investment and exploitation of oil and gas. While the barriers to entry for foreign entities to engage in the development of oil and gas resources in China have recently eased, we believe that many small companies still face significant hurdles due to their lack of experience in the Chinese petroleum industry. Development requires specialized grants and permits, experience with operating in China and dealing with challenging cultural and political environments in remote regions and the ability to manage projects efficiently during times of resource shortages. The Company hopes to take advantage of the energy development opportunities that exist in China today by leveraging its management team’s prior exploration experiences in China and existing relationships with oil industry executives and government officials in China. In addition, we believe that members of the Company’s production team have the hands-on experience with projects in Asia that we believe is essential to any successful petroleum project in China.

Reserves

The information included in this Annual Report on Form 10-K about our proved reserves represents evaluations prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants (“NSAI”). NSAI has prepared evaluations on 100 percent of our proved reserves on a valuation basis, and the estimates of proved crude oil reserves attributable to our net interests in oil and gas properties as of December 31, 2010. The scope and results of NSAI’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, see “Item 8. - Financial Statements and Supplemental Data –Supplemental Data on Oil and Gas Exploration and Producing Activities.”

Internal Controls for Reserve Estimation

The reserve estimates prepared by NSAI are reviewed and approved by our contracted reservoir engineer and management. The process performed by NSAI to prepare reserve amounts included the estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue. NSAI also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance. In the conduct of their preparation of the reserve estimates, NSAI 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, NSAI 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, 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 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 contracted reservoir engineer Mr. Babatunde Olusegun Omidele is primarily responsible for overseeing the preparation of our internal reserve estimates and for the coordination of the third-party reserve report provided by NSAI. Mr. Babatunde Olusegun Omidele has over 28 years of experience and is a graduate of University of Ibadan, Nigeria with a Bachelor of Science degree and from University of Houston, Texas with a Master of Science in Petroleum Engineering. He is a member of the Society of Petroleum Engineers. Mr. Babatunde Olusegun Omidele is Senior Vice President, Exploration & Production with Allied Energy Corp.

The reserves estimates shown herein have been independently prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Connor Riseden and Mr. Patrick Higgs. Mr. Riseden has been practicing consulting petroleum engineering at NSAI since 2006. Mr. Riseden is a Registered Professional Engineer in the State of Texas (License No. 100566) and has over nine years of practical experience in petroleum engineering, with over four years experience in the estimation and evaluation of reserves. Mr. Higgs has been practicing consulting petroleum geology at NSAI since 1996. Mr. Higgs is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 985) and has over 34 years of practical experience in petroleum geosciences, with over 14 years experience in the estimation and evaluation of reserves. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Summary of Crude Oil Reserves at December 31, 2010

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

Crude Oil Reserves as of December 31, 2010

	Crude Oil (MBbls)		PV-10 (in thousands)(1)
Proved
Developed		387
Undeveloped		4,901
Total Proved		5,288	$	95,696

(1)

PV-10 reflects the present value of our estimated future net revenues 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, 2010) without giving effect to non-property related expenses such as DD&A expense and discounted at 10 percent per year before income taxes. The average of the first-day-of-the-month commodity prices during the 12-month period ending on December 31, 2010 was $79.21 per barrel of oil, including differentials.

Development of Proved Undeveloped Reserves

None of our proved undeveloped reserves currently have remained undeveloped for more than five years from the date of initial recognition as proved undeveloped.

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, 2010. In 2010, our share of average daily net production was 396 barrels per day (excluding royalty), average sales price was $85.16 per barrel and production cost of barrels sold was $34.54 per barrel. The Company had no production during 2009 and 2008 in Nigeria.

Drilling Activity

During 2010, the Company did not drill any development or exploratory wells in the Oyo Field, Nigeria. In China, the Company drilled one (gross and net) exploratory well in both 2010 and 2009, which were both determined to be dry wells.

Present Activities

The Company intends to participate in drilling a development well in the Oyo Field, Nigeria during 2011. In China, drilling of an exploratory well is planned in the first half of 2011, with an additional two wells planned for the second half of 2011 in the Zijinshan Block.

Delivery Commitments

As of December 31, 2010, the Company had no delivery commitments.

Productive Wells

At December 31, 2010, the Company had two gross productive wells in Nigeria. The number of net productive wells (net economic interest) in Nigeria at that date under our Production Sharing Contract is less than one net well; this is affected by our participation percentage in funding of expenditures.

Acreage

Interests in developed and undeveloped acreage follow.

	December 31, 2010
	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
China		-		-		175,000		175,000		175,000		175,000
Nigeria		8,600		5,200		-		-		8,600		5,200
Total		8,600		5,200		175,000		175,000		183,600		180,200

The Company has no acreage on which leases are scheduled to expire within the three years after December 31, 2010.

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 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.

Employees

At December 31, 2010 the Company had 13 full-time employees in the United States, 14 full-time employees in China, and two part-time employees in China. There were no employees in Nigeria as of December 31, 2010 as the Company’s interests there were being handled through a contracted technical services agreement with an affiliate company.

In order for us to attract and retain quality personnel, we will have to offer competitive salaries to future employees. During 2011, 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. 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. In the case of Nigeria, the additional personnel cost will be partially offset by a decrease in the contracted technical services charges that we currently incur.

Intellectual Property

The Company through its subsidiary, Dong Fang, owns Patent Application Rights with respect to six patents pending before the PRC Patent Administration which covering certain enhanced oil recovery technologies to be used in connection with EORP operations. As mentioned above, our Board of Directors has approved the dissolution of Dong Fang.

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 we acquired in April 2010 (the Oyo Contract Rights) and the Non-Oyo Contract Rights acquired in February 2011. We have 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 until recently 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 and, as a result of this acquisition, we ceased reporting as a development stage company and now we are an operating company generating significant 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 prior to the generation of significant revenue. 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, in particular with major Chinese government-owned oil and gas companies as joint venture partners. 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.

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 Byron A. Dunn, the Company’s Chief Executive Officer and Abiola L. Lawal, its Chief Financial Officer, has the right to terminate his employment at any time without penalty under his employment agreement. The unexpected loss of the services of either Mr. Dunn or Mr. Lawal, or any other key employee, 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 expects to utilize a term credit facility of $25 million from an affiliated company to meet a substantial portion of its cash obligations for workover expenses on Oyo Field well #5. The credit facility provides for an annual interest rate based on 30 day Libor plus two percentage points with all amounts due and payable within 24 months from the closing date, expected in March 2011. The Company has no other current arrangements with respect to additional source 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.

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 (i) the Oyo and Non-Oyo Contract Rights and (ii) Zijinshan PSC. The Company has not entered into definitive agreements with respect to any other ventures. 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, 2010 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.

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 and through the first quarter of 2011 may rely substantially on a services agreement with an affiliate of CEHL.The objectives of the affiliate may not be in line with the Company’s objectives and could result in the disruption of our operations and prevent us from generating meaningful revenue.

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. In connection with the acquisition of the Oyo Contract rights we entered into a services agreement with Allied, pursuant to which Allied agreed to provide services relating to the Oyo Field consistent with its prior performance of those duties. If Allied fails to perform the services as agreed, or if we fail to secure similar agreements in connection with future assets before we improve and expand our operational, management and financial systems and staff, the profitability and results of operations could be adversely affected and future growth may be impeded. We may need to hire additional personnel in certain operational and other areas during 2011 and future years. The services agreement is expected to be terminated by March 31, 2011.

We will depend on NAE as the operator 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.

As operator under the OML 120/121 PSC, NAE 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 NAE does not properly and efficiently manage operational and production matters, or becomes unable or unwilling to continue acting as the operating contractor 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 Nigeria and China 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 Nigeria and China 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.

The Company is exposed to concentration of credit risk, which may result in losses in the future.

The Company is exposed to concentration of credit risk with respect to cash, cash equivalents, short-term investments, long-term investments, and long-term advances. At December 31, 2010, 68% ($19.6 million) of the Company’s total cash and cash equivalents was on deposit at JP Morgan Chase in the U.S. At December 31, 2009, 65% ($1,291,000) of the Company’s total cash was on deposit at HSBC in China and Hong Kong. Also at December 31, 2009, 64% ($1,029,000) of the Company’s total cash equivalents was invested in a single money market fund in the U.S.

Our business partner, CEHL, is a related party, and our non-executive chairman 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. Dr. Kase Lawal, the Company’s Non-Executive Chairman and member of the Board of Directors, is a director of CAMAC Energy Holdings Limited as well as CINL and Allied, also entities constituting CEHL. 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 and the OML 120/121 Transaction. 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, CAMAC Energy Holdings Limited, 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 CAMAC Energy Holdings Limited 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 CAMAC Energy Holdings Limited’s majority interest in us were to be diluted or reduce due to additional issuances of equity by the Company, CAMAC Energy Holdings Limited’s 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 Oyo Field asset.

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. 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.

The government of Nigeria originally granted the rights to OML 120/121 PSC to CEHL. The government of Nigeria has 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.

Despite undertaking various security measures and being situated 75 miles offshore the Nigerian coast, the Floating Production Storage and Offloading (“FPSO”) vessel currently being used for storing petroleum production in the Oyo Field may become subject to terrorist acts and other acts of hostility like piracy. Such actions could adversely impact our 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 NAE’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.

Lower oil prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil that NAE 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.

Fluctuations in exchange rates could result in foreign currency exchange losses.

Because some of our expenses arising under the OML 120/121 PSC and the Zijinshan PSC may be denominated in foreign currencies, including the Nigerian naira, the Chinese yuan, European Union euro and British pound sterling, and our cash is denominated principally in U.S. dollars, fluctuations in the exchange rates between the U.S. dollar and foreign currencies will affect our balance sheet and earnings per share in U.S. dollars. In addition, we report our financial results in U.S. dollars, and appreciation or depreciation in the value of such foreign currencies relative to the U.S. dollar affects our financial results reported in U.S. dollars terms without giving effect to any underlying change in our business or results of operations. Fluctuations in the exchange rates will also affect the relative value of earnings from and the value of any U.S. dollar-denominated investments we make in the future.

Very limited hedging transactions are available in the Federal Republic of Nigeria to reduce our exposure to exchange rate fluctuations with respect to the Nigerian naira, although there are many hedging transactions available with respect to the European Union euro and the British pound sterling. We have not entered into any hedging transactions in an effort to reduce our exposure to foreign currency exchange risk. While we may decide to enter into hedging transactions in the future, the availability and effectiveness of these hedging transactions may be limited and we may not be able to successfully hedge our subsidiaries' exposure at all. In addition, our currency exchange losses with respect to the Nigerian naira may be magnified by Nigerian exchange control regulations that restrict our ability to convert Nigerian naira into foreign currency.

Currently, there are few means and/or financial tools available in the open market for the Company to hedge its exchange risk against any possible revaluation or devaluation of RMB. Because the Company does not currently intend to engage in hedging activities to protect against foreign currency risks, future movements in the exchange rate of the RMB could have an adverse effect on its results of operations and financial condition.

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 Asia and the Pacific Rim countries 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.

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, 2010, light crude oil futures have ranged from below $65 per barrel to over $85 per barrel, and may continue to fluctuate significantly in the future. With respect to ventures in China, the prices the Company will receive for oil and gas, in connection with any of its production ventures, will likely be regulated and set by the government. As a result, these prices may be well below the market price established in world markets. Therefore, the Company may be subject to arbitrary changes in prices that may adversely affect its ability to operate profitably.

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, China 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.

The Company conducts substantially all of its business in Nigeria and China. 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, China 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 interests in OML 120/121 PSC and the Zijinshan 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 Nigeria and China 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.

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 Nigeria and China or in any other foreign jurisdiction in which it operates. Over the past several years, the Chinese government has pursued economic reform policies including the encouragement of private economic activity, foreign investment and greater economic decentralization. The Chinese government may not continue to pursue these policies or may significantly alter them to the Company’s detriment from time to time with little, if any, prior notice.

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 Nigeria, 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 2010 Transparency International report ranks Nigeria 134 out of 178 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 Nigeria or China 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 and China. 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.

If the United States imposes trade sanctions on China due to its current currency policies, the Company’s operations could be materially and adversely affected.

Trade groups in the U.S. have blamed the unrealistically low value of the Chinese currency for causing job losses in American factories, giving exporters an unfair advantage and making its imports expensive. U.S. Congress from time to time has been considering the enactment of legislation with the view of imposing new tariffs on Chinese imports. If the U.S. Congress deems that China is still gaining a trade advantage from its exchange currency policy and an additional tariff is imposed, it is possible that China-based companies will no longer maintain significant price advantages over U.S. and other foreign companies on their goods and services, and the rapid growth of China’s economy would slow as a result. If the U.S. or other countries enact laws to penalize China for its currency policies, the Company’s business could be materially and adversely affected.

A lack of adequate remedies and impartiality under the Chinese legal system may adversely impact the Company’s ability to do business and to enforce the agreements to which it is a party.

The Company anticipates that it will be entering into numerous agreements governed by Chinese law. The Company’s business would be materially and adversely affected if these agreements were not enforced. In the event of a dispute, enforcement of these agreements in these countries could be extremely difficult.

Unlike the United States, China has a civil law system based on written statutes in which judicial decisions have little precedential value. The government’s experience in implementing, interpreting and enforcing certain recently enacted laws and regulations is limited, and the Company’s ability to enforce commercial claims or to resolve commercial disputes is uncertain. Furthermore, enforcement of the laws and regulations may be subject to the exercise of considerable discretion by agencies of the Chinese government, and forces unrelated to the legal merits of a particular matter or dispute may influence their determination. These uncertainties could limit the protections that are available to the Company.

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, including Nigeria, Hong Kong and China. Similarly, a substantial part of the Company’s operations are, and are expected to continue to be, conducted in Nigeria and China. 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 Nigeria or China 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 Limited is 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, CAMAC Energy Holdings Limited beneficially owned approximately 62.74% of our outstanding shares of Common Stock. CAMAC Energy Holdings Limited 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 CAMAC Energy Holdings Limited as our controlling stockholder could conflict with your interests as a holder of Company Common Stock. For example, CAMAC Energy Holdings Limited 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.

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.

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. Approximately 26 million shares of Preferred Stock are currently available for issuance. 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

Not applicable

ITEM 2. PROPERTIES

Part I, Item 1. Description of Business is incorporated herein by reference. In addition to the material in Item 1. the following additional items are included for Properties.

Office Facility Leases

The Company has three primary leased office facilities: Houston, Texas (the “Houston Facility”), Hartsdale, New York (the “Hartsdale Facility”), and Beijing, China (the “Beijing Facility”).

The Houston Facility covers 3,700 square feet of office space and is under a lease which commenced on October 11, 2010 and ends on October 31, 2013. Rental expense is currently $10,000 per month, including allocated share of operating expenses.

The Hartsdale Facility covers 2,000 square feet of office space and is under lease on a month-to-month basis. The Company plans to close the Hartsdale Facility by March 31, 2011.

The Beijing Facility covers approximately 5,300 square feet of office space. The Beijing Facility is occupied under a tenancy agreement that commenced on September 1, 2009 and ends on August 31, 2011. The Company’s rental expense recorded for the Beijing Facility is $11,000 per month, plus allocated share of utility 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

From time to time, we may become involved in various lawsuits and legal proceedings in the ordinary course of our business. We are currently not aware of any legal proceedings the ultimate outcome of which, in our judgment based on information currently available, would have a material adverse effect on our business, financial condition or operating results.

ITEM 4. REMOVED AND RESERVED

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

The table shows the high and low closing prices as reported by the NYSE Amex and OTC Bulletin Board .

Fiscal year ended December 31, 2010:	High		Low
First quarter	$	5.15	$	3.50
Second quarter		6.07		3.25
Third quarter		4.06		2.11
Fourth quarter		3.97		1.89

Fiscal year ended December 31, 2009:	High		Low
First quarter	$	1.15	$	0.35
Second quarter		2.41		0.75
Third quarter		3.70		1.50
Fourth quarter		5.75		3.15

Common Stock Warrants and Options

As of March 7, 2011, the Company had warrants outstanding to purchase (i) an aggregate of 732,745 shares of Common Stock at a price per share of $1.25; (ii) an aggregate of 134,708 shares of Common Stock at a price per share of $1.375; (iii) an aggregate of 130,000 shares of Common Stock at a price per share of $1.50; (iv) an aggregate of 4,659,551 shares of Common Stock at a price per share of $2.62; (v) an aggregate of 279,573 shares of Common Stock at a price per share of $2.75;(vi) an aggregate of 3,658,770 shares of Common Stock at a price per share of $4.50; (vii) an aggregate of 150,000 shares of Common Stock at a price per share of $5.00; and (viii) an aggregate of 124,408 shares of Common Stock at a price per share of $5.275.

As of March 7, 2011, an aggregate of 3,657,909 shares of Common Stock were issuable upon exercise of outstanding stock options.

Holders

As of March 7, 2011, there were approximately 100 registered holders of record of our common stock, and there are an estimated 7,000 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.

Securities Authorized for Issuance under Equity Compensation Plans

The following table includes the information as of the end of 2010 for each category of our equity compensation plans:

P 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)(3)		4,031,605	$	3.12	(4)		2,870,318
			$	2.19	(5)
Equity compensation plans not approved by security holders (2)		400,000	$	4.62	(2)		-
Total		4,431,605					2,870,318

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

(2)	Represents an individual compensation arrangement entered into between the Company and a consultant in connection with EORP milestone payments. These options were cancelled in January 2011.

(3)	Includes remaining warrants exercisable for 1,646,434 shares of Common Stock, originally issued in 2007 and 2010 to placement agents, for which issuance was approved by stockholders of the Company.

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

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

Recent Sales of Unregistered Securities

Unregistered Sales to United States Persons

On October 8, 2010, the Company issued an aggregate of 12,837 shares of Common Stock to one person upon the cashless "net" exercise by such person on such date of a placement agent warrant exercisable at $1.25 per share for an aggregate of 20,000 shares of the Company's Common Stock. The aggregate number of shares of Common Stock issued upon cashless “net” exercise was reduced from 20,000 shares of Common Stock to 12,837 shares of Common Stock to effect the cashless "net" exercise of the warrant in accordance with its terms, assuming a deemed fair market value of $3.49 per share, as calculated under the warrant as the closing price quoted for one share of the Company's Common Stock on the last trading day prior to the exercise date.

On October 12, 2010 the Company issued aggregates of 26,076 and 13,671 shares of Common Stock to one person upon the cashless "net" exercise by such person on such date of placement agent warrants exercisable at $1.375 and $1.25 per share, respectively, for aggregates of 40,000 and 20,000 shares of the Company's Common Stock, respectively. The aggregate number of shares of Common Stock issued upon cashless “net” exercise was reduced from 40,000 and 20,000 shares of Common Stock, respectively, to 26,076 and 13,671 shares of Common Stock, respectively, to effect the cashless "net" exercise of the warrants in accordance with their terms, assuming a deemed fair market value of $3.95 per share, as calculated under the warrants as the closing price quoted for one share of the Company's Common Stock on the last trading day prior to the exercise date.

On October 15, 2010, the Company issued an aggregate of 12,537 shares of Common Stock to one person upon the cashless "net" exercise by such person on such date of a placement agent warrant exercisable at $1.25 per share for an aggregate of 20,000 shares of the Company's Common Stock. The aggregate number of shares of Common Stock issued upon cashless “net” exercise was reduced from 20,000 shares of Common Stock to 12,537 shares of Common Stock to effect the cashless "net" exercise of the warrant in accordance with its terms, assuming a deemed fair market value of $3.35 per share, as calculated under the warrant as the closing price quoted for one share of the Company's Common Stock on the last trading day prior to the exercise date.

On October 18, 2010 the Company issued aggregates of 14,592 and 67,512 shares of Common Stock to one person upon the cashless "net" exercise by such person on such date of placement agent warrants exercisable at $1.375 and $1.25 per share, respectively, for aggregates of 25,292 and 109,708 shares of the Company's Common Stock, respectively. The aggregate number of shares of Common Stock issued upon cashless “net” exercise was reduced from 25,292 and 109,708 shares of Common Stock, respectively, to 14,592 and 67,512 shares of Common Stock, respectively, to effect the cashless "net" exercise of the warrants in accordance with their terms, assuming a deemed fair market value of $3.25 per share, as calculated under the warrants as the closing price quoted for one share of the Company's Common Stock on the last trading day prior to the exercise date.

Each of the warrants described above were originally issued to Garden State Securities, Inc. (the “Original Holder”) in its role as a placement agent for the Company on May 7, 2007, and subsequently assigned to the individual warrant holders in August 2007.

No underwriters were involved in the transactions described above. All of the securities issued in the foregoing transactions were issued by the Company in reliance upon the exemption from registration available under Section 4(2) of the Securities Act, including Regulation D promulgated thereunder, in that the transactions involved the issuance and sale of the Company’s securities to financially sophisticated individuals or entities that were aware of the Company’s activities and business and financial condition and took the securities for investment purposes and understood the ramifications of their actions. The Company did not engage in any form of general solicitation or general advertising in connection with the transaction. The Original Holder of the warrants represented that it was an “accredited investor” as defined in Regulation D at the time of issuance of the original warrants, and that it was acquiring such securities for its own account and not for distribution. All certificates representing the securities issued have a legend imprinted on them stating that the shares have not been registered under the Securities Act and cannot be transferred until properly registered under the Securities Act or an exemption applies.

Stock Repurchases

The Company did not repurchase any shares of its Common Stock during the quarter ended December 31, 2010.

Performance Graph

The graph below compares the value at December 31, 2007, 2008, 2009 and 2010 of a $100 investment in our common stock with $100 investments in the S&P 500 index and the S&P Small Cap 600 Energy Index assuming the initial investment was made on October 15, 2007. Pursuant to Item 201(e) of Regulation S-K (§220.201), the period covered by the comparison commences on October 15, 2007, which is the date our common stock became registered under section 12 of the Exchange Act.

ITEM 6. SELECTED FINANCIAL DATA

	For the year ended December 31,
Financial Summary	2010			2009			2008			2007			2006
Data	(In Thousands, except per share data)

Total revenues	$	31,612		$	67		$	-		$	-		$	-

Net Loss - CAMAC
Inc. and Subsidiaries	$	(230,468	)	$	(11,489	)	$	(5,447	)	$	(2,384	)	$	(1,086	)

Net Loss per share
of common stock -
basic and diluted	$	(1.95	)	$	(0.28	)	$	(0.14	)	$	(0.08	)	$	(0.10	)

Cash Provided by
(Used in) operating
activities	$	7,867		$	(7,111	)	$	(3,208	)	$	(2,061	)	$	(814	)

Captial Expenditures	$	394,978		$	233		$	330		$	81		$	208


	As of December 31,
Selected Balance		2010			2009			2008			2007			2006
Sheet Data	(In Thousands)

Working Capital	$	1,650		$	3,910		$	11,224		$	13,317		$	3,111

Property Plant and
Equipment - Net	$	204,979		$	451		$	569		$	285		$	209

Total Assets	$	247,843		$	7,436		$	14,119		$	17,457		$	3,929

For more information on results of operations and financial condition, see Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

Our Business

CAMAC Energy Inc. is a publicly traded company which seeks to develop new energy ventures outside the U.S., directly and through joint ventures and other partnerships in which it may participate. The Company’s current operations commenced in 2005 through IMPCO, formed as a limited liability company under New York State law on August 25, 2005. 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 and China.

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 IMPCO and ADS (the “Mergers”), in connection with which the Company changed its name to Pacific Asia Petroleum, Inc. The Company’s name was changed to CAMAC Energy Inc. effective April 7, 2010.

Oyo Field Production Sharing Contract Interest

On November 18, 2009, the Company entered into the Purchase and Sale Agreement with CAMAC Energy Holdings Limited and certain of its affiliates (“CEHL”) pursuant to which the Company agreed to acquire all of CEHL’s interest in a Production Sharing Contract (the “OML 120/121 PSC”) with respect to the oilfield asset known as the Oyo Field (the “Oyo Contract Rights”) and agreed to the related transactions contemplated thereby, including the election of certain directors of the Company. The OML 120/121 PSC governing the Oyo Field is by and among Allied Energy Plc. (“Allied”), an affiliate of CEHL, CAMAC International (Nigeria) Limited (“CINL”), an affiliate of CEHL, and Nigerian Agip Exploration Limited (“NAE”).

As consideration for the Oyo Contract Rights, on April 7, 2010 the Company paid CAMAC Energy Holdings Limited $32 million in cash consideration (the “Cash Consideration”) and issued to CAMAC Energy Holdings Limited 89,467,120 shares of Company Common Stock, par value $0.001, representing approximately 62.74% of the Company’s issued and outstanding Common Stock at closing (the “Consideration Shares”). In addition, if certain issued and outstanding warrants and options exercisable for an aggregate of 7,991,948 shares of Company Common Stock were exercised following the closing, the Company was obligated to issue up to an additional 13,457,188 Consideration Shares to CAMAC Energy Holdings Limited to maintain CAMAC Energy Holdings Limited’s approximately 62.74% interest in the Company. As of December 31, 2010, due to warrant expirations the maximum potential additional Consideration Shares issuable had been reduced to 7,484,983, of which 188,591 related to exercised warrants. As additional Cash Consideration, the Company agreed to pay CAMAC Energy Holdings Limited $6.84 million on the earlier of sufficient receipt of oil proceeds from the Oyo Field or six months from the closing date. This amount was paid in July 2010.

Registered Direct Offerings of Securities

In year 2010, the Company completed three registered direct offerings for combined sales of Company Common Stock and warrants, under which the following securities were issued:

February 16, 2010:

-5,000,000 shares of Common Stock at $4.00 per share – aggregate proceeds of $20 million

-Warrants to purchase 2,000,000 shares of Common Stock at $4.50 per share, expiring August 2013

-Warrants to purchase 2,000,000 shares of Common Stock at $4.00 per share, expired November 2010

-Placement agent warrants to purchase 150,000 shares of Common Stock at $5.00 per share, expiring February 2015

March 5, 2010:

-4,146,922 shares of Common Stock at $4.22 per share – aggregate proceeds of $17.5 million

-Warrants to purchase 1,658,769 shares of Common Stock at $4.50 per share, expiring September 2013

-Warrants to purchase 1,658,769 shares of Common Stock at $4.12 per share, expired December 2010

-Placement agent warrants to purchase 124,408 shares of Common Stock at $5.275 per share, expiring February 2015

December 28, 2010:

-9,319,102 shares of Common Stock at $2.20 per share – aggregate proceeds of $20.5 million

-Warrants to purchase 4,659,551 shares of Common Stock at $2.20 per share, increased to $2.62 per share 31 days after the closing, expiring December 2015

-Placement agent warrants to purchase 279,573 shares of Common Stock at $2.75 per share, expiring February 2015

OML 120/121 Transaction

a.	First Milestone: Upon commencement of drilling of the first well outside of the Oyo Field under the PSC, the Company may elect to retain the Non-Oyo Contract Rights upon payment to CEHL of $5 million (either in cash, or at Allied’s option, in shares);

If any of the above 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 CAMAC retaining all consideration paid by the Company to date.

The Purchase Agreement contained the following conditions to the closing of the Transaction: (i) CPL, CAMAC International (Nigeria) Limited (“CINL”), Allied, and Nigerian Agip Exploration Limited (“NAE”) must enter into a Novation Agreement in a form satisfactory to the Company and CAMAC Energy Holdings Limited and that contains a waiver by NAE of the enforcement of Section 8.1(e) of the PSC (providing for the continued waiver by NAE of its entitlement to “profit oil” in favor of Allied), and that notwithstanding anything to the contrary contained in the PSC, the profit sharing allocation set forth in the PSC shall be maintained after the consummation of the Transaction; (ii) the Company, and CEHL must enter into a registration rights agreement with respect to any shares issued by the Company to Allied at its election as consideration upon the occurrence of any of the above-described milestone events, in a form satisfactory to the Company and CEHL; and (iii) the Oyo Field Agreement, dated April 7, 2010, by and among the Company, CEHL and Allied, must be amended in order to remove certain indemnities with respect to Non-Oyo Operating Costs (as defined therein). In addition, CEHL must deliver the Data and certain equipment to the Company in as-is condition. The Company agreed to limited waivers of certain of these closing conditions under the Limited Waiver Agreement.

Oyo Field Well #5 Workover

During December 2010 and January 2011, the Company incurred approximately $55 million in costs relative to the workover to reduce gas production rising from the #5 well in the Oyo Field with the objective of increasing crude oil production from this well. By joint agreement with Allied, the Company will pay for the workover. To the extent the Company funds these costs, it will be 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. We expect to recover these costs as revenue in 2011 and 2012.

Asia - Zijinshan Production Sharing Contract

Enhanced Oil Recovery and Production (“EORP”)

In the fourth quarter of 2010, the Company decided it would explore all alternatives including the potential sale of the EORP business due to the lack of progress in establishing a significant business and the likelihood that further progress will be difficult to achieve under the existing local operating environment. The assets of the EORP operations are not material in terms of the Company’s total assets and the minority interest is reflected as a non-controlling interest in our consolidated financial statements. All active operations have ceased, including consideration of the Chifeng agreement area in Inner Mongolia for a possible EORP project. In February 2011, the Board of Directors of Dong Fang approved dissolution of Dong Fang, the operating company.

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, 2011 (the “Next Year”). During the Next Year, the Company plans to focus its efforts toward improving production in the Oyo Field, to consummate the OML 120/121 Transaction (which closed in February 2011) and to continue exploration operations under its 100% owned and operated Zijinshan PSC. The Zijinshan operations will include the possible drilling of three additional exploratory wells and continuing geological modeling and mapping.

In addition to these opportunities, the Company is continuing to seek to identify other opportunities in the energy sectors in Africa and Asia that will enhance its production and cash flow, particularly with respect to oil and gas exploration, development, production, refining and distribution. 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, and to realize and maximize value under the related OML 120/121 as a whole in coordination with OML 120/121’s operating contractor, NAE.

The Company expects to utilize a term credit facility of $25 million from an affiliated company to meet a substantial portion of its cash obligations for workover expenses on Oyo Field well #5. The credit facility provides for an annual interest rate based on 30 day Libor plus two percentage points with all amounts due and payable within 24 months from the closing date, expected in March 2011. Because the costs of this workover will be recovered as Cost Oil revenues under the OML 120/121 PSC starting in 2011, we expect to repay this loan 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 the 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; and

●	Continue the exploration and appraisal program for gas in the Zijinshan Block.

Results of Operations

In the quarter ended June 30, 2010, the Company ceased reporting as a development stage company and commenced reporting as an operating company. Therefore, for 2010 the Company has reported less than a full year of operations. Accordingly, comparison with previous year’s reported amounts may not be meaningful. The Company’s focus continues to be the development of new energy ventures, directly and through joint ventures and other partnerships in which it may participate that will provide value to its stockholders.

In 2010 the Company commenced recording significant revenues from operations. We may experience fluctuations in operating results in future periods 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.

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.

Africa Operations

As of December 31, 2010, our Africa operations, which commenced in April 2010, were comprised of an economic interest in the OML 120/121 PSC for the Oyo Field in offshore Nigeria. The Oyo Field commenced crude oil production in December 2009, and the Company acquired its economic interest on April 7, 2010 from CEHL. 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. Past expenditures for capital and operating costs of this field since the commencement of the OML 120/121 PSC have been funded entirely 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 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, which is not currently sufficient for a lifting every month. 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 percentage we receive from each lifting is subject to fluctuation because the proportions of cost oil and profit oil in each settlement can vary. This is dependent upon whether the maximum allowable cost oil recovery, or a lesser amount, is elected by the operating contractor in computing its share, which then affects the levels of profit oil for both parties. Inventory barrels included in the assets acquired at April 7, 2010 are excluded from the Company’s production volumetric statistics as this amount constitutes physical production prior to the acquisition date. Average revenue per barrel on crude oil sold in the year ended December 31, 2010 was $85.16.

Understanding the Results

The Company’s share of net production (which excludes royalties and the share of the other partner) from two oil producing wells for the period April 7 to December 31, 2010 (268 days) averaged 396 barrels per day. During 2010, the 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 Management Committee (MACOM) under the OML 120/121 PSC approved a short-term remedial work plan for well #5 involving pumping of a chemical sealant to block the flow of gas after identifying the locations of gas entry into the well bore, at an initial estimated cost of approximately $55 million. During December 2010, this work commenced on well #5 to significantly reduce its currently non-marketable natural gas production, which was impeding crude oil production. The work was completed in January 2011. The total gross production from the Oyo Field for the period April 7 to December 31, 2010 was 1,952,000 barrels, including royalty barrels. The Company’s share of net production, which excludes royalty barrels and the share of the other partner, was 106,000 barrels for that period.

The net operating loss (before non-cash impairment) for the Africa operations shown below for 2010 should not be viewed as predictive of results for future periods. Most significantly, the well # 5 workover resulted in a significant charge to expenses. These expenses will be fully recoverable as Cost Oil in future revenues. Another factor affecting 2010 results was that virtually all of the crude oil revenue in the six months ended June 30, 2010 arose from the sale of crude oil inventory included in the Oyo Field assets acquired on April 7, 2010 and recorded at fair value at that date under applicable accounting principles. This fair value per barrel approximated the ultimate sales price per barrel realized in the subsequent April 2010 third party lifting (sale) of Oyo Field crude oil. The initial inventory recorded at fair value was fully charged to cost of sales against the April 2010 sale under the Company’s first in, first out accounting method for valuing inventories. Thus the Company recorded only a small profit margin on the initial inventory that was liquidated in April 2010 although significant sales revenues were recorded. For future periods, net operating income for Africa 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 early 2011 we will record an additional charge to expense of approximately $25 million for the completion of the workover on well # 5 in the Oyo Field. These costs will be fully recoverable as Cost Oil in future revenues, dependent upon future production levels in the field and future operating costs.

Impairment of Assets

We evaluate our long-lived assets for indicators of potential impairment based on changes in circumstances. 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. We make critical assumptions and estimates in completing impairment assessments of long-lived assets. 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.

During the interim period ended September 30, 2010 and in connection with the preparation of its Quarterly Report on Form 10-Q for the period ended September 30, 2010, the Company commissioned an independent petroleum engineers report for an estimate of its current crude oil net underground reserves and related future net revenues (net cash flows) on its interest in the Oyo Field in Nigeria. This was the first assessment post-acquisition that reflected the Company’s current expected participation level in future operating and capital expenditures under the production sharing contract of this field. The amounts of such participation can have a significant effect on the allocation of net reserves by interest owner. The final reserve report was received by the Company on November 5, 2010 (the “Third Quarter Reserve Report”).

Upon review of the Third Quarter Reserve Report, the Company determined there was an indication of possible impairment with respect to the Oyo Field. This was due to the impact of a revised unit-of-production depletion rate on the Oyo Field oil and gas leasehold asset. This rate would result in future operating losses on this asset if based on the existing carrying amount at September 30, 2010.

The Company then determined that the September 30, 2010 aggregate undiscounted future net cash flows on the Company’s interest in the Oyo Field (recoverable amounts) were less than the net carrying amount of that asset in property, plant and equipment. Accordingly, on November 4, 2010, the Company determined that the leasehold asset was impaired. The estimate of cash flows included the use of the above Third Quarter Reserve Report combined with management’s assumptions of cash inflows and outflows directly resulting from the use of those assets in operations, including gross margin on sales and other costs to produce crude oil.

As of September 30, 2010, a non-cash impairment charge of $186.2 million was recorded in the Africa operating segment to adjust the Oyo Field carrying amount to estimated fair value based upon the present value of estimated future net cash flows.

Asia Operations

As of December 31, 2010, our active operations in China were focused on gas reserves exploration and development.

In the Zijinshan Block located in Shanxi province, the Company performed seismic work in 2009 and drilled its first exploratory well in late 2009. In 2010 the Company completed one additional exploratory well which resulted in finding of the presence of gas at several intervals. However, no flow tests were conducted due to the deteriorated hole condition, and therefore all exploratory costs were expensed. Under the production sharing contract covering this area, the Company is obligated to drill an additional five wells in future periods, estimated to cost approximately $1 million each, for a total of seven wells in the exploratory phase before commencement of formal development. Plans for 2011 include the drilling of up to three additional wells. Therefore, no revenues are expected from this area in 2011, and the Company has not yet declared any net proved reserves for this area.

Segment Analysis

Our segment analysis that follows is segmented on a geographic basis between our active operations in Africa (Nigeria) and Asia (China) for revenues and among Africa, Asia and Corporate for net income (loss). This is based upon the current management structure of our Company.

(In thousands)	Years Ended December 31,
Revenues	2010			2009			2008
Africa	$	31,409		$	-		$	-
Asia		203			67			-
Total	$	31,612		$	67		$	-


(In thousands)	Years Ended December 31,
Net Income (Loss)		2010			2009			2008
Africa - before impairment	$	(29,686	)	$	-		$	-
Africa - impairment		(186,235	)		-			-
Asia		(3,068	)		(4,560	)		(1,427	)
Corporate and other		(11,479	)		(6,929	)		(4,020	)
Net income (loss) - CAMAC Energy Inc.
and Subsidiaries	$	(230,468	)	$	(11,489	)	$	(5,447	)

Revenues and net loss for Africa before impairment in the year ended December 31, 2010 reflected workover expense and initial crude oil sales revenues since the acquisition in April 2010 of the Oyo field interest. Africa results include a non-cash impairment loss of $186,235,000 as discussed above under “Africa Operations – Impairment of Assets”.

Revenues in Asia for 2010 and 2009 related to sales of EORP chemicals were immaterial. In 2008 there were no revenues. Net losses in Asia decreased in 2010 versus 2009 principally due to decreased exploratory expenses of $882,000 and decreased consulting expenses of $632,000. There was a temporary decline in exploratory activity in the Zijinshan Block in the first six months of 2010 during further review and planning for the drilling of additional wells which commenced in the third quarter of 2010. The decrease in consulting expenses was principally due to nonrecurring EORP milestone payments of $500,000 in 2009 and decreased Zijinshan charges. In 2009 net operating losses in Asia increased versus 2008 principally due to increased exploratory expenses of $1,456,000 in the Zijinshan Block; increased consulting expense of $962,000 related to EORP; and $392,000 in other EORP operations expenses.

Net losses for Corporate and other items increased in 2010 versus 2009 periods principally due to increased salaries and bonus expense of $1,258,000 (including termination and accrued vacation payments of $345,000 to executives retiring in 2010); increased insurance expense of $329,000; increased executive recruiting fees of $254,000; increased travel , meals and entertainment of $234,000; increased legal fees of $231,208; and increased stock-based employee compensation expense of $1,683,000. The latter included $638,000 for the effects of accelerating the vesting dates of certain awards and reversal of expense on forfeited awards previously granted to former executive officers who retired in 2010, and a larger value of awards subject to amortization.

Net losses for Corporate and other items increased in 2009 versus 2008 principally due to increased salaries and bonus expense of $266,000; increased consulting expense paid as equity of $887,000; increased cash consulting expense of $314,000; and increased stock compensation expense of $1,076,000 (related to a larger value of awards subject to amortization).

Consolidated Statements of Operations

Year Ended December 31, 2010 Versus Year Ended December 31, 2009

●	Revenues ($31,612,000 vs. $67,000): The increase in revenues is principally due to $31,409,000 from crude oil sales from the Oyo Field in 2010, the initial year of activity. EORP sales of finished chemicals and services revenues also increased.

●	Crude oil and products cost of sales ($26,113,000 vs. $52,000): The increase is principally due to $25,966,000 from crude oil sales from the Oyo Field in 2010, the initial year of activity. Cost of sales from sales of finished chemicals in China also increased but did not have a significant effect.

●

Operating expenses ($32,901,000 vs. $2,580,000): The increase is principally due to operating expenses in Nigeria in 2010, the initial year of activity. Of this amount, $30,660,000 is due to well workover costs relative to well #5 in the Oyo Field. Consulting expenses for China operations decreased by $632,000 due to decreased EORP and Zijinshan consulting charges.

●

Selling, general and administrative expenses ($11,535,000 vs. $6,967,000): The increase is principally due to increased salaries and bonus expense of $1,258,000 (including termination and accrued vacation payments of $345,000 to executives retiring in 2010); increased insurance expense of $329,000; increased executive recruiting fees of $254,000; increased travel, meals and entertainment of $234,000; and increased stock based employee compensation expense of $1,683,000. The latter included $638,000 for the effects of accelerating the vesting dates of certain awards and reversal of expense on forfeited awards previously granted to former executive officers who retired in 2010.

●	Exploratory expenses ($823,000 vs. $1,705,000): The decrease is related to China gas operations and was affected by the timing of expenditures and overall level of activity.

●	Impairment of assets ($186,235,000 vs. $219,000): The increase is principally due to the year 2010 charge of $186,235,000 on the Oyo Field in Nigeria as discussed above under “Africa Operations – Impairment of Assets.”

●	Depreciation, depletion and amortization ($4,218,000 vs. $132,000): The increase is principally due to depletion expense of $4,007,000 on the Oyo Field in 2010, the initial year of activity.

Year Ended December 31, 2009 Versus Year Ended December 31, 2008

●	Revenues ($67,000 vs. zero): The increase in revenues is due to initial China EORP operations’ sales of finished chemicals and services revenues.

●	Crude oil and products cost of sales ($52,000 vs. zero): The increase is due to initial sales of finished chemicals in China.

●	Operating expenses ($2,580,000 vs. $862,000): The increase is principally due to a $962,000 increase in consulting charges for China EORP and other EORP operations initial expenses of $392,000.

●

Selling, general and administrative expense ($6,967,000 vs. $4,332,000): The increase is principally due to increased salaries and bonus expense of $266,000; increased consulting paid as equity of $887,000; increased cash consulting expense of $314,000; and increased stock compensation expense of $1,076,000.

●	Exploratory expenses ($1,705,000 vs. $249,000): The increase is related to China gas operations and was affected by the timing of expenditures and overall level of activity.

●	Impairment of assets ($219,000 vs. $274,000): The 2009 amount relates to impairment of a Chifeng well in China while the 2008 amount relates to impairment of a note receivable from a joint venture partner in China.

●	Depreciation, depletion and amortization ($132,000 vs. $67,000): The increase is principally due to an increased level of depreciable assets.

Liquidity and Capital Resources

The following table provides summarized statements of net cash flows for the years ended December 31, 2010 and 2009:

Cash Flows (In thousands)	Years Ended December 31,
	2010			2009
Net Cash Provided by (Used in) Operating Activities	$	7,867		$	(7,111	)
Net Cash Provided by (Used in) Investing Activities		(37,755	)		191
Net Cash Provided by Financing Activities		55,204			14
Effect of Exchange Rate Changes on Cash		-			(8	)
Net increase (decrease) in Cash and Cash Equivalents		25,316			(6,914	)
Cash and Cash Equivalents – Beginning of Period		3,602			10,516
Cash and Cash Equivalents – End of Period		28,918			3,602

As of December 31, 2010, the Company had net working capital of $1,650,000 and cash and cash equivalents of $28,918,000.

Net cash provided by operating activities was $7,867,000 in 2010 compared to cash used in operating activities of $7,111,000 in 2009. The increase in 2010 versus 2009 was due to revenues and collections of acquired receivables related to the Oyo Field in Nigeria, partially offset by increases in corporate expenses.

Net cash used in investing activities was $37,755,000 during 2010 versus $191,000 of net cash provided by investing activities in 2009. Cash used in 2010 was principally due to $38,840,000 for the cash portion of the purchase price of the Oyo Contract Rights. We met our cash requirements for investing activities in 2010 through net proceeds of $54,542,000 from registered direct offerings of equity securities and proceeds from operating cash flows from sales of crude oil production and collection of acquired receivables in Nigeria.

Net cash provided by financing activities was $55,204,000 in 2010 and $14,000 in 2009. The increase in 2010 was principally due to three registered direct offerings of equity securities in 2010 totaling $54,542,000, net of offering costs.

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.

During December 2010 and January 2011, the Company incurred approximately $55 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 from this well, of which $30.7 million was expensed as of December 31, 2010 for work completed as of that date. By agreements involving Allied, the Company will pay for the workover. As of December 31, 2010, $1.4 million of this amount had been paid.

The Company expects to utilize a term credit facility of $25 million from an affiliated company to meet a substantial portion of its cash obligations for workover expenses on Oyo Field well #5. The credit facility provides for an annual interest rate based on 30 day Libor plus two percentage points with all amounts due and payable within 24 months from the closing date, expected in March 2011. Because the costs of this work will be recovered as Cost Oil revenues under the OML 120/121 PSC starting in 2011, we expect to repay this loan 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’s consolidated financial statements have been prepared assuming it will continue as a going concern. Based upon current cash flow projections, management believes that the Company will have sufficient capital resources to meet projected cash flow requirements through 2011.

Our continued operations will 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, 2010 virtually all of our financing had been raised through private placements and registered direct offerings of equity instruments. The Company at December 31, 2010 had no credit lines for financing and no short-term or long-term debt.

Long-Lived Assets

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

As of December 31,	2010		2009
(In thousands)
Property, plant and equipment, net
United States	$	358	$	119
Outside United States		204,621		332
Total	$	204,979	$	451

Obligations under Material Contracts

The following table summarizes the Company’s significant contractual obligations at December 31, 2010.

	Payments Due By Period
Contractual Obligations - In thousands	Total	Less than 1 year	1-3 years	3-5 years	More than 5 years
Workover for well #5 and operating lease obligations	$54,542	$54,310	$232	$-	$-

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.

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 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. 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. 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). The amount of any asset retirement obligations which the Company may become subject to from its future operations is not determinable at this time.

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 in Nigeria include sales of royalty barrels. Oil revenue is recognized using the sales method for our share of Cost Oil, Profit Oil and Tax 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.

Foreign Currency Translation

The functional currency of the U.S. parent company and Nigeria subsidiary is the U.S. dollar. The functional currency of China incorporated subsidiaries is the local currency (RMB). For Hong Kong incorporated subsidiaries, the functional currency is the U.S. dollar or RMB, depending on the primary activity of the subsidiary. Balance sheet translation effects from translating functional currency into U.S. dollars (the reporting currency) are recorded directly to other comprehensive income in accordance with ASC Topic 200, Comprehensive Income.

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 (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.

Allocation of Purchase Price in Acquisitions

As part of our business strategy, we actively pursue the acquisition of oil and gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Recently Issued Accounting Standards Not Yet Adopted

As of the balance sheet date, there were no new accounting pronouncements not yet adopted that are expected to materially affect the Company.

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

The Company may be exposed to certain market risks related to changes in foreign currency exchange, interest rates, and commodity prices.

Foreign Currency Exchange Risk

In addition to the U.S. dollar, the Company conducts its business in RMB and therefore is subject to foreign currency exchange risk on cash flows related to expenses and investing transactions.

In July 2005, the Chinese government began to permit the RMB to float against the U.S. dollar. All of our costs to operate our Chinese office and operations are paid in RMB. Our exploration costs in China may be incurred under contracts denominated in RMB or U.S. dollars. To date the Company has not engaged in hedging activities to hedge our foreign currency exposure. In the future, the Company may enter into hedging instruments to manage its foreign currency exchange risk or continue to be subject to exchange rate risk.

Interest Rate Risk

See Note 17 to the consolidated financial statements in Part II, Item 8. Financial Statements and Supplemental Data for information regarding our financial instruments. At December 31, 2010 the Company had investments in fixed rate financial instruments subject to interest rate risk affecting fair value. However, those instruments were bank certificates of deposit with remaining terms of less than one year or break clauses permitting withdrawal in less than one year. Therefore, the effect of an increase or decrease in interest rates on the fair value of those financial instruments would not be material.

Commodity Price Risk

As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil. Prevailing prices for such commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control. Historically, prices received for oil production have been volatile and unpredictable, and such volatility is expected to continue.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

The following index lists the financial statements and supplemental data of CAMAC Energy Inc. that are included in this report.

	Page
Report of Independent Registered Public Accounting Firm		54

Financial Statements:

Consolidated Balance Sheets –December 31, 2010 and 2009		55

Consolidated Statements of Operations – For the years ended December 31, 2010, 2009, and 2008		56

Consolidated Statements of Comprehensive Income (Loss) – For the years ended December 31, 2010, 2009, and 2008		57

Consolidated Statements of Equity (Deficiency) – For the years ended December 31, 2010, 2009, and 2008		58

Consolidated Statements of Cash Flows – For the years ended December 31, 2010, 2009 and 2008		59

Notes to Consolidated Financial Statements		60

Supplemental Quarterly Financial Data		82

Supplemental Data on Oil and Gas Exploration and Producing Activities		83

Schedules not disclosed above or elsewhere in this report have been omitted since they are either not required, are not applicable or the required information is shown in the financial statements or the related notes.

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 sheets of CAMAC Energy Inc. and its subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2010. 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 audits.

We conducted our audits in accordance with 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 audits 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, 2010 and 2009 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ RBSM LLP

New York, New York

March 10, 2011

AUDITED FINANCIAL STATEMENTS

CAMAC Energy Inc. and Subsidiaries

(Formerly Pacific Asia Petroleum, Inc. and Subsidiaries)

Consolidated Balance Sheets

(In thousands, except par value and share data)
As of December 31,	2010			2009

Assets
Current assets
Cash and cash equivalents	$	28,918		$	3,602
Short-term investments		256			1,736
Accounts receivable		10,411			69
Inventories		72			73
Other current assets		2,847			467
Total current assets		42,504			5,947

Non-current assets
Property, plant and equipment - at cost (net of accumulated depreciation, depletion and amortization):
(2010 - $2,306; 2009 - $182)		204,979			451
Intangible assets		-			1
Investment in long-term certificate of deposit		-			25
Long-term advances		34			33
Investment in nonsubsidiary - at fair value		272			478
Deferred charges		54			501

Total Assets	$	247,843		$	7,436

Liabilities and Equity
Current liabilities
Accounts payable	$	63		$	172
Income taxes payable		163			13
Accrued contracting and development fees		32,329			920
Accrued personnel expenses		606			368
Accrued liability for contingent acquisition cost		890			-
Accrued royalties		5,933			-
Accrued and other liabilities		870			564
Total current liabilities		40,854			2,037

Equity
Stockholders' equity - CAMAC Energy Inc. and Subsidiaries:
Preferred stock
Authorized - 50,000,000 shares at $.001 par value;
Issued - 23,708,952 as of December 31, 2010 and December 31, 2009
Outstanding - None as of December 31, 2010 and December 31, 2009		-			-
Common stock
Authorized - 300,000,000 shares at $.001 par value; Issued and outstanding -
153,611,792 as of December 31, 2010; 43,037,596 as of December 31, 2009		154			43
Paid-in capital		458,523			26,035
Accumulated deficit		(250,925	)		(20,457	)
Other comprehensive income (loss)		(120	)		91
Total stockholders' equity - CAMAC Energy Inc. and subsidiaries		207,632			5,712
Noncontrolling interests deficit		(643	)		(313	)
Total equity		206,989			5,399

Total Liabilities and Equity	$	247,843		$	7,436

The accompanying notes to the consolidated financial statements are an integral part of this statement.

AUDITED FINANCIAL STATEMENTS

CAMAC Energy Inc. and Subsidiaries

(Formerly Pacific Asia Petroleum, Inc. and Subsidiaries)

Consolidated Statements of Operations

(In thousands, except per common
share data)	Years ended December 31,
	2010			2009			2008
Revenues
Crude oil (Note 10)	$	31,409		$	-		$	-
Products		188			56			-
Services		15			11			-
Total revenues		31,612			67			-

Costs and operating expenses
Crude oil cost of sales (Note 10)		25,966			-			-
Products cost of sales		147			52			-
Operating expenses (Note 10)		32,901			2,580			862
Selling, general and administrative expenses		11,535			6,967			4,332
Exploratory expenses		823			1,705			249
Impairment of assets (Note 7)		186,235			219			274
Depreciation, depletion and amortization		4,218			132			67
Total costs and operating expenses		261,825			11,655			5,784

Operating loss		(230,213	)		(11,588	)		(5,784	)

Other income (expense)
Interest income		10			37			324
Interest expense		-			(1	)		-
Other income (expense)		(4	)		-			14
Total other income		6			36			338

Net loss before income taxes and
noncontrolling interests		(230,207	)		(11,552	)		(5,446	)
Income tax expense		(591	)		(39	)		(13	)

Net loss		(230,798	)		(11,591	)		(5,459	)
Less: Net loss - noncontrolling interests		330			102			12

Net Loss - CAMAC Energy Inc.
and Subsidiaries	$	(230,468	)	$	(11,489	)	$	(5,447	)

Net loss per common share - CAMAC
Energy Inc. common stockholders -
basic and diluted	$	(1.95	)	$	(0.28	)	$	(0.14	)

Weighted average number of common
shares outstanding, basic and diluted		117,926			41,647			39,993

The accompanying notes to the consolidated financial statements are an integral part of this statement.

AUDITED FINANCIAL STATEMENTS

CAMAC Energy Inc. and Subsidiaries

(Formerly Pacific Asia Petroleum Inc. and Subsidiaries)

Consolidated Statements of Comprehensive

Income (Loss)

	Years ended December 31.
(In thousands)	2010			2009			2008

Net loss	$	(230,798	)	$	(11,591	)	$	(5,459	)
Other comprehensive income (loss) -
pre-tax and net of tax:
Currency translation adjustment		(7	)		(64	)		102
Unrealized gain (loss) on
investments in securities		(206	)		(75	)		-
Total other comprehensive income (loss)		(213	)		(139	)		102

Comprehensive income (loss)		(231,011	)		(11,730	)		(5,357	)
Less: Comprehensive (income) loss -
Noncontrolling interests' share:
Net loss plus pre-tax and net of
tax other comprehensive income/loss		332			102			9

Comprehensive income (loss) -
CAMAC Energy Inc. and
Subsidiaries	$	(230,679	)	$	(11,628	)	$	(5,348	)

The accompanying notes to the consolidated financial statements are an integral part of this statement.

AUDITED FINANCIAL STATEMENTS

CAMAC Energy Inc. and Subsidiaries

(Formerly Pacific Asia Petroleum Inc. and Subsidiaries)

Consolidated Statements of Equity (Deficiency)

Years ended December 31, 2010, 2009 and 2008

(In thousands, except par value)	CAMAC Energy Inc. Stockholders
	No. of Preferred Shares $.001 par value		Preferred Stock		No. of Common Shares $.001 par value			Common Stock		Paid-in Capital			Accumulated Deficit			Other Comprehensive Income (Loss)			Noncontrolling Interests			Total Equity (Deficiency)
Balance - December 31, 2007		-	$	-		39,931		$	40	$	20,251		$	(3,521	)	$	128		$	395		$	17,293
Issued on exercise of warrants		-		-		80			-		-			-			-			-			-
Vesting of restricted stock		-		-		76			-		-			-			-			-			-
Cancellation of restricted stock		-		-		(10	)		-		-			-			-			-			-
Compensation cost of stock options and restricted stock		-		-		-			-		1,356			-			-			-			1,356
Issued for services		-		-		15			-		138			-			-			-			138
Issued for acquisition of Navitas Corporation		-		-		450			-		8,176			-			-			-			8,176
Acquired on acquisition of Navitas Corporation		-		-		(480	)		-		(8,179	)		-			-			-			(8,179	)
Currency translation		-		-		-			-		-			-			102			3			105
Net loss		-		-		-			-		-			(5,447	)		-			(12	)		(5,459	)
Balance - December 31, 2008		-		-		40,062			40		21,742			(8,968	)		230			386			13,430
Issued on exercise of warrants and options		-		-		239			-		14			-			-			-			14
Exchanged for stock of Sino Gas & Energy Holdings Limited		-		-		970			1		552			-			-			-			553
Vesting of restricted stock		-		-		738			1		(1	)		-			-			-			-
Compensation cost of stock options and restricted stock		-		-		-			-		2,432			-			-			-			2,432
Issued for services		-		-		1,029			1		1,052			-			-			-			1,053
Adjustments to noncontrolling interests in subsidiary equity		-		-		-			-		244			-			-			(597	)		(353	)
Currency translation		-		-		-			-		-			-			(64	)		-			(64	)
Unrealized gain (loss) on investments in securities		-		-		-			-		-			-			(75	)		-			(75	)
Net loss		-		-		-			-		-			(11,489	)		-			(102	)		(11,591	)
Balance - December 31, 2009		-		-		43,038			43		26,035			(20,457	)		91			(313	)		5,399
Issued on exercise of warrants and options		-		-		1,514			2		660			-			-			-			662
Vesting of restricted stock		-		-		814			1		(1	)		-			-			-			-
Issued for cash, net of issuance costs		-		-		18,466			18		54,524			-			-			-			54,542
Compensation cost of stock options and restricted stock		-		-		-			-		4,115			-			-			-			4,115
Issued for services		-		-		313			1		1,096			-			-			-			1,097
Adjustments to noncontrolling interests in subsidiary equity		-		-		-			-		-			-			-			2			2
Issued for assets in Nigeria		-		-		89,467			89		372,094			-			-			-			372,183
Currency translation		-		-		-			-		-			-			(5	)		(2	)		(7	)
Unrealized gain (loss) on investments in securities		-		-		-			-		-			-			(206	)		-			(206	)
Net loss		-		-		-			-		-			(230,468	)		-			(330	)		(230,798	)
Balance - December 31, 2010		-	$	-		153,612		$	154	$	458,523		$	(250,925	)	$	(120	)	$	(643	)	$	206,989

The accompanying notes to the consolidated financial statements are an integral part of this statement.

AUDITED FINANCIAL STATEMENTS

CAMAC Energy Inc. and Subsidiaries

(Formerly Pacific Asia Petroleum, Inc. and Subsidiaries)

Consolidated Statements of Cash Flows

	Years ended December 31,
(In thousands)	2010			2009			2008

Cash flows from operating activities
Net loss- CAMAC Energy Inc. and subsidiaries	$	(230,468	)	$	(11,489	)	$	(5,447	)
Adjustments to reconcile net loss to cash provided by
(used in) operating activities:
Interest income on long-term advances		-			-			(88	)
Currency transaction (gain) loss		(8	)		(56	)		41
Stock-based compensation expense		4,560			3,457			1,493
Net loss – noncontrolling interest		(330	)		(102	)		(12	)
Impairment of assets		186,235			219			274
Depreciation, depletion and amortization		4,218			132			67
Changes in current assets and current
liabilities:
(Increase) decrease in accounts and other receivables		3,537			(61	)		(8	)
(Increase) decrease in inventory		5,530			(73	)		-
(Increase) decrease in other current assets		(1,231	)		20			(57	)
Increase (decrease) in accounts payable		(109	)		147			23
Increase in accrued and other current liabilities		35,933			695			506
Net cash provided by (used in) operating activities		7,867			(7,111	)		(3,208	)

Cash flows from investing activities
Net sales (purchases) of available for sale securities		1,504			(475	)		9,940
Purchase of long-term certificate of deposit		-			(25	)		-
Refunds on prospective property acquisitions		-			1,150			1,900
(Increase) decrease in long-term advances and deferred charges		(56	)		(226	)		6
Additions to property, plant and equipment		(39,203	)		(233	)		(334	)
Net cash provided by (used in) investing activities		(37,755	)		191			11,512

Cash flows from financing activities
Proceeds from exercise of stock options and warrants		662			14			-
Issuance of common stock net of issuance costs		54,542			-			(3	)
Net cash provided by (used in) financing activities		55,204			14			(3	)

Effect of exchange rate changes on cash		-			(8	)		6

Net increase in cash and cash equivalents		25,316			(6,914	)		8,307
Cash and cash equivalents at beginning of period		3,602			10,516			2,209
Cash and cash equivalents at end of period	$	28,918		$	3,602		$	10,516

Supplemental disclosures of cash flow information
Interest paid	$	-		$	1		$	-
Income taxes paid	$	20		$	25		$	49
Supplemental schedule of non-cash investing and
financing activities
Common and preferred stock issued for services and fees	$	1,097		$	1,053		$	138
Common stock issued for stock of nonsubsidiary	$	-		$	553		$	-
Issuance costs paid as warrants issued	$	749		$	-		$	-
Common stock issued for net assets acquired in acquisition	$	372,183		$	-		$	-
Increase in fixed assets accrued in liabilities	$	78		$	-		$	-
Decrease to long-term advances to noncontrolling interest shareholder	$	-		$	354		$	-
Disposition of partial interest in a subsidiary	$	-		$	244		$	-
Decrease in noncontrolling interest investment in subsidiary	$	-		$	(597	)	$	-

The accompanying notes to consolidated financial statements are an integral part of this statement.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. --- COMPANY DESCRIPTION

CAMAC Energy Inc. (the “Company”) is the successor company from a reverse merger involving the former Pacific East Advisors, Inc. and other entities on May 7, 2007. The Company’s activities commenced in 2005 through Inner Mongolia Production Company, LLC (“IMPCO”), a limited liability company formed under New York State law on August 25, 2005. In April 2010, due to a change in control of the Company resulting from an asset acquisition in Nigeria, the Company’s name was changed from Pacific Asia Petroleum, Inc. to CAMAC Energy Inc.

The Company operates in the upstream segment of the oil and gas industry in exploration and producing activities. The Company’s operational assets are located in Nigeria and China.

NOTE 2. --- BASIS OF PRESENTATION AND LIQUIDITY

Basis of Presentation

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. Certain previously reported amounts have been reclassified to conform to the current year presentation.

For the period from inception of the Company through March 31, 2010, the Company’s consolidated financial statements were prepared as a development stage company. In the three months ended June 30, 2010 the Company commenced the recognition of significant revenues from operating assets located in Nigeria and at that time ceased reporting as a development stage company. Prior year data has been revised to the current year reporting basis as an operating company, and accordingly, comparison with previous year's reported amounts may not be meaningful. In addition, certain amounts for cumulative effects from inception of the Company and other disclosures required for a development stage company in the financial statements are no longer included.

In preparing the accompanying consolidated financial statements, we have evaluated information about subsequent events that became available to us through the date the consolidated financial statements were issued (March 10, 2011). This information relates to events, transactions or changes in circumstances that would require us to adjust the amounts reported in the financial statements or to disclose information about those events, transactions or changes in circumstances.

Liquidity

The Company incurred a net loss of $230,468,000 for the year ended December 31, 2010 and at that date had an accumulated deficit of $250,925,000. During December 2010 and January 2011, the Company incurred approximately $55 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. (See Note. 5. - Acquisition of Oyo Field Production Sharing Contract Interest). Of this amount, $30.7 million was charged to expense as of December 31, 2010 for costs incurred as of that date. By agreements involving Allied Energy Plc, an affiliated company, the Company will pay for the workover.

The Company expects to utilize a term credit facility from an affiliated company, which has agreed to provide this facility, in order to meet a substantial portion of the Company’s cash obligations with respect to the workover on well #5 in the Oyo Field. The costs of this work will be recovered as Cost Oil in revenues under the OML 120/121 Production Sharing Contract starting in 2011, which the Company expects will enable it to repay the loans within the due date under the term facility. The portion of the workover funded from the Company’s own cash will also be recovered as Cost Oil in revenues and thus will be available for future operations after such recovery occurs.

NOTE 3. --- SIGNIFICANT ACCOUNTING POLICIES

Accounting Standards Codification

Effective July 1, 2009, the Accounting Standards Codification (the “Codification”)(“ASC”) became the single official source of authoritative accounting principles recognized by Financial Accounting Standards Board to be applied by non- governmental entities in the preparation of financial statements in conformity with U.S. GAAP. Sources of accounting principles referred to in this report refer to Topics of the Codification.

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.

Short-Term Investments

The Company applies the provisions of ASC Topic 320, (Investments in Debt and Equity Securities). The Company classifies debt and equity securities into one of three categories: held-to-maturity, available-for-sale or trading. These security classifications may be modified after acquisition only under certain specified conditions. Securities may be classified as held-to-maturity only if the Company has the positive intent and ability to hold them to maturity. Trading securities are defined as those bought and held principally for the purpose of selling them in the near term. All other securities must be classified as available-for-sale. Declines in the fair value of held-to-maturity and available-for-sale securities below their cost that are deemed to be other than temporary are reflected in earnings as realized losses.

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. Amounts of accounts receivable deemed uncollectible are charged off generally one year after the original due date. As of December 31, 2010 and 2009, no allowance for doubtful accounts was necessary.

Inventories

The Company's inventories of chemicals are carried at lower of cost or market, with cost determined using average cost.

Deferred Technical Services Agreement (TSA) charges

Deferred TSA charges represent the Company's capitalized technical services expenses for administration of our interest in the Oyo Field. These amounts are charged to cost of sales as crude oil is sold. At December 31, 2010 and 2009 $393,000 and zero are included in other current assets in the accompanying consolidated balance sheets.

Property, Plant and Equipment

Asset Retirement Obligations

Revenues

Income Taxes

Foreign Currency Translation

Stock-Based Compensation

Net Earnings (Loss) Per Common Share

New Accounting Pronouncements

As of the balance sheet date, there were no new accounting pronouncements not yet adopted that are expected to materially affect the Company.

NOTE 4. -- ADOPTION OF UPDATES TO THE FASB ACCOUNTING STANDARDS CODIFICATION

ASC 820-10

Effective January 1, 2009 the Company adopted the portion of ASC Topic 820 (Fair Value Measurements and Disclosures) that relates to assets measured at fair value on a nonrecurring basis. The Company had previously adopted the remainder of ASC Topic 820 effective January 1, 2008. Neither adoption had a material effect on the Company’s measurement practices for determining fair value.

ASC 825-10

Commencing with the interim period ending June 30, 2009, the Company adopted new requirements for quarterly disclosures related to fair values of financial instruments whether or not currently reflected on the balance sheet at fair value. Previously, qualitative and quantitative information about fair value estimates for financial instruments not measured on the balance sheet at fair value were disclosed only annually. Quarterly disclosures were required under an update to ASC Topic 825 (Financial Instruments) effective for interim periods ending after June 15, 2009. The adoption of this update did not have a material impact on the Company’s results of operations or financial condition.

ASC 810-10

Effective January 1, 2009 the Company adopted an update to ASC Topic 810 (Consolidation) that changes the accounting and reporting for noncontrolling interests (formerly known as minority interests) in subsidiaries and for the deconsolidation of a subsidiary. The presentation of noncontrolling interests in the balance sheet and income statement has been revised to report noncontrolling interests as a separate component of total consolidated equity and total consolidated net income, rather than as reduction adjustments. In addition, if a subsidiary is deconsolidated, the parent company will now recognize a gain or loss to net income based upon the fair value of the noncontrolling equity at that date.

The update is applied prospectively except for the provisions involving financial statements line detail presentation. All of the Company’s financial statements contain changes as a result of the update. Under the update, the amount formerly titled “Net Loss” in the income statement is now referred to as “Net Loss - CAMAC Energy, Inc. and Subsidiaries,” to designate the portion of total net loss attributable to the controlling shareholder interest of the parent company. Financial statements for years prior to 2009 have been revised retrospectively in this report to reflect the revised presentation basis.

ASC 855-10

Effective with the six months ended June 30, 2009, the Company adopted an update to ASC Topic 855 (Subsequent Events). Subsequent events are events or transactions about which information becomes available after the balance sheet date but before the financial statements are issued or are available to be issued. In the case of the Company as a public entity, the applicable cutoff date is the date the financial statements are issued, whereas previously the cutoff date could be the date the financial statements were available for issuance.

The update requires that certain subsequent events (“recognized subsequent events”) be recorded in the financial statements of the latest preceding period currently being issued. These items provide evidence about conditions that existed at the date of that balance sheet, including estimates inherent in preparing the financial statements for that period. Other subsequent events (“nonrecognized subsequent events”) are not recorded in balance sheet for the latest preceding period currently being issued. Those items relate to conditions that arose only after the balance sheet date. Disclosure is required for nonrecognized subsequent events if necessary to prevent those financial statements from being misleading.

NOTE 5. -- ACQUISITION OF OYO FIELD PRODUCTION SHARING CONTRACT INTEREST

On April 7, 2010, the Company consummated the acquisition of all of the interests held by CAMAC Energy Holdings Limited and certain of its affiliates (“CEHL”) in a Production Sharing Contract (the “OML 120/121 PSC”) with respect to an oilfield asset known as the Oyo Field located offshore Nigeria (the “Oyo Contract Rights”). The OML 120/121 PSC governing the Oyo Field is by and among Allied Energy Plc. (“Allied”), an affiliate of CEHL, CAMAC International (Nigeria) Limited (“CINL”), an affiliate of CEHL, and Nigerian Agip Exploration Limited (“NAE”). The Oyo Field was under development until oil production commenced in December 2009.

As consideration for the Oyo Contract Rights, the Company paid CAMAC Energy Holdings Limited $32 million in cash consideration (the “Cash Consideration”) and issued to CAMAC Energy Holdings Limited 89,467,120 shares of Company Common Stock, par value $0.001, representing approximately 62.74% of the Company’s issued and outstanding Common Stock at closing (the “Consideration Shares”). In addition, if certain issued and outstanding warrants and options exercisable for an aggregate of 7,991,948 shares of Company Common Stock were exercised following the closing, the Company was obligated to issue up to an additional 13,457,188 Consideration Shares to CAMAC Energy Holdings Limited to maintain CAMAC Energy Holdings Limited’s approximately 62.74% interest in the Company. As additional Cash Consideration, the Company agreed to pay CAMAC Energy Holdings Limited $6.84 million on the earlier of sufficient receipt of oil proceeds from the Oyo Field or six months from the closing date. This amount was paid in July 2010. At December 31, 2010, due to warrant expirations the maximum additional Consideration Shares obligation on the warrants and options had been reduced to 7,484,983 shares of which 188,591 related to exercised warrants. The Company is unable to estimate the number of such remaining warrants and options which may ultimately be exercised. In connection with the closing on April 7, 2010, the Company, CEHL and certain of their respective affiliates entered into a number of ancillary documents to consummate the transaction.

As a result of this transaction, a change in control of the Company occurred and CEHL is now a related party. As a result of its controlling interest in the Company, CEHL has the ability to approve any matter submitted to the Company’s stockholders where a simple majority vote is required to obtain stockholder approval, whether such action is sought through a special or annual meeting or through written consent. Additionally, CEHL currently owns and controls enough shares to elect the Company’s directors at annual meetings.

Upon closing of the transaction, the Company changed its name to CAMAC Energy Inc., but continues as a publicly-traded entity, separate from CEHL.

The original purchase cost for the acquisition of CEHL’s interests in the OML 120/121 PSC with respect to the Oyo Field was allocated as shown in the table below. The measurement date was the closing date, April 7, 2010. The fair value of the consideration paid was not fixed and determinable prior to closing. The transaction has been accounted for as an acquisition of an asset and does not represent the acquisition of a business. The allocation of the acquisition as of the closing date was as follows:

(In thousands)
Accounts receivable	$	13,880
Inventories		11,619
Property cost of PSC interest		393,648
Current liabilities		( 7,771	)
Total purchase cost	$	411,376

See Note 7. -- Impairment of Assets regarding the recording of an impairment loss on the property cost portion of this acquisition as of September 30, 2010.

NOTE 6. -- REGISTERED DIRECT OFFERINGS OF SECURITIES

In year 2010, the Company completed three registered direct offerings for combined sales of Company Common Stock and warrants, under which the following securities were issued:

February 16, 2010:

-5,000,000 shares of Common Stock at $4.00 per share – aggregate proceeds of $20 million

-Warrants to purchase 2,000,000 shares of Common Stock at $4.50 per share, expiring August 2013

-Warrants to purchase 2,000,000 shares of Common Stock at $4.00 per share, which expired November 2010

-Placement agent warrants to purchase 150,000 shares of Common Stock at $5.00 per share, expiring February 2015

March 5, 2010:

-4,146,922 shares of Common Stock at $4.22 per share – aggregate proceeds of $17.5 million

-Warrants to purchase 1,658,769 shares of Common Stock at $4.50 per share, expiring September 2013

-Warrants to purchase 1,658,769 shares of Common Stock at $4.12 per share, which expired December 2010

-Placement agent warrants to purchase 124,408 shares of Common Stock at $5.275 per share, expiring February 2015

December 28, 2010:

-9,319,102 shares of Common Stock at $2.20 per share – aggregate proceeds of $20.5 million

-Warrants to purchase 4,659,551 shares of Common Stock at $2.20 per share, increasing to $2.62 per share 31 days after the closing, expiring December 2015

-Placement agent warrants to purchase 279,573 shares of Common Stock at $2.75 per share, expiring February 2015

The exercise prices for all of the above warrants are subject to customary adjustments as included in each respective warrant agreement.

Net proceeds from the February and March offerings have been used by the Company for working capital purposes, and to fund the Company’s acquisition from CEHL of the Oyo Contract Rights in April 2010. Net proceeds from the December offering are being used to fund a portion of the cost of the workover work on well #5 in the Oyo Field and for working capital purposes.

NOTE 7. -- IMPAIRMENT OF ASSETS

Impairment of Oyo Field Leasehold Cost

Impairment of Chifeng Oil Well Costs

In 2009, the Company conducted an impairment review of its Chifeng contract capitalized oil well cost for recoverability as an asset to be held and used. This review was prompted based on the continuing lack of production license that would enable recovery of these costs through production revenues and that three years have passed with no progress in this regard. Without a production license, the opportunities to drill additional production wells under the contract and future production from this initial well are significantly at risk. The Company had alternate strategies it intended to pursue toward possibly obtaining a production license through modification of the existing agreement and/or inclusion of this area in a production license for a neighboring area should the Company be able to obtain a production license for that other area. However, as of December 31, 2009, activity toward accomplishing this result by specific negotiations and agreements had not commenced, and the likelihood of possible success and when it might occur could not be reasonably estimated. Therefore, the Company concluded that an estimate of future cash flows from this asset no longer could be made. Absent the likely ability to obtain a production license, the fair value of the asset is zero under Level 3 unobservable inputs for estimation of fair value under ASC Topic 820. Those conditions required the recording of an impairment charge to expense and retirement of capitalized costs of $219,000.

Impairment of BJHTC Note Receivable

In 2006, the Company advanced $401,000 to Beijing Jinrun Hongda Technology Co. Ltd. (“BJHTC”) to facilitate that company’s investment in a 3% interest in a China subsidiary of the Company, IMPCO Sunrise. The note matures November 14, 2014 and is payable in RMB. Subsequently, the note balance increased to $535,000 from accrued interest and currency translation gains. The note and interest are repayable only from profits of IMPCO Sunrise. Based upon the delay in achieving net income in IMPCO Sunrise and the increasing accrued interest, the Company determined in year 2008 that the note was impaired and recorded an impairment charge of $274,000. The calculation was based upon a “level 3” unobservable input as there was no publicly traded security comparable to this note, since repayment is only required from profits of IMPCO Sunrise should they occur.

NOTE 8. --- PROPERTY, PLANT AND EQUIPMENT

			Accumulated
			Depreciation,
			Depletion and
(In thousands)	Gross		Amortization		Net
December 31, 2010
Oil and gas properties	$	206,440	$	1,917	$	204,523
Enhanced oil recovery operations		35		8		27
Office and computer equipment		623		314		309
Leasehold improvements		187		67		120
Total	$	207,285	$	2,306	$	204,979

December 31, 2009
Oil and gas properties	$	150	$	-	$	150
Enhanced oil recovery operations		34		2		32
Office and computer equipment		359		161		198
Leasehold improvements		90		19		71
Total	$	633	$	182	$	451

NOTE 9. --- OPERATING SEGMENT DATA

The Company manages its operations on a geographical basis. Commencing with the second quarter of fiscal 2010, the Company’s two operating segments are Africa and Asia.

Our segments derive revenues from the sale of oil and gas products. The Company has no intersegment revenues and is not dependent on a single significant customer for a substantial portion of its revenues.

	Years ended December 31,
(In thousands)	2010		2009		2008
Revenues
Africa	$	31,409	$	-	$	-
Asia		203		67		-
Total revenues	$	31,612	$	67	$	-

Segment performance is measured on an after-tax operating basis. Corporate income and expense items for interest income and expense, corporate administrative costs, stock-related compensation and noncontrolling interests are not allocated to segments. Following below are net income (loss); impairment; depreciation, depletion and amortization; and income tax expense by segment.

	Years ended December 31,
(In thousands)	2010			2009			2008
Net Income (Loss)
Africa	$	(215,921	)	$	-		$	-
Asia		(3,068	)		(4,560	)		(1,427	)
Corporate		(11,479	)		(6,929	)		(4,020	)
Total net income (loss)	$	(230,468	)	$	(11,489	)	$	(5,447	)

	Years ended December 31,
(In thousands)	2010		2009		2008
Impairment
Africa	$	186,235	$	-	$	-
Asia		-		219		274
Corporate		-		-		-
Total impairment	$	186,235	$	219	$	274

	Years ended December 31,
(In thousands)	2010		2009		2008
Depreciation, Depletion and Amortization
Africa	$	4,007	$	-	$	-
Asia		100		70		42
Corporate		111		62		25
Total depreciation, depletion and amortization	$	4,218	$	132	$	67

	Years ended December 31,
(In thousands)	2010			2009		2008
Income Tax Expense
Africa	$	423		$	-	$	-
Asia		(1	)		-		-
Corporate		169			39		13
Total income tax expense	$	591		$	39	$	13

Segment assets below exclude intercompany receivables and payables, intercompany investments, cash and cash equivalents, short-term investments and marketable securities. Below are capital expenditures and assets by segment.

	Years ended December 31,
(In thousands)	2010		2009		2008
Capital Expenditures
Africa	$	394,537	$	-	$	-
Asia		90		147		244
Corporate		351		86		86
Total capital expenditures	$	394,978	$	233	$	330

	As of December 31,
(In thousands)	2010		2009		2008
Assets
Africa	$	216,721	$	-	$	-
Asia		408		582		908
Corporate		30,714		6,854		13,211
Total assets	$	247,843	$	7,436	$	14,119

NOTE 10. SUPPLEMENTAL STATEMENT OF OPERATIONS INFORMATION

Following is an analysis of the components for revenues and cost of sales related to crude oil for the year ended December 31, 2010.

			2010
	2010		Cost of
(In thousands)	Revenues		Sales
Crude Oil (includes royalty oil)
Liquidation of acquired inventory (Oyo Field)	$	11,827	$	11,715
Post-acquisition production (Oyo Field)		19,582		14,251
Total crude oil	$	31,409	$	25,966

As shown in Note 5, one of the assets acquired as part of the Oyo Field interest was inventory. This was for crude oil which had been produced but not yet sold as of the acquisition date. As evident in the tables of revenues and cost of sales above, a significant portion of the crude oil revenues in the year ended December 31, 2010 arose from the sale of this acquired inventory. At the date of acquisition this inventory had been recorded at fair value as required under applicable accounting principles. Accordingly, the related portion of cost of sales for the year ended December 31, 2010 reflects the liquidation of this inventory based on that recorded cost, as adjusted for final pricing adjustment on the royalty portion. For the remainder of crude oil sold in the year ended December 31, 2010, cost rather than fair value is the basis for cost of sales.

Revenues and cost of sales for 2010 include our share of Royalty Oil of $16,421,000. Revenues also include our share of Tax Oil of $2,252,000, which is also recorded as income tax expense.

Operating expenses for the year 2010 include $30,700,000 for the workover on well #5 in the Oyo Field in Nigeria, for the purpose of improving the crude oil production rate. We expect that this amount will be recovered as Cost Oil in years 2011 and 2012 revenues under the OML 120/121 PSC.

NOTE 11. --- INCOME TAXES

Income tax expense was as follows for the respective periods:

(In thousands)	2010		2009		2008
Current:
U.S. Federal	$	-	$	-	$	(19	)
Outside U.S.		422		-		-
State		169		39		32
Total income tax expense	$	591	$	39	$	(13	)

The Company’s subsidiaries outside the United States did not have any undistributed net earnings at December 31, 2010, due to accumulated net losses.

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

(In thousands)	2010			2009			2008
Net (loss) before income tax expense	$	(229,877	)	$	(11,450	)	$	(5,434	)
Expected income tax provision at statutory rate of 35%:	$	(80,457	)	$	(4,007	)	$	(1,902	)
Increase (decrease) due to:
Foreign-incorporated subsidiaries		11,624			1,585			434
Impairment permanent difference		65,182			-			-
State and other income tax		169			39			32
Net losses not realizable currently for U.S. tax purposes		4,073			2,422			1,468
Penalties and miscellaneous		-			-			(19	)
Total income tax expense	$	591		$	39		$	13

The Company records interest and penalties related to income taxes as 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.

Deferred income tax assets by category are as follows as of December 31:

(In thousands)	2010			2009			2008
Tax basis operating loss carryovers	$	11,730		$	5,172		$	1,746
Well workover		15,943			-			-
Other		554			386			406
		28,227			5,558			2,152
Valuation allowance		(28,227	)		(5,558	)		(2,152	)
Net deferred income tax assets	$	-		$	-		$	-

The Company’s total tax basis loss carryovers at December 31, 2010 were $34,808,000. Of this amount, $6,257,000 has no expiration date. The remainder expires from 2011 to 2030. Due to the significant change in ownership, the Company's future use of its existing operating losses may be limited.

Tax years ended December 31, 2007 through 2009 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.

NOTE 12. – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Following is a detail of activity by category for accumulated other comprehensive income (loss).

(In thousands)	Currency translation adjustment			Gain (loss) on investments in securities			Total
Balance – December 31, 2007	$	128		$	-		$	128
Change during 2008		102			-			102
Balance – December 31, 2008		230			-			230
Change during 2009		( 64	)		(75	)		(139	)
Balance – December 31, 2009		166			-			91
Change during 2010		( 5	)		(206	)		(211	)
Balance – December 31, 2010	$	161		$	(281	)	$	( 120	)

NOTE 13. --- 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 6,000,000 shares of Common Stock. Options awarded expire 10 years from date of grant or shorter term as fixed by the Board of Directors. In 2010, the Company granted a total of 2,019,500 stock options with vesting periods from 6 months to 60 months under all compensation agreements.

	Number of Shares Underlying Options			Weighted Average Exercise Price per Share		Weighted Average Remaining Contractual Term(Years)
Outstanding at December 31, 2009		2,542,270		$	1.57		8.2
Granted in 2010		2,019,500		$	3.61		4.6
Exercised in 2010		(1,344,100	)	$	0.59
Forfeited in 2010		(432,499	)	$	2.79
Outstanding at December 31, 2010		2,785,171		$	3.34		5.1
Expected to vest		2,217,475		$	3.00		4.6
Exercisable at December 31, 2010		613,260		$	2.64		6.6

The total intrinsic values of options at December 31, 2010 were $497,000 for options outstanding and $382,000 for options that were exercisable at that date. The total intrinsic values realized by recipients on options exercised were $3,882,000 in 2010, $118,000 in 2009, and none in 2008.

The Company recorded compensation expense relative to stock options in 2010, 2009 and 2008 of $1,666,000, $584,000 and $378,000 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.

	2010			2009			2008
Expected price volatility (basket of comparable public companies)		113.7	%		77.5	%		65.60	%
Risk free interest rate (U.S. Treasury bonds)		0.8	%		1.4	%		2.04	%
Expected annual dividend rate		0.0	%		0.0	%		0.00	%
Expected option term – weighted average	3.6yrs.			3.2 yrs.			6.0 yrs.
Grant date fair value per common share – weighted average	$	2.36		$	2.05		$	.39

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.

Restricted Stock	Number Of Grants			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2009		1,020,055		$	2.29
Granted in 2010		620,350		$	3.44
Vested in 2010		(814,411	)	$	2.80
Forfeited in 2010		(268,294	)	$	2.05
Outstanding at December 31, 2010		557,700		$	3.02

The total grant date fair value of RSA shares that vested during 2010 was approximately $2,279,000. As of December 31, 2010, there was approximately $1,055,000 of total unrecognized compensation cost related to nonvested RSAs, with $1,015,000, and $40,000 to be recognized during the years ended December 31, 2011and 2012, respectively.

NOTE 14. --- POTENTIALLY DILUTIVE SECURITIES

Warrants issued in stock offerings, options and restricted stock are potentially dilutive in future periods if the Company has net income. These potentially dilutive securities have been anti-dilutive for all periods to date because the Company has been in a loss position.

NOTE 15. --- EMPLOYEE BENEFIT PLANS

In 2007 the Company adopted a defined contribution 401(k) plan for its 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. In 2010, the Company contributions were $95,000 under this plan including third party administration fees.

NOTE 16. --- PATENT APPLICATION RIGHTS

On November 27, 2009, the State Intellectual Property Office of the PRC in China recognized Dong Fang as the official owner of the six LXD Patent Application Rights (the “Rights”), covering enhanced oil recovery technologies developed by LXD (the “EORP Technologies”). LXD contributed the Rights in satisfaction of his 24.5% share of Dong Fang’s registered capital of RMB 30,000,000. The fair value of the Rights was verified by a certified Chinese valuation firm. Thus far, Dong Fang has used the Rights to utilize the EORP Technologies in both service and sale scenarios.

Under interpretation SAB No. 48 issued by the Staff of the U.S. Securities and Exchange Commission, the Company in this case is not permitted to record a capitalized asset value on the Rights for U.S. reporting. This ruling in no way lessens the fair value of the Rights to the Company.

In February 2011, the Board of Directors of Dong Fang approved the dissolution of Dong Fang.

NOTE 17. --- FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

The carrying amounts of the Company’s financial instruments for cash equivalents, short-term and long-term cash investments, accounts receivable, deposits, advances, accounts payable, and accrued expenses, approximate fair value at December 31, 2010, and 2009. The carrying amount for the investment in nonsubsidiary is fair value from a market price. The recorded amounts for fair values of securities were as follows at December 31, 2010 and 2009:

(In thousands)	2010		2009
Available for sale:
Short-term investments	$	256	$	1,736
Investment in nonsubsidiary		272		478

Held to maturity:
Long-term certificate of deposit	$	-	$	25
Long-term advances		34		33

Concentration of Credit Risk

The Company is exposed to concentration of credit risk with respect to cash, cash equivalents, short-term investments, and noncurrent investments and advances. At December 31, 2010, 68% ($19.6 million) of the Company’s total cash and cash equivalents was on deposit at JP Morgan Chase in the U.S. At December 31, 2009, 65% ($1,291,000) of the Company’s total cash was on deposit at HSBC in China and Hong Kong. Also at December 31, 2009, 64% ($1,029,000) of the Company’s total cash equivalents was invested in a single money market fund in the U.S.

NOTE 18. – FAIR VALUE MEASUREMENTS

The Company calculates fair values for assets and liabilities utilizing a three level hierarchy as follows:

Level 1: Quoted market prices in active markets for identical items.

Level 2: Observable inputs not included in Level 1, such as quoted prices for similar assets or liabilities, broker quotations, or other observable inputs for a similar contract term.

Level 3: Unobservable inputs where Level 1 or Level 2 inputs are not available. Level 3 inputs may involve internal models of risk-adjusted expected cash flows using present value techniques.

The tables below exclude current assets and current liabilities other than assets for short-term investments, as fair value and cost are deemed to be identical for the excluded items.

Assets Measured at Fair Value on a Recurring Basis - as of December 31
(In thousands)
			Level 1					Level 1
	2010		Measurements		2009			Measurements
Short-term investments	$	256	$	256	$	1,736		$	1,736
Investment in nonsubsidiary		272		272		478			478
Total	$	528	$	528	$	2,214		$	2,214


Assets Measured at Fair Value on a Nonrecurring Basis - as of December 31
(In thousands)
					Loss
			Level 3		Recorded
		2010	Measurements		for Year
Property, plant and equipment
to be held and used	$	204,979	$	204,979	$	(186,235	)
Long-term advances	$	34	$	34	$	-

					Loss
			Level 3		Recorded
		2009	Measurements		for Year
Property, plant and equipment
to be held and used	$	451	$	451	$	(219	)
Long-term advances	$	33	$	33	$	-

NOTE 19. --- COMMITMENTS AND CONTINGENCIES

Lease Commitments

We rent office space under non-cancelable operating leases. Rent expense for the years ended December 31, 2010, 2009 and 2008 was $238,000, $233,000 and $110,000, respectively. At December 31, 2010, future rental commitments for operating leases were a total of $442,000 as follows: 2011 - $210,000; 2012 - $123,000; and 2013 – $109,000.

Workover Commitment

As of December 31, 2010, the Company has a workover commitment for rig rental and other costs related to Oyo Field well #5 for approximately $55 million. Of this amount, $30.7 million was recorded in accrued liabilities at December 31, 2010.

Contingencies

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, 2010, 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 financial position or our net income or loss.

NOTE 20. --- RELATED PARTY TRANSACTIONS

Agreements with Related Parties

Employment Agreement and Consulting Agreement with Frank C. Ingriselli

The Company and Frank C. Ingriselli, its former President, Chief Executive Officer and member of the Board of Directors, were parties to an employment agreement (the “Ingriselli Agreement”) through the date of Mr. Ingriselli’s voluntary retirement effective August 1, 2010. The Ingriselli Agreement contained, among other things, severance payment provisions that required the Company to continue Mr. Ingriselli’s salary for 36 months and his benefits for 36 months if employment was terminated without “cause,” as such term is defined in the Ingriselli Agreement, and to make a lump sum payment equal to 48 months salary and continue benefits for 48 months if terminated within 12 months of a “change in control,” as such term is defined in the Ingriselli Agreement. Pursuant to this agreement, Mr. Ingriselli’s annual base salary was $350,000, and he was entitled to an annual bonus of between 20% and 40% of his base salary, as determined by the Company’s Board of Directors, based on his performance, the Company’s achievement of financial performance and other objectives established by the Board of Directors each year, provided, however, that annual bonus may be less as approved by the Board of Directors based on his performance and the performance of the Company. Under the agreement, Mr. Ingriselli was eligible for long-term incentive compensation, such as additional options to purchase shares of the Company’s capital stock, on such terms as established by the Board of Directors. Mr. Ingriselli voluntarily retired from his employment and all positions with the Company effective August 1, 2010, and in connection with Mr. Ingriselli’s retirement, the Company and Mr. Ingriselli entered into a separately negotiated Separation and Mutual Release Agreement pursuant to which Mr. Ingriselli provided a general release of all claims against the Company in exchange for the Company’s release of all claims against Mr. Ingriselli, the release by the Company of repurchase rights with respect to an aggregate of 60,000 shares of unvested restricted Company Common Stock held by Mr. Ingriselli, the acceleration of vesting with respect to options to purchase an aggregate of 154,666 shares of the Company’s Common Stock held by Mr. Ingriselli, and a lump sum payment of $169,166.66 to Mr. Ingriselli.

The Company and Mr. Ingriselli were parties to a consulting agreement, dated August 1, 2010, pursuant to which Mr. Ingriselli served as an independent consultant to the Company to assist in the transition of his management roles and responsibilities to a successor to be selected by the Company. As compensation, Mr. Ingriselli received a fee of $40,000 per month. Mr. Ingriselli’s consulting engagement ended September 30, 2010.

Employment Agreement with Stephen F. Groth

The Company and Stephen F. Groth, its former Chief Financial Officer, were parties to an employment agreement (the “Groth Agreement”) through the date of Mr. Groth’s voluntary retirement on May 17, 2010. The Groth Agreement contained, among other things, severance payment provisions that required the Company to continue Mr. Groth’s salary for 36 months and his benefits for 24 months if employment was terminated without “cause,” as such term is defined in the Groth Agreement, and to make a lump sum payment equal to 48 months salary and continue benefits for 36 months if terminated within 12 months of a “change in control,” as such term is defined in the Groth Agreement. Pursuant to this agreement, Mr. Groth’s annual base salary was $150,000 (changed to $165,000 effective January 1, 2008), and he was entitled to an annual bonus of between 20% and 30% of his base salary, as determined by the Company’s Board of Directors based on his performance, the Company’s achievement of financial performance and other objectives established by the Board of Directors each year, provided, however, that annual bonus may be less as approved by the Board of Directors based on his performance and the performance of the Company. Under the agreement, Mr. Groth was eligible for long-term incentive compensation, such as additional options to purchase shares of the Company’s capital stock, on such terms as established by the Board of Directors. Mr. Groth voluntarily retired from his employment with the Company effective May 17, 2010, and in connection with Mr. Groth’s retirement, the Company and Mr. Groth entered into a separately negotiated Separation and Mutual Release Agreement pursuant to which Mr. Groth provided a general release of all claims against the Company in exchange for the Company’s release of all claims against Mr. Groth, the release by the Company of repurchase rights with respect to an aggregate of 64,261 shares of unvested restricted Company Common Stock held by Mr. Groth, the acceleration of vesting with respect to options to purchase an aggregate of 92,332 shares of the Company’s Common Stock held by Mr. Groth, and a lump sum payment of $40,000 to Mr. Groth.

Employment Agreement with Richard Grigg

On August 1, 2008, the Company entered into an Employment Agreement with Richard Grigg, the Company’s Senior Vice President and Managing Director (the “Grigg Agreement”). The Grigg Agreement, which superseded the prior employment agreement the Company entered into with Mr. Grigg in March 2008, had a three year term, and provided for a base salary of 1,650,000 RMB (approximately $241,000) per year and an annual performance-based bonus award targeted at between 30% and 40% of his then-current annual base salary awardable in the discretion of the Company’s Board of Directors. Mr. Grigg was also entitled to reimbursement of certain accommodation expenses in Beijing, China, medical insurance, annual leave expenses, and certain other transportation fees and expenses. In addition, in the event the Company terminated Mr. Grigg’s employment without Cause (as defined in the Grigg Agreement), the Company would have been required to pay to Mr. Grigg a lump sum amount equal to 50% of Mr. Grigg’s then-current annual base salary. However, on January 27, 2009, the Company revised the terms of its employment relationship with Richard Grigg by entering into an Amended and Restated Employment Agreement with Mr. Grigg (the “Amended Employment Agreement”) and a Contract of Engagement (“Contract of Engagement”) with KKSH Holdings Ltd., a company registered in the British Virgin Islands (“KKSH”). Mr. Grigg is a minority shareholder and member of the board of directors of KKSH. The Amended Employment Agreement superseded the Grigg Agreement and now governs the employment of Mr. Grigg in the capacity of Managing Director of the Company for a period of three years. The Amended Employment Agreement provided for a base salary of 990,000 RMB (approximately $144,000) per year and the reimbursement of certain accommodation expenses in Beijing, China, annual leave expenses, and certain other transportation and expenses of Mr. Grigg. In addition, in the event the Company terminated Mr. Grigg’s employment without Cause (as defined in the Amended Employment Agreement), the Company would pay to Mr. Grigg a lump sum amount equal to 50% of Mr. Grigg’s then-current annual base salary. The Contract of Engagement governed the engagement of KKSH for a period of three years to provide the services of Mr. Grigg through KKSH as Senior Vice President of the Company strictly with respect to the development and management of business opportunities for the Company outside of the People’s Republic of China. The basic fee for the services provided under the Contract of Engagement was 919,000 RMB (approximately $134,000) per year, to be prorated and paid monthly and subject to annual review and increase upon mutual agreement by the Company and KKSH. Pursuant to the Contract of Engagement, the Company also provided Mr. Grigg with medical benefits and life insurance coverage, and an annual performance-based bonus award targeted at between 54% and 72% of the basic fee, awardable in the discretion of the Company’s Board of Directors. In addition, in the event the Company terminated the Contract of Engagement without Cause (as defined in the Contract of Engagement), the Company would pay to KKSH a lump sum amount equal to 215% of the then-current annual basic fee. On February 7, 2011 the Company and Mr. Grigg entered into a voluntary retirement agreement for Mr. Grigg’s retirement effective on that date. In addition, Mr. Grigg and KKSH entered into General Release of All Claims Agreements with the Company in return for a payment of $50,000, acceleration of vesting with respect to options to purchase an aggregate of 31,792 shares of Company Common Stock held by Mr. Grigg and KKSH, and release by the Company of repurchase rights with respect to an aggregate of 86,925 shares of unvested restricted Company Common Stock held by Mr. Grigg. On February 8, 2011 KKSH and the Company entered into a Consulting Agreement for temporary services of Mr. Grigg through March 31, 2011 to provide transition services for a total fee of approximately $54,000.

Transaction with Richard Grigg

In March 2009, the Company issued 970,000 shares of Company Common Stock, to Richard Grigg, the Company’s Senior Vice President and Managing Director, in exchange for 3,825,000 Ordinary fully paid shares of Sino Gas & Energy Holdings Limited (SG&E) owned by Mr. Grigg. This represented approximately 3.26% of the outstanding shares of SG&E as of March 9, 2009. The acquired shares were originally accounted for by the Company as a non-current investment carried at cost. Commencing with the interim period ending September 30, 2009 the carrying amount was recorded at fair value, due to SG&E trading publicly on the Australian Stock Exchange beginning September 15, 2009. Mr. Grigg is a former executive of SG&E who joined the Company in October 2007. The SG&E shares were acquired in order to eliminate possible conflicts of interest involving Mr. Grigg regarding possible future transactions that may occur between the Company and SG&E, as both companies’ business plans involve developing operations in China.

Employment Agreement with Jamie Tseng

The Company was a party to an Employment Agreement with Jamie Tseng, the Company’s former Executive Vice President (the “Tseng Employment Agreement”), dated April 22, 2009 and effective January 1, 2009. The Tseng Employment Agreement governed the employment of Mr. Tseng in the capacity of Executive Vice President of the Company until Mr. Tseng’s retirement effective January 15, 2010, and provided for a base salary of $140,000 per year, and provided that, in the event the Company terminated Mr. Tseng’s employment without Cause (as defined in the Tseng Employment Agreement), the Company would have been required to pay to Mr. Tseng a lump sum amount equal to 50% of Mr. Tseng’s then-current annual base salary. Mr. Tseng retired from his employment with the Company effective January 15, 2010, and in connection with Mr. Tseng’s retirement, the Company and Mr. Tseng entered into a Separation and Release Agreement pursuant to which Mr. Tseng provided a general release of all claims against the Company in exchange for the release by the Company of repurchase rights with respect to an aggregate of 61,572 shares of unvested restricted Company Common Stock held by Mr. Tseng, the acceleration of vesting with respect to options to purchase 40,800 shares of the Company’s Common Stock held by Mr. Tseng, the award of 20,000 shares of restricted Company Common Stock to Mr. Tseng, a lump sum payment of $50,000 to Mr. Tseng, and the continued payment by the Company of the Beijing office lease through February 2010 that was used by Mr. Tseng.

Consulting Agreement with William E. Dozier

The Company and William E. Dozier, its Interim Chief Executive Officer and member of the Board of Directors, were parties to a consulting agreement, dated August 1, 2010, pursuant to which Mr. Dozier served as an independent consultant to the Company. The consulting agreement was terminable by either the Company or Mr. Dozier upon thirty days’ notice. As compensation, Mr. Dozier received a fee of $30,000 per month, and was granted 100,000 shares of the Company’s Common Stock pursuant to the Company’s 2009 Equity Compensation Plan, all of which shares vested upon the effective date of the Company’s appointment of a new Chief Executive Officer. Upon the appointment of Mr. Byron A. Dunn on October 1, 2010 as Chief Executive Officer, Mr. Dozier stepped down as the Interim Chief Executive Officer and consultant.

Employment Agreement with Byron A. Dunn

Effective October 1, 2010, the Company appointed Mr. Byron A. Dunn as the Company’s new President, Chief Executive Officer, and member of the Board of Directors. The Company and Mr. Dunn are parties to an employment agreement (“Dunn Employment Agreement”) pursuant to which Mr. Dunn shall receive an annual base salary of $375,000, a one-time cash sign-on bonus of $150,000, and payment of certain club membership and transportation expenses, and Mr. Dunn shall also be eligible to receive a discretionary cash performance bonus each year targeted at 100% of his then-current annual base salary. Also, effective on his start date of October 1, 2010, the Company issued to Mr. Dunn 250,000 shares of Company restricted Common Stock subject to a one year vesting period, and an option to purchase 1.5 million shares of the Company’s Common Stock vesting 1/3 on December 1 of each of 2011, 2012 and 2013. In addition, in the event the Company terminates Mr. Dunn’s employment without Cause (as defined in the Dunn Employment Agreement) or Mr. Dunn resigns for Good Reason (as defined in the Employment Agreement, (i) the Company must pay to Mr. Dunn an amount equal to 24 months of his base salary plus target bonus as in effect immediately before Mr. Dunn’s termination or resignation (30 months in connection with a Change in Control, as defined in the Dunn Employment Agreement), (ii) the Company must pay to Mr. Dunn an amount equal to 24 months of the maximum contribution the Company may make for Mr. Dunn under the Company’s 401(k) plan (30 months in connection with a Change in Control, as defined in the Employment Agreement), (iii) any outstanding stock options and restricted stock shall become fully vested, and options shall remain exercisable for 12 months, (iv) the Company shall reimburse Mr. Dunn for up to $20,000 of outplacement services, and (v) the Company shall continue to provide Mr. Dunn and his dependents with the same level of insurance benefits received immediately prior to termination or resignation for up to 2 years, or until Mr. Dunn obtains similar replacement benefits through a new employer.

Secondment Agreement for Abiola L. Lawal

Abiola L. Lawal, the Company's Executive Vice President and Chief Financial Officer effective August 1, 2010, was under contract in that capacity from May 17, 2010 to September 1, 2010 pursuant to a secondment agreement from CAMAC International Corporation (“CIC”), Mr. Lawal's employer (the “Secondment”). During that time Mr. Lawal remained an employee of CIC, which contracted his services to the Company pursuant to the Secondment on a month-to-month basis to serve the Company on a full-time basis, reporting directly to the Company’s Chief Executive Officer. During the term of the Secondment, the Company paid directly to CIC on a monthly basis the pro rata portion of Mr. Lawal’s then-currently existing $315,000 salary, CIC’s cost of providing employee benefits to Mr. Lawal, the pro rata portion of any cash bonus paid to Mr. Lawal and approved by the Company’s Board of Directors or Compensation Committee, CIC’s share of any employment-related taxes and fees with respect to Mr. Lawal’s employment, and any expenses incurred by CIC at the request of the Company, or otherwise required of CIC in connection with the Secondment.

The Company's Chairman and Director, Dr. Kase Lawal, is also a minority shareholder and director of CIC, as well as an indirect shareholder and control person of CEHL. In addition to being a shareholder of CIC, Dr. Kase Lawal is the Chairman and CEO of that company, and is also a director of CAMAC International Ltd. (“CIL”) and CEHL. Mr. Abiola Lawal and Dr. Kase Lawal have no familial relationship. CIC represents the interests of CEHL and other entities affiliated with CIL (collectively, “CAMAC Entities”), providing technical, administrative, and other assistance to the CAMAC Entities in the United States and overseas. Although some of the shareholders of CIC, including Dr. Kase Lawal, also own shares of the CAMAC Entities, the majority ownership of CIC and CIL are different. During the term of Mr. Abiola Lawal's service to the Company pursuant to the Secondment, which ended September 1, 2010, he no longer served as an executive officer of CIC or any party related to CIC or any of the CAMAC Entities.

Employment Agreements with Abiola L. Lawal

On September 1, 2010, the Company and Mr. Abiola Lawal, the Company’s Executive Vice President and Chief Financial Officer, entered into an Employment Offer Letter (the “Lawal Employment Agreement”) pursuant to which Mr. Lawal became a full-time employee of the Company. Prior to becoming a full-time employee of the Company, Mr. Lawal served as Executive Vice President and Chief Financial Officer of the Company on a full-time basis pursuant to the Secondment from CIC which ended effective September 1, 2010 upon the commencement of Mr. Lawal’s employment with the Company. Pursuant to the Lawal Employment Agreement, Mr. Lawal received an annual base salary of $315,000 and received a one-time cash promotion bonus of $50,000. In addition, Mr. Lawal was eligible for a discretionary cash performance bonus each year targeted at between 25% to 50% of his then-current annual base salary, as well as additional equity grants, in the discretion of the Company’s Board of Directors. In addition, in the event the Company terminated Mr. Lawal’s employment without Cause or Mr. Lawal resigned for Good Reason (each as defined in the Lawal Employment Agreement), the Company was obligated to continue paying to Mr. Lawal his base salary and benefits for a period for 12 months following such termination.

Effective March 8, 2011 the Company and Mr. Lawal entered into an Amended and Restated Employment Agreement (the “Amended Lawal Employment Agreement”) pursuant to which Mr. Lawal receives an annual base salary of $315,000. In addition, Mr. Lawal is eligible for a discretionary cash performance bonus each year targeted at between 0% and 100% of his then-current annual base salary, as well as additional equity grants, in the discretion of the Company’s Board of Directors. In addition, in the event the Company terminates Mr. Lawal’s employment without Cause (as defined in the Amended Lawal Employment Agreement) or Mr. Lawal resigns for Good Reason (as defined in the Amended Lawal Employment Agreement, (i) the Company must pay to Mr. Lawal an amount equal to 24 months of his base salary plus target bonus as in effect immediately before Mr. Lawal’s termination or resignation (30 months in connection with a Change in Control, as defined in the Lawal Amended Employment Agreement), (ii) the Company must pay to Mr. Lawal an amount equal to 24 months of the maximum contribution the Company may make for Mr. Lawal under the Company’s 401(k) plan (30 months in connection with a Change in Control, as defined in the Amended Lawal Employment Agreement), (iii) any outstanding stock options and restricted stock shall become fully vested, and options shall remain exercisable for 12 months, (iv) the Company shall reimburse Mr. Lawal for up to $20,000 of outplacement services, and (v) the Company shall continue to provide Mr. Lawal and his dependents with the same level of insurance benefits received immediately prior to termination or resignation for up to 2 years, or until Mr. Lawal obtains similar replacement benefits through a new employer.

Management Service Contracts

In connection with the merger on May 7, 2007, the Company assumed an Advisory Agreement, dated December 1, 2006, by and between ADS and Cagan McAfee Capital Partners, LLC (“CMCP”), pursuant to which CMCP agreed to provide certain financial advisory and management consulting services to the Company. Pursuant to the Advisory Agreement, CMCP was entitled to receive a monthly advisory fee of $9,500 for management work commencing on December 11, 2006 and continuing until December 11, 2009. The Company received services from CMCP under this agreement since the Mergers. Laird Q. Cagan, the Managing Director and 50% owner of CMCP, served as a member of the Company’s Board of Directors until his resignation in May 2009. During 2009, the Company paid $85,500 in fees under this contract, including amounts paid for early termination of this contract in June 2009.

Merger-Related Transactions

In connection with the Mergers on May 7, 2007, the Company assumed the obligation of ADS to pay Chadbourn Securities, Inc., a NASD licensed broker-dealer for which Mr. Laird Cagan (at that time a director and significant shareholder of the Company) served as a registered representative and Managing Director, $1,195,430 in placement fees and expense reimbursements relative to the previous securities offering of ADS. This amount has been paid in full.

Immediately prior to the Mergers, ADS issued to its placement agents 1,860,001 warrants to purchase Class B membership units of ADS. Included were (i) warrants to purchase 3,825 Class B membership units of ADS issued to Michael McTeigue, an executive officer of ADS, (ii) warrants to purchase 83,354 Class B membership units of ADS issued to Chadbourn Securities, Inc., a NASD licensed broker-dealer for which Laird Q. Cagan served as a registered representative and Managing Director, and (iii) warrants to purchase 696,094 Class B membership units of ADS issued to Laird Q. Cagan, a former member of the Company’s Board of Directors and the then-beneficial owner of 7.7% of the Company’s Common Stock. These warrants were exchanged in the Mergers for warrants exercisable for 1,860,001 shares of Common Stock of the Company. The Company has accounted for this as an offering cost applicable to paid-in capital and therefore will not record any compensation expense on these warrants. At December 31, 2010, 1,092,453 warrants remained unexercised, at a weighted average exercise price of $1.30 per share of Common Stock, and expire May 7, 2012.

Relationships with Li Xiangdong

During the third quarter of 2009, the Company conducted its enhanced oil recovery and production business prior to incorporation of its Chinese joint venture company, Beijing Dong Fang Ya Zhou Petroleum Technology Service Company Limited (Dong Fang), through an arrangement with Tongsheng, a subsidiary of the family owned business of Mr. Li Xiangdong (LXD). Upon the incorporation of Dong Fang in China on September 24, 2009, LXD became a 24.5% interest owner in Dong Fang. The patent application rights and related technology for the specialty chemicals and processes in this business have been contributed to Dong Fang by LXD. The original arrangement with Tongsheng was necessary because, pending the incorporation of Dong Fang, the Company was not licensed in China to purchase, blend or sell chemicals. Dong Fang does not presently have a license to manufacture finished chemicals. Under the most current arrangement with Tongsheng for finished product sales, Tongsheng purchases raw chemicals from Dong Fang, manufactures specialty blends of chemicals using technology developed by LXD, and sells the finished product to the Company’s customers. Tongsheng remits to the Company revenues it collects in advance of delivering finished product to customers and bills the Company for the related costs.

Oyo Field Transaction with CAMAC Energy Holdings Limited and Affiliate (CEHL)

See Note 5 regarding the Oyo Field transaction in April, 2010, which resulted in a change in control of the Company and began a related party relationship with the new majority owner and additional parties. Dr. Kase Lawal, a member of the Company’s Board of Directors, is the Chairman and Chief Executive Officer of CEHL. Dr. Lawal also owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CAMAC Energy Holdings Limited. As a result, Dr. Lawal may be deemed to have an indirect material interest in agreements related to the Oyo Field involving CEHL.

Technical Services Agreement with CEHL

On April 7, 2010, CEHL entered into a technical services agreement with the Company to provide the Company with certain technical services with respect to the Oyo Field. In consideration for these services, the Company will pay CEHL (i) an initial monthly service fee of $400,000 per month for the initial three months, plus out-of-pocket expenses, commencing immediately following the closing, with the monthly service fee to be negotiated after the initial three months, and (ii) $1.6 million for service-related expenses incurred by CEHL prior to the closing, due and payable from proceeds received by the Company under the PSC following the closing. The technical service agreement has an initial term of five years, but is terminable upon 30 days’ prior written notice by the Company. The services agreement is expected to be terminated by March 31, 2011.

Right of First Refusal Agreement with CEHL

On April 7, 2010, the Company and CEHL entered into a Right of First Refusal Agreement, pursuant to which, for a period of five years following that date, CEHL has granted to the Company a right of first refusal with respect to any and all licenses, leases and other contract rights for the exploration or production of oil or natural gas currently held by or hereafter acquired by or arising and inuring to CEHL that CEHL offers for sale, transfer, license or other disposition, other than such sales that occur in the ordinary course of business, subject to certain terms and conditions as set forth therein.

Oyo Field Supplemental Agreement with CEHL

On April 7, 2010, CEHL, Allied Energy PLC, a wholly-owned subsidiary of CEHL (“Allied”), and CAMAC Petroleum Limited, the Company’s wholly-owned Nigerian subsidiary (“CPL”), entered into the Oyo Field Agreement (the “Supplemental Agreement”) to provide certain management rights as it relates to the Contract Rights. In addition, the parties agreed that if any non-Oyo Field operating costs incurred prior to the date of the Supplemental Agreement exceed $80,000,000, then Allied shall indemnify CPL for any decrease in CPL’s allocation of “profit oil” and “cost oil” from the Oyo Field from what would have otherwise been allocated to CPL in the absence of such prior non-Oyo Field operating costs in excess of $80,000,000. The Supplemental Agreement also provides that CEHL will indemnify CPL for any negative effect on CPL’s share of “profit oil” in certain circumstances. The Supplemental Agreement expires when the Oyo Field has been abandoned and all applicable filing and reporting requirements relating to CPL’s interest in the Oyo Field have been satisfied or are no longer applicable.

On February 15, 2011, Allied, CEHL and CPL entered into the Amended and Restated Oyo Field Agreement Hereby Renamed OML 120/121 Management Agreement (the “Management Agreement”). Under the Management Agreement, the arrangements entered into pursuant to the Supplemental Agreement were extended to cover the entirety of OML 120/121 and that the indemnities described above with respect to non-Oyo Field operating costs provided for under the Oyo Field Agreement were removed.

Registration Rights Agreements with CEHL

On April 7, 2010, the Company and CEHL entered into a Registration Rights Agreement, pursuant to which the Company was required to prepare and file with the SEC a registration statement on Form S-3 covering the resale of the Consideration Shares, in addition to providing unlimited “piggyback” registration rights to CEHL with respect to the Consideration Shares, in each case, subject to certain limitations and conditions. If any Consideration Shares were not covered by a registration statement within 18 months following the closing date, the Company would be required to pay liquidated damages to CEHL. As required, the Company filed a related Form S-3 with the SEC on May 21, 2010, which became effective on June 4, 2010.

On February 15, 2011, the Company and CEHL entered into a Registration Rights Agreement (the “Registration Rights Agreement”), pursuant to which the Company agreed to prepare and file with the SEC one or more registration statements covering the resale of any and all shares of the common stock of the Company issued to Allied under an option-based consideration structure pursuant to the Purchase Agreement defined below (related to the acquisition of the non-Oyo portion of OML 120/121), in addition to providing certain “piggyback” and other registration rights to CEHL with respect to the shares issued, in each case, subject to certain limitations and conditions. Each registration statement must be filed within 15 days of the Company’s receipt of Allied’s election to receive shares under the Purchase Agreement (subject to such notice being received within 15 days of the occurrence of a milestone under the Purchase Agreement). If any shares are not covered by a registration statement within 90 days following the required filing date of the registration statement, then the Company is required to pay liquidated damages to CEHL.

OML 120/121 Agreement with CAMAC Energy Holdings Limited and Affiliates

On December 13, 2010, the Company entered into a Purchase and Continuation Agreement (the “Purchase Agreement”) with CEHL, superseding earlier related agreements. Pursuant to the Purchase Agreement, the Company agreed to acquire CEHL’s full remaining interest (the “OML 120/121 Transaction”) in the OML 120/121 PSC (the “Non-Oyo Contract Rights”). In April 2010 the Company had acquired from CEHL the Oyo Contract Rights in the OML 120/121 PSC. The OML120/121 Transaction closed on February 15, 2011. Upon consummation of the acquisition of the Non-Oyo Contract Rights under the Purchase Agreement, the Company acquired CEHL’s full interest in the OML 120/121 PSC.

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 Energy Plc upon the closing of the OML 120/121 Transaction on February 15, 2011. The Company has the option to elect to retain the Non-Oyo Contract Rights upon payment of additional consideration to Allied as follows:

a.	First Milestone: Upon commencement of drilling of the first well outside of the Oyo Field under the PSC, the Company may elect to retain the Non-Oyo Contract Rights upon payment to CEHL of $5 million (either in cash, or at Allied’s option, in shares);

If any of the above 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 CAMAC retaining all consideration paid by the Company to date.

The Purchase Agreement contained the following conditions to the closing of the Transaction: (i) CAMAC Petroleum Limited (subsidiary of the Company), CAMAC International (Nigeria) Limited (“CINL”), Allied, and Nigerian Agip Exploration Limited (“NAE”) must enter into a Novation Agreement in a form satisfactory to the Company and CAMAC Energy Holdings Limited and that contains a waiver by NAE of the enforcement of Section 8.1(e) of the PSC (providing for the continued waiver by NAE of its entitlement to “profit oil” in favor of Allied), and that notwithstanding anything to the contrary contained in the PSC, the profit sharing allocation set forth in the PSC shall be maintained after the consummation of the Transaction; (ii) the Company, and CEHL must enter into a registration rights agreement with respect to any shares issued by the Company to Allied at its election as consideration upon the occurrence of any of the above-described milestone events, in a form satisfactory to the Company and CEHL; and (iii) the Oyo Field Agreement, dated April 7, 2010, by and among the Company, CEHL and Allied, must be amended in order to remove certain indemnities with respect to Non-Oyo Operating Costs (as defined therein). In addition, CEHL must deliver the Data and certain equipment to the Company in as-is condition. The Company agreed to limited waivers of certain of these closing conditions under the Limited Waiver Agreement.

Limited Waiver Agreement

On February 15, 2011, the Company, CPL, CAMAC Energy Holdings Limited, CAMAC International (Nigeria) Limited (“CINL”), and Allied entered into a Limited Waiver Agreement Relating to Purchase and Continuation Agreement (the “Limited Waiver Agreement”). Under the Limited Waiver Agreement, the Company and CPL agreed to waivers of certain conditions to closing under the Purchase and Continuation Agreement, dated December 10, 2010, among the Company, CPL, and CEHL (the “Purchase Agreement”), permitting CEHL to cure a certain lien (the “Lien”) and deliver certain data (the “Data”) within ten days of the closing of the Purchase Agreement. The Company also indefinitely waived the requirement that CEHL deliver certain equipment and related materials. The parties agreed that if CEHL fails to discharge the Lien and deliver the Data within ten business days of the closing of the Purchase Agreement, the Company may rescind and terminate the Purchase Agreement, subject to the approval of NAE, and in any event elect to receive a refund with interest of the initial $5 million cash payment made in connection with closing or seek indemnification and other claims without regard to certain limitations on indemnification in the Purchase Agreement.

Second Novation Agreement

On February 15, 2011, the Non-Oyo Contract Rights were assigned and assumed pursuant to a Second Agreement Novating Production Sharing Contract (the “Second Novation Agreement”) by and among Allied, CINL, Nigerian NAE, and CPL. The Second Novation Agreement provides for the novation of the Non-Oyo Contract Rights from CEHL to CPL, a wholly-owned subsidiary of the Company, and consent to the novation by NAE, the operator under the OML 120/121 PSC. The Second Novation Agreement further provides for the continued waiver by NAE of its entitlement to “profit oil” in favor of Allied pursuant to Section 8.1(e) of the OML 120/121 PSC, and that notwithstanding anything to the contrary contained in the OML 120/121 PSC, the profit sharing allocation set forth in the OML 120/121 PSC shall be maintained after the consummation of the Transaction.

Transactions with Related Parties

	As of				As of
	December 31,				December 31,
(In thousands)	2010		2009		2010		2009
	Receivables		Receivables		Payables		Payables
EORP related parties	$	39	$	55	$	-	$	538
CEHL		-		-		2,244		-
U.S. executive bonuses		-		-		400		200
Total	$	39	$	55	$	2,644	$	738

	Years Ended
	December 31,
(In thousands)		2010		2009
	Purchases Charged to Income
CEHL	$	3,471	$	-

NOTE 21. - SUBSEQUENT EVENTS

As discussed in Note 20, the Company completed the OML 120/121 Transaction on February 15, 2011.

SUPPLEMENTAL QUARTERLY FINANCIAL DATA

	First			Second			Third			Fourth
(In thousands except per common share data)	Quarter			Quarter			Quarter			Quarter
2010
Revenues - sales and serivces	$	77		$	12,343		$	8,820		$	10,372
Gross Profit	$	19		$	323		$	2,737		$	2,420
Impairment of assets (loss)	$	-		$	-		$	(186,235	)	$	-
Operating Loss	$	(3,318	)	$	(3,183	)	$	(188,714	)	$	(34,998	)
Net Loss	$	(3,174	)	$	(3,172	)	$	(188,557	)	$	(35,565	)
Basic and diluted net loss per common share	$	(0.07	)	$	(0.02	)	$	(1.32	)	$	(0.25	)


2009
Revenues - sales and serivces	$	-		$	-		$	56		$	11
Gross Profit	$	-		$	-		$	3		$	12
Impairment of assets (loss)	$	-		$	-		$	-		$	(219	)
Operating Loss	$	(2,938	)	$	(2,150	)	$	(2,696	)	$	(3,804	)
Net Loss	$	(2,922	)	$	(2,159	)	$	(2,644	)	$	(3,764	)
Basic and diluted net loss per common share	$	(0.07	)	$	(0.05	)	$	(0.06	)	$	(0.09	)

(1)	The Company started recognizing crude oil revenues in the second quarter of 2010 as a result of the purchase of the Oyo Contract Rights.

(2)	The Company recognized a non-cash write down of the net book value of our oil and gas properties in the third quarter of fiscal 2010 as discussed in Note 7.

(3)	The Company incurred a workover expense of $30.7 million related to Oyo # 5 well in the fourth quarter of 2010.

SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES

The supplemental data below reports information for our oil and gas producing activities.

Estimated Net Proved Crude Oil Reserves

The following estimates of the net proved crude oil reserves in Nigeria are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

Table I - Proved Reserves - Crude Oil
	Consolidated Subsidiaries
(Thousands of barrels)	Africa			Total
December 31, 2009		-			-
Change for year due to:
Revisions		17			17
Improved recovery		-			-
Purchases		5,377			5,377
Extensions and discoveries		-			-
Sales of minerals in place		-			-
Production		(106	)		(106	)
Total change for year 2010		5,288			5,288
December 31, 2010		5,288			5,288

Developed reserves
December 31, 2009		-			-
December 31, 2010		387			387

Undeveloped reserves
December 31, 2009		-			-
December 31, 2010		4,901			4,901

Capitalized Costs

The Company follows the successful efforts method of accounting for capitalization of costs of oil and gas producing activities. Amounts below include only activities classified as exploration and producing.

Table II - Capitalized Costs - Oil and Gas Activity
	Consolidated Subsidiaries
(In thousands)	Africa		Asia		Total
As of December 31, 2010
Proved properties	$	206,212	$	-	$	206,212
Unproved properties		-		228		228
Support equipment and facilities		-		236		236
Total gross		206,212		464		206,676
Accumulated depreciation, depletion and
amortization		1,917		168		2,085
Net capitalized costs	$	204,295	$	296	$	204,591

Costs Incurred

Costs incurred include capitalized and expensed amounts for the year excluding support equipment and facilities.

Table III - Costs Incurred - Oil and Gas Activity
	Consolidated Subsidiaries
(In thousands)	Africa		Asia		Total
Year ended December 31, 2010
Proved property acquisition	$	394,537	$	-	$	394,537
Unproved property acquisition		-		-		-
Exploration		-		901		901
Development		-		-		-
Total costs incurred	$	394,537	$	901	$	395,438

Results of Operations

Results of operations includes activity allocable to oil and gas exploration and producing operations.

Table IV - Results of Operations for Exploration and Producing Operations
	Consolidated Subsidiaries
(In thousands)	Africa			Asia			Total
Year ended December 31, 2010
Revenues	$	31,409		$	-		$	31,409
Production and other costs		(25,966	)		-			(25,966	)
Exploration expenses		-			(823	)		(823	)
Impairment of assets		(186,235	)		-			(186,235	)
Depreciation, depletion and amortization		(4,007	)		(85	)		(4,092	)
Other operating expenses		(30,699	)		(1,475	)		(32,174	)
Results of operations before income taxes		(215,498	)		(2,383	)		(217,881	)
Income tax expense		(423	)		1			(422	)
Results of operations	$	(215,921	)	$	(2,382	)	$	(218,303	)

Standardized Measure of Discounted Future Net Cash Flows

Future net cash flows below are computed using first day of the month average commodity prices, year-end costs and statutory tax rates (adjusted for tax credits and other items) that relate to our existing proved crude oil reserves. Amounts below for production sold and production costs exclude royalties.

Table V - Standardized Measure of Discounted Future Net Cash Flows - Proved Reserves

	Consolidated Subsidiaries
(In thousands)	Africa			Total
As of December 31, 2010
Future cash inflows from production sold	$	418,850		$	418,850
Future production costs		(226,759	)		(226,759	)
Future development costs		(45,000	)		(45,000	)
Future income taxes		(20,050	)		(20,050	)
Future net cash flows before discount		127,041			127,041
Discount at 10% annual rate		(31,345	)		(31,345	)
Standardized measure of discounted
future net cash flows	$	95,696		$	95,696

Change in Standardized Measure of Discounted Future Net Cash Flows

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

Table VI - Changes in Standardized Measure of Discounted Future Net Cash Flows

	Consolidated Subsidiaries
(In thousands)	Africa			Total
Standardized measure, December 31, 2009	$	-		$	-
Sales/production net of production costs		(5,891	)		(5,891	)
Development costs incurred		-			-
Purchases of reserves		98,961			98,961
Sales of reserves		-			-
Net change in sale prices and production costs on
future production		5,970			5,970
Changes in estimated future development costs		(2,730	)		(2,730	)
Extensions, discoveries, improved recovery and
changes in production rates		-			-
Revisions of previous quantity estimates		(1,682	)		(1,682	)
Accretion of discount		4,773			4,773
Net change in income tax		(3,705	)		(3,705	)
Net change for the year		95,696			95,696
Standardized measure, December 31, 2010	$	95,696		$	95,696

Table VII - Unit Prices
	Consolidated
	Subsidiaries
	Africa
Sales revenue per barrel of crude oil
2010	$	85.16

Production costs per barrel of net crude oil production
2010	$	34.54

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 Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Management of the Company, with the participation of its CEO and CFO, 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 CFO 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, 2010 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 CFO, concluded that our internal control over financial reporting was effective as of December 31, 2010.

RBSM LLP, the independent registered public accounting firm that has audited the financial statements included in this Report, has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2010 which is given below.

RBSM LLP

CERTIFIED PUBLIC ACCOUNTANTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

CAMAC Energy Inc.

Houston, TX

We have audited CAMAC Energy Inc. and its subsidiaries (the "Company") internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles (United States). A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, CAMAC Energy Inc. and its subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of CAMAC Energy Inc. and its subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2010, and our report dated March 10, 2011 expressed an unqualified opinion.

/s/ RBSM LLP

New York, New York

March 10, 2011

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, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE

The information required by this item is incorporated herein by reference to the 2011 Proxy Statement or Form 10-K/A which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.

ITEM 11. EXECUTIVE COMPENSATION

Information called for by Item 11 of Form 10-K will be set forth in the 2011 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

Information called for by Item 12 of Form 10-K will be set forth in the 2011 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 2011 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 2011 Proxy Statement or Form 10-K/A, which is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents Filed as Part of this Report:

(1,2) Financial Statements and Schedules.

The following financial documents of CAMAC Energy Inc. are filed as part of this report under Item 8:

Consolidated Balance Sheets – December 31, 2010 and 2009

Consolidated Statements of Operations – For the years ended December 31, 2010, 2009 and 2008

Consolidated Statements of Comprehensive Income (Loss) – For the years ended December 31, 2010, 2009 and 2008

Consolidated Statements of Equity (Deficiency) – For the years ended December 31, 2010, 2009, and 2008

Consolidated Statements of Cash Flows – For the years ended December 31, 2010, 2009 and 2008

Notes to Consolidated Financial Statements

Supplemental Quarterly Financial Data

Supplemental Data on Oil and Gas Exploration and Producing Activities

(3) EXHIBITS

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).

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. *

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 B Warrant (incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed on February 12, 2010).

4.7		Form of Series C and Series D Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on March 3, 2010).

4.8		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).

4.9		Form of Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on December 23, 2010).

4.10		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		Company Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).

10.5		Company 2009 Equity Incentive Plan form of Stock Option Agreement. *

10.6		Company 2009 Equity Incentive Plan form of Restricted Shares Grant Agreement. *

10.7		Subscription Agreement, dated March 2, 2009, by and between the Company and Richard Grigg (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K (No. 000-52770) filed March 4, 2009).

10.8		Consulting Agreement dated February 28, 2007, by and between Christopher B. Sherwood and IMPCO (incorporated by reference to Exhibit 10.9 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).

10.9		Consulting Agreement dated February 28, 2007, by and between Dr. Y.M. Shum and IMPCO (incorporated by reference to Exhibit 10.10 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).

10.10		Executive Employment Agreement dated September 29, 2006, by and between Frank C. Ingriselli and the Company (incorporated by reference to Exhibit 10.11 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). *

10.11		Executive Employment Agreement dated September 29, 2006, by and between Stephen F. Groth and the Company (incorporated by reference to Exhibit 10.12 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). *

10.12		Amended and Restated Employment Agreement, dated January 27, 2009, entered into by and between the Company and Richard Grigg (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K (No. 000-52770) filed on February 3, 2009). *

10.13		Contract of Engagement, dated January 27, 2009, entered into by and between the Company and KKSH Holdings Ltd. (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K (No. 000-52770) filed on February 3, 2009). *

10.14		Employment Agreement, dated April 22, 2009, entered into by and between the Company and Jamie Tseng (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K (No. 000-52770) filed on April 28, 2009). *

10.15		Lease, dated December 1, 2006, by and between Station Plaza Associates, and IMPCO (incorporated by reference to Exhibit 10.13 of our Form 10-SB (No. 000-52770) filed on August 15, 2007).

10.16		First Amendment to Lease, effective September 10, 2008, entered into by and between the Company and Station Plaza Associates (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K (No. 000-52770) filed on September 18, 2008).

10.17		Tenancy Agreement, dated June 12, 2009, by and between Bluewater Property Management Co., Ltd. and the Company (incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q (No. 000-52770) filed on August 6, 2009).**

10.18		Contract for Cooperation and Joint Development, dated August 23, 2006, by and between Chifeng Zhongtong Oil and Natural Gas Co., Ltd. and Inner Mongolia Production Company (HK) Ltd. (incorporated by reference to Exhibit 10.18 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). ***

10.19		Agreement on Joint Cooperation dated May 31, 2007, by and between Sino Geophysical Co., Ltd. and the Company (incorporated by reference to Exhibit 10.20 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). ***

10.20		Production Sharing Contract for Exploitation of Coalbed Methane Resources in Zijinshan Area, Shanxi Province, The People’s Republic of China, dated October 26, 2007, by and between Pacific Asia Petroleum, Ltd. and China United Coalbed Methane Corp. Ltd. (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K (No. 000-52770) filed on October 31, 2007). ***

10.21		The Articles of Association of the Chinese-foreign Equity Joint Venture Inner Mongolia Sunrise Petroleum Co Ltd. (incorporated by reference to Exhibit 10.21 of our Form 10-SB/A (No. 000-52770) filed on October 12, 2007). **

10.22		The Contract of the Chinese-Foreign Equity Joint Venture Inner Mongolia Sunrise Petroleum Co. Ltd., by and between Beijing Jin Run Hang Da Technology Company Ltd. and Inner Mongolia Production Company (HK) Ltd., dated October 25, 2006 (incorporated by reference to Exhibit 10.22 of our Form 10-SB/A (No. 000-52770) filed on October 12, 2007). **

10.23		Amendment to the Contract of the Chinese-Foreign Equity Joint Venture Inner Mongolia Sunrise Petroleum Co. Ltd., and Promissory Note, by and between Beijing Jin Run Hang Da Technology Company Ltd. and Inner Mongolia Production Company (HK) Ltd., dated December 31, 2009.

10.24		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).

10.25		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).

10.26		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).

10.27		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).

10.28		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).

10.29		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).*

10.30		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).*

10.31		Heads of Agreement, dated October 11,2010, by and among CAMAC Energy Inc., CAMAC Energy Holdings Limited, Allied Energy Resources Nigeria Limited, and CAMAC International (Nigeria) Limited (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on October 12, 2010).

10.32		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).

10.33		Form of Securities Purchase Agreement (incorporated by reference to Exhibit 10.1 of our Current Report filed on December 23, 2010).

10.34		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).

10.35		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).

10.36		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).

10.37		Amended and Restated Employment Agreement effective March 8, 2011, by and between Abiola L. Lawal and the Company*

21.1		Subsidiaries of the Company

23.1		Consent of RBSM LLP, Independent Registered Public Accounting Firm, filed herewith.

23.2		Consent of Netherland, Sewell & Associates, Inc.

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 Chief Financial 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 Chief Financial 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 Netherland, Sewell & Associates, Inc.

* Indicates a management contract or compensatory plan or arrangement.

**	English translation of executed Chinese original document included. Document provides that in the event of any inconsistencies between the Chinese and English versions of these documents, the Chinese versions shall govern.

***	Document provides that inconsistencies between the Chinese and English versions to be resolved in accordance with Chinese law.

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: March 10, 2011

	CAMAC Energy Inc.

	By:	/s/ Byron A. Dunn
		Byron A. Dunn
		President and Chief Executive Officer
		(Principal Executive Officer)

	By:	/s/ Abiola L. Lawal
		Abiola L. Lawal
		Chief Financial Officer
		(Principal Financial and Accounting 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.

Signature	Title	Date

/s/ Byron A. Dunn	Director, President and Chief Executive Officer	March 10, 2011
Bryon A. Dunn	(Principal Executive Officer)

/s/ Abiola L. Lawal	Chief Financial Officer	March 10, 2011
Abiola L. Lawal	(Principal Financial and Accounting Officer)

/s/ Dr. Lee Brown	Director	March 10, 2011
Dr. Lee Brown

/s/ Dr. Kase Lukman Lawal	Director	March 10, 2011
Dr. Kase Lukman Lawal

/s/ William E. Dozier	Director	March 10, 2011
William E. Dozier

/s/ John Hofmeister	Director	March 10, 2011
John Hofmeister

/s/ Hazel O’leary	Director	March 10, 2011
Hazel O’Leary

Attached files

Erin Energy Corp. Reports

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