	Years Ended December 31,
(In thousands)	2013			2012			2011			2010			2009
Statement of Income Data
Revenues	$	63,736		$	74,667		$	37,922		$	20,229		$	67
Net loss attributable to CAMAC Energy Inc.	$	(43,525	)	$	(29,529	)	$	(24,913	)	$	(230,468	)	$	(11,489	)
Net loss per common share attributable to CAMAC Energy Inc.:
Basic	$	(0.05	)	$	(0.05	)	$	(0.07	)	$	(0.80	)	$	(0.11	)
Diluted	$	(0.05	)	$	(0.05	)	$	(0.07	)	$	(0.80	)	$	(0.11	)
Cash Flow Data
Net cash (used in) provided by operating activities	$	(36,625	)	$	9,434		$	(14,654	)	$	8,572		$	(6,872	)

	As of December 31,
(In thousands)	2013			2012			2011			2010			2009
Balance Sheet Data
Working capital	$	(39,704	)	$	(4,610	)	$	(5,380	)	$	1,650		$	3,910
Property plant and equipment, net	$	435,787		$	363,724		$	196,222		$	204,979		$	451
Total assets	$	454,224		$	377,043		$	230,870		$	247,843		$	7,436
Note payable - related party	$	6,496		$	872		$	6,000		$	-		$	-

The above presented earnings per share amounts reflect the effect of the Stock Dividend paid in February 2014.

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

The following discussion of the Company’s historical performance and financial condition should be read together with Part II, Item 6, “Selected Financial Data” and the consolidated financial statements and related notes in Part II, Item 8 of this Report and in conjunction with the 2013 Form 10-K filed March 14, 2014. This discussion contains forward-looking statements based on the views and beliefs of our management, as well as assumptions and estimates made by our management. These statements by their nature are subject to risks and uncertainties, and are influenced by various factors. As a consequence, actual results may differ materially from those in the forward-looking statements. See Item 1A of our 2013 Form 10-K for the discussion of risk factors.

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

The Company’s operating subsidiaries include CAMAC Energy Ltd., CAMAC Petroleum Limited, CAMAC Energy International Ltd., CAMAC Energy Ghana Limited, CAMAC Energy Kenya Limited, CAMAC Energy Gambia A2 Ltd. and CAMAC Energy Gambia A5 Ltd. The Company also conducts certain business transactions with its majority shareholder, CAMAC Energy Holdings Limited (“CEHL”), and its affiliates, which include Allied Energy Plc (“Allied”). See “Note 15 – Related Party Transactions” of the Notes to Consolidated Financial Statements for details of these transactions.

The Company operates as an independent oil and gas exploration and production company focused on energy resources in Africa.

The Company’s asset portfolio consists of nine licenses across four countries covering an area of approximately 43,000 square kilometers (approximately 10 million acres). The Company owns producing properties and conducts exploration activities in Nigeria, conducts explorations activities as an operator onshore and offshore Kenya, and conducts exploration activities as an operator offshore The Gambia.

In August 2012, the Company divested its wholly owned Hong Kong subsidiary Pacific Asia Petroleum Limited for net cash consideration of $2.4 million and 9.6 million fully paid ordinary shares, net of selling expenses, of Leyshon Resources Limited, a natural resources mining company based in Beijing, China. The Leyshon shares had a fair market value of $1.9 million, and have since been sold. As a result of the transaction, the Company is reporting its China operations, including other inactive operations not involved in this sale, for all presented periods in discontinued operations.

From September 2013 to November 2013, the first phase of drilling operations was conducted on the Oyo-7 well. Based on logging-while-drilling (“LWD”) data, the well encountered gross oil pay of 133 feet (net oil pay of 115 feet) and gross gas pay of 103 feet (net gas pay of 93 feet) in the gas cap from the currently producing Pliocene reservoir, with excellent reservoir quality. As a secondary objective, the Oyo-7 well confirmed the presence of hydrocarbons in the deeper Miocene formation. This marked the first time a well had been successfully drilled into the Miocene formation on OML 120. Hydrocarbons were encountered in three intervals totaling approximately 65 feet, as interpreted from the LWD data.

During 2013, the Company completed shooting airborne gravity and magnetic geophysical surveys on its Kenya onshore Lamu Basin blocks L1B and L16. The data acquisition covers essentially the entire 12,129 square kilometers in block L1B and the entire 3,613 square kilometers in block L16 and satisfies the gravity and magnetic survey requirements for each block under the relevant PSC. The Company has signed agreements for both blocks for the acquisition, processing, and interpretation of 2D seismic data.

In February 2014, the Company completed the acquisition of the remaining economic interests that it did not already own in the Production Sharing Contract (“PSC”) covering Oil Mining Leases 120 and 121 (“OMLs 120 and 121” or “OMLs”) located offshore Nigeria, which include the currently producing Oyo Field (the “Allied Assets”), from Allied (the “Allied Transaction”). Pursuant to the terms of the Transfer Agreement, the Company, as partial consideration for the Allied Assets, paid $85.0 million in cash to Allied, issued 497,454,857 shares of the Company’s common stock to Allied and delivered a $50.0 million Convertible Subordinated Note (the “Convertible Subordinated Note”) to Allied under which $25.0 million was deemed to be advanced.

Revenue is recognized when a lifting (sale) occurs. Crude oil revenues for 2013 were $63.7 million, as compared to revenues of $74.7 million and $37.9 million for 2012 and 2011, respectively. In 2013, the Company sold approximately 591,000 net barrels of oil at an average price of $107.84/Bbl. In 2012, the Company sold approximately 683,000 net barrels of oil at an average price of $109.32/Bbl. In 2011, the Company sold approximately 337,000 net barrels of oil at an average price of $112.91/Bbl. The decrease in revenues in 2013 compared to 2012 was primarily due to the natural decline in production, leading to lower sales volumes. In addition, a lifting did not occur during the fourth quarter of 2013 as compared to 2012. The increase in revenues in 2012 compared to 2011 was primarily due to additional revenues recorded from the acquired Allied Assets.

During 2013, 2012 and 2011, the net daily production from the Oyo Field was approximately 2,000 barrels of oil per day (“BOPD”), 2,400 BOPD and 3,300 BOPD, respectively.

Production costs were $70.4 million for 2013, as compared to $41.6 million in 2012 and $30.9 million for 2011. Production costs include costs directly related to the production of hydrocarbons. Such costs are capitalized as a component of crude oil inventory and are reflected in operating costs and expenses when inventory is sold. Production costs were higher in 2013 as compared to 2012, primarily due to 2013 including twelve months of costs for the acquired Allied Assets, as compared to only six months of costs recorded in 2012 for the same assets. The 2011 production costs include $30.8 million spent for the Oyo-5 well workover.

Exploration expenses were $5.5 million for 2013, as compared to $3.2 million in 2012 and $0.9 million in 2011. Exploration expenses consist of personnel costs, drilling costs for unsuccessful wells, costs for acquiring seismic data and other related costs as required. In 2013, the Company incurred $5.5 million of exploration expenses, including $2.1 million spent at the corporate level for exploration activities, $2.5 million related to Kenya, $0.6 million related to Gambia, and $0.3 million related to Nigeria. In 2012, the Company incurred $3.2 million of exploration expenses, including $1.5 million spent at the corporate level for exploration activities, $1.0 million related to Kenya, $0.5 million related to Gambia, and $0.2 million related to Nigeria. In 2011, the Company incurred $0.7 million at the corporate level and $0.2 million in Nigeria for exploration activities.

Depreciation, depletion and amortization (“DD&A”) expenses for 2013, including accretion, were $16.9 million, as compared to $51.0 million in 2012 and $13.5 million in 2011. The 2013 DD&A expenses decreased as compared to 2012 primarily due to both lower sales volumes and lower depletion rates as a result of the 2012 positive reserve revision. The 2012 DD&A expenses increased as compared to 2011 primarily due to higher sales volumes with regards to the Allied Assets and increased depletion rates. The average depletion rates for 2013, 2012 and 2011, were $28.60/Bbl, $74.70/Bbl and $40.00/Bbl, respectively.

General and administrative expenses for 2013 were $14.5 million, as compared to $11.0 million and $13.3 million for 2012 and 2011, respectively. The increase in general and administrative expenses for 2013 as compared to 2012 was primarily due to higher consulting and legal costs associated with the Allied Transaction. The decrease in general and administrative expenses for 2012 as compared to 2011 was primarily due to lower administrative expenses associated with staffing reductions. The Company incurred non-cash based stock compensation expenses of $2.0 million, $0.7 million, and $2.5 million for the years 2013, 2012, and 2011, respectively.

Other income was $38,000 in 2013, as compared to other expense of $0.6 million and $0.3 million in 2012 and 2011, respectively. In 2013, the Company recognized realized foreign currency gains of $0.3 million, partially offset by $0.2 million in interest expense associated with the Promissory Note with Allied (the “Promissory Note”). In 2012, the Company recognized realized losses of $0.5 million on sale of securities and incurred $0.1 million in interest expenses associated with the Promissory Note. In 2011, the Company incurred other expense of $0.3 million, which included $0.1 million in interest expense and $0.2 million in other adjustments.

Income taxes were nil for the year 2013, 2012, and 2011. The Company did not have any taxable income in the years 2013, 2012 and 2011, and was therefore not subject to Petroleum Profit Taxes.

Losses from continuing operations were $43.5 million in 2013, as compared to losses of $32.7 million and $21.0 million for 2012 and 2011, respectively. In 2013, losses from continuing operations increased by $10.8 million as compared to 2012, primarily as the result of lower sales volumes. In 2012, losses from continuing operations increased by $11.7 million as compared to 2011 primarily as the result of higher depletion expense, partially offset by the additional revenues recorded from the acquired Allied Assets.

In February 2014, the Company’s Common Stock became listed on the Johannesburg Stock Exchange (“JSE”). The Company is required to publish all documents filed with the U.S. Securities and Exchange Commission (“SEC”) on the JSE. The JSE requires that we calculate Headline Earnings Per Share (“HEPS”) which, per the SEC, is considered a non-GAAP measurement.

As defined in the Circular 3/2009 of The South African Institute of Chartered Accountants, headline earnings is an additional earnings number that excludes separately identifiable remeasurements, net of related tax, and related non-controlling interest.

The number of shares used to calculate basic and diluted HEPS is the same as basic and diluted EPS. In the years ended December 31, 2013, 2012, and 2011, there were no separately identifiable remeasurements based on the criteria outlined in circular 3/2009 and headline earnings was the same as net loss per share from continuing operations as disclosed on the audited consolidated statements of operations. Therefore, HEPS for the years ended 2013, 2012 and 2011 were $(0.05), $(0.05) and $(0.07), respectively.

Discontinued operations include the results of operations of the Company’s China business, which was divested in 2012. In 2012, the Company recognized a gain of $4.2 million, net of selling expenses, associated with the sale. For details of the sale and results of operations, see “Note 3 – Discontinued Operations” within the Notes To Consolidated Financial Statements of this Report.

As of December 31, 2013, the Company had a net working capital (current assets minus current liabilities) deficit of $39.7 million.

Net cash used in operating activities was $36.6 million for 2013 as compared to net cash provided by operating activities of $9.4 million for 2012 and net cash used in operating activities of $14.7 million in 2011. The change in net cash flows from operating activities of $46.1 million in 2013 as compared to 2012 was primarily due to both higher production costs and lower revenues in 2013. Production costs increased in 2013 as compare to 2012 because 2013 includes twelve months of costs for the acquired Allied Assets, as compared to only six months of costs recorded in 2012 for the same assets. Revenues decreased in 2013 as compared to 2012 because of the natural decline in production, leading to lower sales volumes. The increase in net cash provided by operating activities of $24.1 million in 2012 as compared to 2011 was primarily due to additional revenues in 2012 recorded from the acquired Allied Assets.

Net cash used in investing activities for 2013 was $0.6 million, compared to net cash provided by investing activities of $1.2 million in 2012, and net cash used in investing activities of $6.9 million in 2011. Net cash used in investing activities of $0.6 million in 2013 consisted primarily of office infrastructure expenditures. In 2012, net cash provided by investing activities consisted primarily of $2.4 million net cash proceeds from the divestiture of the Company’s China operations and $2.4 million of proceeds received from the sale of long-term investments, partially offset by $3.6 million paid for capital expenditures. In 2011, net cash used in investing activities consisted primarily of $7.2 million paid for capital expenditures, partially offset by $0.3 million received for the sales of available for sale securities.

Net cash provided by financing activities was $33.6 million for 2013 as compared to net cash used in financing activities of $20.5 million in 2012 and net cash provided by financing activities of $6.2 million in 2011. Net cash provided by financing activities for 2013, consisted primarily of a $29.2 million positive adjustment to the net assets of Allied in connection with the Allied Transaction and $4.4 million of net borrowings under the Promissory Note with Allied. Net cash used in financing activities in 2012, consisted primarily of a $15.3 million negative adjustment to the net assets of Allied and a $5.1 million of net repayments under the Promissory Note with Allied. Net cash provided by financing activities for 2011 consisted primarily of net borrowings under the Promissory Note with Allied. See below for details of the Promissory Note with Allied.

The Company has a $25.0 million borrowing facility under a Promissory Note with Allied. In August 2014, the Promissory Note was amended to extend the maturity date by one year to July 2015 and to allow for the entire $25.0 million facility amount to be utilized for general corporate purposes. As of December 31, 2013, $6.5 million was outstanding under the Promissory Note. See “Note 9. – Note Payable – Related Party” for additional information regarding the Promissory Note.

In February 2014, the Company completed the Allied Transaction and the First Closing of the Private Placement with the Public Investment Corporation (SOC) Limited, a state-owned company incorporated in the Republic of South Africa (“PIC”), in accordance with the terms of the Transfer Agreement and the Share Purchase Agreement, respectively. In May 2014, the Company completed the Second Closing of the Private Placement with the PIC. In aggregate, the Company received $270.0 million pursuant to the Closing of both the First and Second Private Placements with the PIC. The Company paid Allied a total sum of $170.0 million in cash, resulting in a net $100.0 million retained by the Company.

In September 2014, the Company entered into a Term Loan Facility Agreement (the “Term Loan Facility”) with a Nigerian bank for a five year senior secured term loan providing initial borrowing capacity of up to $100.0 million. The purpose of the facility established pursuant to the Loan Agreement is to provide funding for continued expansion and development of OMLs 120 and 121. For more information on the Term Loan Facility, see “Note 18 – Subsequent Events” within the Notes to the Consolidated Financial Statements.

Although there are no assurances that the Company’s plans will be realized, management believes that the Company will have sufficient capital resources to meet projected cash flow requirements for the next twelve months from the date of filing this report.

In 2013, the Company invested $0.6 million in property and equipment additions primarily for office infrastructure support costs. In 2012, the company invested $3.6 million in property and equipment additions, primarily associated with leasehold acquisition costs of $2.0 million and $1.2 million in The Gambia and Kenya, respectively, and $0.4 million in office infrastructure support costs. In 2011, the Company invested $7.2 million in property and equipment additions, of which $5.0 million was for the acquisition of an economic interest in OML 121 offshore Nigeria.

The following table summarizes the Company’s significant estimated future contractual obligations at December 31, 2013:

The minimum obligations for both Kenya and The Gambia require annual rental payments, training and community fees, all of which have been included in the above table.

In January 2014, a long-term drilling contract was signed for the drillship Energy Searcher. The rig arrived at the Oyo Field offshore Nigeria in June 2014 and has commenced the Oyo Field development campaign. The agreement covers an initial term of one year, with an option to extend the contract for an additional one year. The minimum commitment pursuant to the initial term of the agreement is approximately $86.0 million.

In February 2014, a long-term contract was signed for the floating, production, storage, and offloading vessel (“FPSO”) Armada Perdana, which is the vessel currently connected to the Company’s producing wells Oyo-5 and Oyo-6 in OML 120. The contract provides for an initial term of seven years beginning January 1, 2014, with an automatic extension for an additional term of two years unless terminated by the Company with prior notice. The FPSO can process up to 40,000 barrels of liquid per day, with a storage capacity of approximately one million barrels. The annual minimum commitment per the terms of the agreement is approximately $35.0 million in the first year and approximately $48.0 million thereafter.

We have no off-balance sheet arrangements, other than normal operating leases and employee contracts, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

The following describes the critical accounting policies used by the Company in its financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting; such is the case with accounting for oil and gas activities described below. In those cases, the Company’s results of operations would be different should it implement an alternative accounting method.

The Company follows the successful efforts method of accounting for 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. Possible indicators of impairment include current period losses combined with a history of losses, significant downward oil and gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable. An impairment loss is recognized for assets to be held and used when the estimated undiscounted future cash flows expected to result from the asset, including ultimate disposition, are less than its carrying amount. In the case of oil and gas properties, the Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset. The Company’s cash flow projections into the future include assumptions on variables such as future sales, sales prices, operating costs, economic conditions, market competition, and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount over the fair value of the assets. No impairment charges were recorded for the years ended December 31, 2013, 2012 or 2011, respectively.

The Company accounts for asset retirement obligations in accordance with ASC Topic 410 (Asset Retirement and Environmental Obligations), which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. ASC 410 requires the Company to record a liability for the present value using a credit-adjusted risk free interest rate of the estimated site restoration costs with a corresponding increase to the carrying amount of the related long-lived assets. As of December 31, 2013 and 2012, the Company recognized $20.6 million and $24.8 million, respectively, in asset retirement obligations related to OMLs 120 and 121.

Inventories of crude oil are valued at the lower of cost or market using the first-in, first-out method and include certain costs directly related to the production process.

In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendments in ASU 2013-02 to Topic 220, Comprehensive Income, update, supersede and replace the presentation requirements for reclassifications out of accumulated other comprehensive income in ASUs 2011-05 and 2011-12. ASU 2013-02 requires either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. The new guidance is effective prospectively for reporting periods beginning after December 15, 2012. The Company adopted the guidance required as of January 1, 2013. The required disclosures have been included in Note 5, Accumulated Other Comprehensive Income (Loss) of the Notes to Consolidated Financial Statements.

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting From Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The amendments in ASU 2013-04 to Topic 405, Liabilities, provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for obligations addressed with existing U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation, as well as other information about those obligations. The amendment is effective retrospectively for reporting periods beginning after December 15, 2013. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements.

In April 2013 the FASB issued ASU 2013-07, Liquidation Basis of Accounting. The amendments in ASU 2013-07 to Topic 205, Presentation of Financial Statements, clarify when an entity should apply the liquidation basis of accounting and provide principles for the recognition and measurement of associated assets and liabilities. In accordance with the amendments, the liquidation basis is used when liquidation is imminent. Liquidation is considered imminent when the likelihood is remote that the organization will return from liquidation and either: (a) a plan for liquidation is approved by the person or persons with the authority to make such a plan effective and the likelihood is remote that the execution of the plan will be blocked by other parties; or (b) a plan for liquidation is being imposed by other forces. The amendments in ASU 2013-07 are effective prospectively for entities that determine liquidation is imminent for reporting periods beginning after December 15, 2013, with early adoption permitted. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements.

In July 2013 the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The amendments in ASU 2013-11 to Topic 740, Income Taxes, clarify that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The amendments in ASU 2013-11 are effective prospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. Retrospective application is permitted. The Company is currently evaluating the possible impact of ASU 2013-11, but does not anticipate that it will have a material impact on the Company’s consolidated financial statements.

In April 2014, the Financial Accounting Standards Board (“FASB”) issued updated guidance that changes the criteria for reporting discontinued operations including enhanced disclosure requirements. Under the updated guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization´s operations and financial results. The standards update is effective for fiscal years beginning after December 15, 2014. We will adopt this standards update, as required, beginning with the first quarter of 2015. The adoption of this standards update affects presentation only and, as such, is not expected to have a material impact on our consolidated financial statements.

In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. The objective of this guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising from an entity’s contracts with customers, including qualitative and quantitative disclosures around contracts with customers, significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. The standards update is effective for interim and annual periods beginning after December 15, 2016. We will adopt this standards update, as required, beginning with the first quarter of 2017. The Company is in the process of evaluating the impact, if any, of this guidance on its consolidated financial statements.

In June 2014, the FASB issued updated guidance around share-based compensation. The guidance was issued to clarify the accounting treatment for performance-based stock awards. The update states that companies should not record compensation expense related to an award for which transfer to the employee is contingent on the company’s satisfaction of a performance target until it becomes probable that the performance target will be met. The update does not contain any new disclosure requirements and is effective for interim and annual periods beginning after December 15, 2015. We will adopt this standards update, as required, beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on our consolidated financial statements.

In August 2014, the FASB issued updated guidance on determining when and how reporting entities must disclose going concern uncertainties in its financial statements. The objective of the update is to define management’s responsibility to evaluate, each annual and interim reporting period, whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date the financial statements are issued and to provide related footnote disclosures. The standards update is effective for annual periods ending after December 15, 2016, and interim period thereafter. We will adopt this standards update, as required, beginning with the first quarter of 2017. The Company is in the process of evaluating the impact this guidance will have on its footnote disclosures.

We have audited the accompanying consolidated balance sheets of CAMAC Energy Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 that 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 subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

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

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

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

	As of December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	163		$	3,806
Accounts receivable		1,112			6,103
Crude oil inventory		16,254			2,350
Prepaids and other current assets		856			1,013
Total current assets		18,385			13,272

Property, plant and equipment:
Oil and gas properties (successful efforts method of accounting), net		435,035			363,268
Other property, plant and equipment, net		752			456
Total property, plant and equipment, net		435,787			363,724

Other assets		52			11
Noncurrent assets of discontinued operations		-			36

Total Assets	$	454,224		$	377,043

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	31,668		$	15,112
Accrued expenses		7,446			2,770
Asset retirement obligations		12,479			-
Notes payable - related party		6,496			-
Total current liabilities		58,089			17,882

Asset retirement obligations		8,122			24,832
Long-term notes payable - related party		-			872
Other long-term liabilities		67			55

Total liabilities		66,278			43,641

Commitments and Contingencies

Equity:
Preferred stock $0.001 par value - 50,000,000 shares authorized; none issued and outstanding as of December 31, 2013 and 2012, respectively		-			-
Common stock $0.001 par value - 1,227,894,857 shares authorized; 879,817,093 and 877,515,805 shares outstanding as of December 31, 2013 and 2012, respectively		879			877
Paid-in capital		735,959			637,674
Accumulated deficit		(348,892	)		(305,367	)
Accumulated other comprehensive income (loss)		-			224
Total equity - CAMAC Energy Inc.		387,946			333,408
Noncontrolling interests of discontinued operations		-			(6	)
Total equity		387,946			333,402

Total liabilities and equity	$	454,224		$	377,043

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

	Years Ended December 31,
		2013			2012		2011
Revenues:
Crude oil sales, net of royalties	$	63,736		$	74,667		$	37,922

Operating costs and expenses:
Production costs		70,427			41,555			30,882
Exploratory expenses		5,501			3,236			890
Depreciation, depletion and amortization		16,875			51,002			13,477
General and administrative expenses		14,460			10,998			13,336
Total operating costs and expenses		107,263			106,791			58,585

Operating loss		(43,527	)		(32,124	)		(20,663	)

Other income (expense), net:		38			(582	)		(328	)

Loss from continuing operations before income taxes		(43,489	)		(32,706	)		(20,991	)
Income tax expense		-			-			-
Net loss from continuing operations		(43,489	)		(32,706	)		(20,991	)

Discontinued Operations
Net loss from discontinued operations, net of tax		(36	)		(991	)		(4,012	)
Gain on divestiture, net		-			4,160			-
Net (loss) income from discontinued operations		(36	)		3,169			(4,012	)

Net loss		(43,525	)		(29,537	)		(25,003	)
Noncontrolling interests - discontinued operations		-			8			90

Net loss attributable to CAMAC Energy Inc.	$	(43,525	)	$	(29,529	)	$	(24,913	)

Net (loss) income per common share attributable to CAMAC Energy Inc. - basic:
Continuing operations	$	(0.05	)	$	(0.05	)	$	(0.06	)
Discontinued operations	$	(0.00	)	$	(0.00	)	$	(0.01	)
Total	$	(0.05	)	$	(0.05	)	$	(0.07	)
Net (loss) income per common share attributable to CAMAC Energy Inc. - diluted:
Continuing operations	$	(0.05	)	$	(0.05	)	$	(0.06	)
Discontinued operations	$	(0.00	)	$	(0.00	)	$	(0.01	)
Total	$	(0.05	)	$	(0.05	)	$	(0.07	)
Weighted average common shares outstanding:
Basic		878,710			628,101			376,312
Diluted		878,710			628,101			376,312

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

											Accumulated
					Additional						Other
	Common Stock				Paid-in			Accumulated			Comprehensive			Noncontrolling			Total
	Shares		Amount		Capital			Deficit			Income (Loss)			Interest			Equity
At December 31, 2010		374,014	$	374	$	458,303		$	(250,925	)	$	(120	)	$	(643	)	$	206,989

Stock issued for services		2,045		2		705			-			-			-			707
Exercise of options		786		1		176			-			-			-			177
Vesting of restricted stock		1,488		1		(1	)		-			-			-			-
Stock-based employee compensation		-		-		2,484			-			-			-			2,484
Adjustments to noncontrolling interest		-		-		(733	)		-			-			735			2
Net loss		-		-		-			(24,913	)		-			(90	)		(25,003	)
Other comprehensive income (loss):		-		-														-
Foreign currency loss		-		-		-			-			(31	)		-			(31	)
Unrealized loss on investments, net of taxes		-		-		-			-			(114	)		-			(114	)
At December 31, 2011		378,333		378		460,934			(275,838	)		(265	)		2			185,211

Exercise of options		17		-		3			-			-			-			3
Vesting of restricted stock		1,251		1		-			-			-			-			1
Contingent consideration stock issued		460		1		889			-			-			-			890
Stock-based employee compensation		-		-		739			-			-			-			739
Net loss		-		-		-			(29,529	)		-			(8	)		(29,537	)
Net assets contributed by parent		-		-		190,925			-			-			-			190,925
Shares issued to affiliate		497,455		497		(497	)		-			-			-			-
Allied Transaction adjustments						(15,331	)		-			-			-			(15,331	)
Other comprehensive income (loss):		-		-														-
Foreign currency gain		-		-		12			-			94			-			106
Unrealized gain on investments, net of taxes		-		-		-			-			395			-			395
At December 31, 2012		877,516		877		637,674			(305,367	)		224			(6	)		333,402

Vesting of restricted stock		2,301		2		-			-			-			-			2
Stock-based employee compensation		-		-		2,013			-			-			-			2,013
Realized foreign currency gain		-		-		-			-			(224	)		-			(224	)
Adjustments to noncontrolling interest		-		-		-			-			-			6			6
Net loss		-		-		-			(43,525	)		-			-			(43,525	)
Net assets contributed by parent		-		-		61,205			-			-			-			61,205
Allied Transaction adjustments		-		-		35,067			-			-			-			35,067
At December 31, 2013		879,817	$	879	$	735,959		$	(348,892	)	$	-		$	-		$	387,946

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

	Years Ended December 31,
	2013			2012			2011
Cash flows from operating activities
Net loss	$	(43,525	)	$	(29,537	)	$	(25,003	)

Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization		14,640			49,963			13,530
Asset retirement obligation accretion		2,235			1,047			-
Stock-based compensation		2,013			739			2,484
Currency transaction (gain) loss		(224	)		22			(31	)
Dry hole costs		-			(37	)		2,176
Gain on divestiture, net		-			(4,160	)		-
Other		16			55			-
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(3,046	)		12,836			(8,528	)
Decrease in other current assets		156			649			1,841
(Increase) decrease in inventories		(14,004	)		(1,483	)		72
Increase (decrease) in accounts payable and accrued expenses		5,114			(20,660	)		(1,195	)
Net cash (used in) provided by operating activities		(36,625	)		9,434			(14,654	)

Cash flows from investing activities
Capital expenditures		(602	)		(3,576	)		(7,159	)
Proceeds from divestiture, net		-			2,364			-
Net sales of available for sale securities		-			-			256
Decrease in other assets		-			465			43
Proceeds from the sale long-term investments		-			1,966			-
Net cash (used in) provided by investing activities		(602	)		1,219			(6,860	)

Cash flows from financing activities
Allied Transaction adjustments		29,234			(15,331	)		-
Proceeds from the exercise of stock options		-			3			177
Proceeds (repayments) of note payable - related party, net		4,350			(5,128	)		6,000
Net cash provided by (used in) financing activities		33,584			(20,456	)		6,177

Effect of exchange rate on cash and cash equivalents		-			(17	)		45

Net decrease in cash and cash equivalents		(3,643	)		(9,820	)		(15,292	)
Cash and cash equivalents at beginning of period		3,806			13,626			28,918
Cash and cash equivalents at end of period	$	163		$	3,806		$	13,626

Supplemental disclosure of cash flow information
Cash paid for:
Interest, net	$	99		$	117		$	120
Contingent consideration stock	$	-		$	890		$	-
Supplemental disclosure of non-cash investing and financing activities:
Nonsubsidiary common stock received as partial proceeds from divestiture, net	$	-		$	1,877		$	-
Common stock issued for services	$	-		$	-		$	707
Related party accounts payable, net, settled with related party notes payable	$	1,274		$	-		$	-
Non-cash gain from asset retirement obligation extinguishment	$	5,833		$	-		$	-
Net assets contributed by parent	$	61,205		$	190,925		$	-

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

CAMAC Energy, Inc. (NYSE MKT: CAK, JSE: CME) is an independent exploration and production company engaged in the acquisition and development of energy resources in Africa. The Company’s asset portfolio consists of nine licenses across four countries covering an area of approximately 43,000 square kilometers (approximately 10 million acres). The Company owns producing properties and conducts exploration activities offshore Nigeria, conducts exploration activities offshore Ghana and The Gambia, and both offshore and onshore Kenya.

CAMAC Energy Inc. is headquartered in Houston, Texas and has offices in Nairobi, Kenya, Banjul, The Gambia and Lagos, Nigeria.

The Company’s operating subsidiaries include CAMAC Energy Ltd (“CEL”), CAMAC Petroleum Limited (“CPL”), CAMAC Energy International Limited, CAMAC Energy Ghana Limited, CAMAC Energy Kenya Limited, CAMAC Energy Gambia A2 Limited, and CAMAC Energy Gambia A5 Limited. The terms “we,” “us,” “our,” “Company,” and “our Company” refer to CAMAC Energy Inc. and its subsidiaries and affiliates.

The Company also conducts certain business transactions with its majority shareholder, CAMAC Energy Holdings Limited (“CEHL”), and its affiliates, which include Allied Energy Plc (“Allied”). See “Note 15 – Related Party Transactions” for additional information with regard to these transactions.

The Company’s Executive Chairman of the Board of Directors, and Chief Executive Officer, is a director of each of the above listed related parties. He indirectly owns 27.7% of CEHL, which is the majority shareholder of the Company. As a result, he may be deemed to have an indirect material interest in transactions contemplated with any of the above companies and their affiliates.

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

In August 2012, the Company divested its wholly owned Hong Kong subsidiary Pacific Asia Petroleum Limited for cash and shares of stock. The Company has classified the current and historical results of its China operations, including other inactive operations not involved in this sale, as discontinued operations, net of tax, in the accompanying consolidated statements of operations. See “Note 3 - Discontinued Operations”, for more information regarding the sale.

In January 2014 the Company’s Board of Directors declared a stock dividend on all shares of the Company’s outstanding Common Stock entitling stockholders of record as of the close of business on February 13, 2014, to receive an additional 1.4348 shares of Common Stock for every share of Common Stock held (the “Stock Dividend”). Payment of the Stock Dividend was conditioned on (i) approval of the Company’s stockholders at the special meeting of stockholders to be held on February 13, 2014 of certain proposals related to the Allied Transaction, including a proposal to amend the Company’s certificate of incorporation to increase the number of authorized shares of Common Stock and (ii) approval of the listing of the Company’s Common Stock on the Johannesburg Stock Exchange (“JSE”). On February 13, 2014, the Company held a special meeting of its stockholders to consider and vote upon the proposals mentioned above and other related agenda items. All of the proposals presented at the meeting received the requisite shareholder approval and the approval of the JSE listing was successfully obtained. On February 21, 2014, the Company paid the Stock Dividend pursuant to which each share of stock of record as of the close of business on February 13, 2014, carried the right to receive 1.4348 shares of Common Stock for every one share of Common Stock held.

Due to the large nature of the Stock Dividend (exceeds 25% of the total shares outstanding prior to the distribution), it has been accounted for as a Stock Split. The effect is a retroactive adjustment to the financial statements and associated footnotes as if the dividend had occurred at the beginning of the first period presented.

In February 2014, the Company completed the acquisition of the remaining economic interests that it did not already own in the Production Sharing Contract (“PSC”) covering Oil Mining Leases 120 and 121 (“OMLs 120 and 121”) located offshore Nigeria, which include the currently producing Oyo Field (the “Allied Assets”), from Allied (the “Allied Transaction”). Allied is a subsidiary of CEHL, the Company’s majority shareholder, and deemed to be under common control (transactions between subsidiaries of the same parent). Accordingly, the net assets acquired from Allied were recorded at their respective carrying values as of the acquisition date. The consolidated financial statements, included herein, are presented as though the Allied Transaction had occurred in June 2012, the date Allied Acquired the Allied Assets from an independent third party. See “Note 4 – Acquisitions” for additional information relating to the Allied Assets and “Note 18 – Subsequent Events” for additional information relating to the Allied Transaction.

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

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 include cash on hand, demand deposits and short-term investments with initial maturities of three months or less.

Trade accounts receivable are accounted for at cost less allowance for doubtful accounts. We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2013 and 2012, no allowance for doubtful accounts was necessary.

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. Possible indicators of impairment include current period losses combined with a history of losses, significant downward oil and gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable. An impairment loss is recognized for assets to be held and used when the estimated undiscounted future cash flows expected to result from the asset 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. The Company’s cash flow projections into the future include assumptions on variables such as future sales, sales prices, operating costs, economic conditions, market competition and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount over the fair value of the assets. No impairment charges were recorded for the years ended December 31, 2013, 2012 or 2011, respectively.

The Company accounts for asset retirement obligations in accordance with ASC Topic 410 (Asset Retirement and Environmental Obligations), which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. ASC 410 requires the Company to record a liability for the present value, using a credit-adjusted risk free interest rate, of the estimated site restoration costs with a corresponding increase to the carrying amount of the related long-lived assets. See “Note 8 – Asset Retirement Obligations” for further information.

Inventories of crude oil are valued at the lower of cost or market using the first-in, first-out method and include certain costs directly related to the production process.

Revenues are recognized when a lifting (sale) occurs. The recognition criteria are satisfied when there exists a signed contract with defined pricing, delivery and acceptance (as defined in the contract) of the product or service have occurred, there is no significant uncertainty of collectability, and the amount is not subject to refund. Crude oil revenues are net of royalties.

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 to their net realizable amounts if it is more likely than not that the related tax benefits will not be fully realized.

The Company routinely 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 or expense to recognize in the consolidated financial statements. See “Note 10 – Income Taxes” for further information.

The Company recognizes all stock-based payments to employees, including grants of employee stock options, in the consolidated financial statements based on their grant-date fair values in accordance with ASC Topic 718-10 (Stock Compensation). The Company values its stock options awarded using the Black-Scholes option pricing model, and the restricted stock is valued at the grant date closing market price. Such costs are recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). Stock-based compensation paid to non-employees is valued at the fair value at the applicable measurement date and charged to expense as services are rendered.

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.

In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendments in ASU 2013-02 to Topic 220, Comprehensive Income, update, supersede and replace the presentation requirements for reclassifications out of accumulated other comprehensive income in ASUs 2011-05 and 2011-12. ASU 2013-02 requires disclosure, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. The new guidance is effective prospectively for reporting periods beginning after December 15, 2012. The Company adopted the guidance required as of January 1, 2013. The required disclosures have been included in Note 5, Accumulated Other Comprehensive Income (Loss) of the Notes to Consolidated Financial Statements

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting From Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The amendments in ASU 2013-04 to Topic 405, Liabilities, provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for obligations addressed with existing U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amounts of the obligation, as well as other information about those obligations. The amendment is effective retrospectively for reporting periods beginning after December 15, 2013. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements.

In July 2013 the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The amendments in ASU 2013-11 to Topic 740, Income Taxes, clarify that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, or the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The amendments in ASU 2013-11 are effective prospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013. Retrospective application is permitted. The Company is currently evaluating the possible impact of ASU 2013-11, but does not anticipate that it will have a material impact on the Company’s consolidated financial statements.

In August 2012, the Company divested its wholly owned Hong Kong subsidiary Pacific Asia Petroleum Limited (“PAPL”) for net cash consideration of $2.4 million and 9.6 million fully paid ordinary shares, net of selling expenses, of Leyshon Resources Limited, a natural resources mining company based in Beijing, China. The Leyshon shares had a fair market value of $1.9 million, and have since been sold.

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

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

Results of operations from discontinued operations are as follows (in thousands):

Assets and liabilities of discontinued operations are as follows (in thousands):

In June 2012, Allied purchased the Allied Assets from an independent third party. The Allied Assets were subsequently acquired by the Company in February 2014 as part of the Allied Transaction see “Note 18 – Subsequent Events”. Allied is a wholly owned subsidiary of CEHL, the Company’s majority shareholder, and deemed to be under common control (transactions between subsidiaries of the same parent). The transaction has been accounted for as if CEHL had acquired the Allied Assets and contributed them to the Company. In addition, costs related to the drilling of the Oyo-7 well, incurred by Allied in 2013, are also considered to be contributed to the Company.

The table below shows the carrying values of the net Allied Assets contributed at their respective periods (in thousands):

Because these assets were deemed paid for by CEHL and contributed to the Company, they have been treated as non-cash transactions in the accompanying Consolidated Statements of Cash Flows.

In May 2012, the Company, through a wholly owned subsidiary, entered into four production sharing contracts with the Government of the Republic of Kenya (the “Kenya PSCs”), covering onshore exploration blocks L1B and L16, and new offshore exploration blocks L27 and L28. For all blocks, the Company is the operator, with the Government having the right to participate up to 20%, either directly or through an appointee, in any area subsequent to declaration of a commercial discovery. The Company also has the right to apply for up to two additional two-year exploration periods, with specified additional minimum work obligations, including the acquisition of seismic data and the drilling of one exploratory well on each block during each such additional period. The Company is responsible for all exploration expenditures.

The Kenya PSCs for onshore blocks L1B and L16 each provide for an initial exploration period, now extended through June 2015, with specified minimum work obligations during that period. Prior to the end of the initial exploration period, the Company is required to conduct, for each block, a gravity and magnetic survey and acquire, process and interpret 2D seismic data. The gravity and magnetic survey was completed in April 2013. In December 2013, the Company initiated an Environmental and Social Impact Assessment (“ESIA”) study which was successfully completed in March 2014. In October 2014, the Company signed agreements for both blocks for the acquisition, processing and interpretation of 2D seismic data. The project is expected to be completed in the first half of 2015.

The Kenya PSCs for offshore blocks L27 and L28 each provide for an initial exploration period of three years, through August 2015, with specified minimum work obligations during that period. Prior to the end of the initial exploration period, the Company is required to conduct, for each block, a regional geological and geophysical study, acquire 2D seismic data and acquire, process and interpret 3D seismic data. The Company participated in a multi-client combined gravity / magnetic and 2D seismic survey covering blocks L27 and L28. The survey was successfully completed in March 2014. The processed data is currently being interpreted internally. Further, in March 2014 the Company started the regional geophysical study for these two blocks.

In addition to the minimum work obligations, each of the Kenya PSCs requires annual surface rental payments, training fund payments and contributions to local community development projects.

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

The Gambia Licenses provide for an initial exploration period of four years with specified minimum work obligations during that period. Prior to the end of the initial exploration period, the Company will conduct, on each block, a regional geological study, acquire, process and interpret seismic data, drill one exploration well and evaluate drilling results, with the first two work obligations (regional geological study and 3D seismic data acquisition and processing) due prior to the end of the second year. The Company has the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including the drilling of one exploration well during each additional period for each block. The company has completed a regional geology and geophysical study of both the A2 and A5 blocks.

In addition to the minimum work obligations, The Gambia Licenses require annual rental payments, training and community fees.

The following summarizes the changes in the balances of each component of accumulated other comprehensive income (loss) (in thousands):

In November 2013, the Company achieved both its primary and secondary drilling objectives for the Oyo-7 well. The primary drilling objective was to establish production from the existing Pliocene reservoir. The secondary drilling objective was to confirm the presence of hydrocarbons in the deeper Miocene formation. Hydrocarbons were encountered in three Miocene intervals totaling approximately 65 feet, as interpreted by the logging-while-drilling (“LWD”) data. Management is making plans to further explore the Miocene formation in future wells. The Company’s suspended exploratory well costs were $26.5 million at December 31, 2013 for the costs related to the Miocene exploratory drilling activities. The Company did not have any suspended exploratory well costs at December 31, 2012.

The Company’s asset retirement obligations primarily represent the estimated fair value of the amounts that will be incurred to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include, but are not limited to, estimates of plugging and abandonment costs, estimated future inflation rates and changes in property lives. The inputs are calculated based on historical data as well as current estimated costs.

The following tables summarize the changes and the balances of current and long-term portions in the Company’s asset retirement obligations during the periods (in thousands):

Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying consolidated statements of operations.

In June 2011, CPL, a wholly owned subsidiary of the Company, executed a Promissory Note in favor of Allied. Under the initial terms of the Promissory Note, Allied agreed to make loans to CPL from time to time for purposes of making payments relating to the workover of the Oyo-5 well in an aggregate sum of up to $25.0 million. Interest accrues on the outstanding principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum. In September 2013, the Company and Allied amended the Promissory Note and the Guaranty to add the Company as a borrower, to allow for borrowings of up to $10.0 million for general corporate purposes and to pledge the stock of the subsidiary of CEI that holds the exploration licenses in The Gambia and Kenya as collateral pursuant to an equitable share mortgage arrangement. As of December 31, 2013, the book value of the exploration licenses in The Gambia and Kenya was $3.2 million. Pursuant to the initial terms of the Promissory Note, the outstanding principal amount of all loans was to mature on June 6, 2013. In August 2012, the Promissory Note was amended to extend the maturity date to October 15, 2013, and in March 2013 the Promissory Note was again amended to extend the maturity date to July 15, 2014. In January 2014, Allied agreed to amend the Promissory Note and extend the maturity date to July 15, 2015 in the event the Company is not successful in obtaining external financing arrangements by June 30, 2014. In August 2014, the Promissory Note was amended to extend the maturity date by one year to July 2015, and to allow for the entire $25.0 million facility amount to be utilized for general corporate purposes. The Company has guaranteed all of CPL’s obligations under the Promissory Note. As of December 31, 2013, $6.5 million was outstanding under the Promissory Note.

The Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer indirectly owns 27.7% of CEHL, which is the majority shareholder of the Company. As a result, he is deemed to have an indirect material interest in the transaction contemplated by the Promissory Note. The material facts as to this relationship with Allied were fully disclosed to the Board of Directors prior to Board approval of the transaction.

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):

Significant components of our deferred tax assets are as follows (in thousands):

The majority of the Company’s basis difference in fixed assets and unused capital allowances were generated from its Nigerian operations. The Company’s foreign net operating losses in Nigeria are not subject to expiration, and can be carried forward indefinitely. The foreign operating losses in The Gambia and Kenya are included in the respective subsidiaries cost oil accounts, which will be offset against future taxable revenues.

Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. Based on current facts and circumstances related to its Nigerian operations, Management has determined that it cannot demonstrate that it is more likely than not that the Nigerian losses and unutilized capital allowances will be utilized to reduce the Company’s petroleum profit tax liability within the foreseeable future. Furthermore, since the Company does not currently have any revenue generating activities either in the U.S. or in any of its non-Nigerian subsidiaries, it cannot demonstrate that it is more likely than not that any of the related deferred tax assets will be utilized in the foreseeable future.

On the basis of this assessment, valuation allowances of $264.0 million and $243.8 million were recorded as of December 31, 2013 and 2012, respectively.

At December 31, 2013 and 2012, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.

The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:

Under the Company’s amended 2009 Equity Incentive Plan (“2009 Plan”), the Company may issue restricted stock awards and stock options to result in issuance of a maximum aggregate of 100,000,000 shares of Common Stock. Options awarded expire between five and 10 years from date of grant, or shorter term as fixed by the Board of Directors. On February 18, 2014, the Company executed the amendment to the 2009 Plan thereby increasing the number of shares that may be granted thereunder to 100,000,000.

In 2013, the Company granted a total of 8,003,874 stock options with vesting periods from three years to five years.

A summary of stock option activity for the year ended December 31, 2013, is presented below.

The total intrinsic values of options outstanding and options exercisable were $0.9 million at December 31, 2013. The total intrinsic values realized by recipients on options exercised were $0 in 2013, $0 in 2012, and $0.2 million in 2011.

The Company recorded compensation expense relative to stock options in 2013, 2012 and 2011 of $1.1 million, $0.2 million and $1.3 million, 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.

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

A summary of restricted stock activity for the year ended December 31, 2013, is presented below.

The Company recorded compensation expense relative to RSA’s in 2013, 2012 and 2011 of $0.9 million, $0.6 million and $1.2 million, respectively.

The total grant date fair value of RSA shares that vested during 2013 was approximately $0.5 million. As of December 31, 2013, there was approximately $1.2 million of total unrecognized compensation cost related to nonvested RSAs, with $0.9 million, and $0.3 million to be recognized during the years ended December 31, 2014 and 2015, respectively.

Basic earnings or loss per common share (“EPS”) is computed by dividing net income or loss available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for basic and diluted EPS for years ended December 31, 2013, 2012, and 2011, respectively, were as follows

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

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, trade receivables, deposits, inventory, accounts payable, accrued expenses, asset retirement obligations, other long-term liabilities and debt at floating interest rates approximate their fair values at December 31, 2013 and 2012, respectively, principally due to the short-term nature, maturities or nature of interest rates of the above listed items.

We rent office space and miscellaneous office equipment under non-cancelable operating leases. Office rent expense, net of sublease income, for the years ended December 31, 2013, 2012, and 2011 was $0.7 million, $0.5 million and $0.5 million, respectively. At December 31, 2013, minimum future rental commitments for operating leases were a total of $2.2 million as follows: $0.4 million in 2014, $0.4 million in 2015, $0.4 million in 2016, $0.4 million in 2017 and $0.6 in 2018 and thereafter.

The Company also has commitments related to four production sharing contracts with the Republic of Kenya and two Petroleum Exploration, Development & Production Licenses with the Republic of The Gambia, in each case entered into by the Company through a wholly owned subsidiary. To maintain compliance and ownership, the Company is required to fulfill minimum work obligations and to make certain payments as stated in each of the Kenya PSCs and The Gambia Licenses. At December 31, 2013, minimum future work obligations were a total of $148.4 million as follows: $14.8 million in 2014 and $133.6 million in the years 2015 and 2016.

In January 2014, a long-term drilling contract was signed for the drillship Energy Searcher. The rig arrived on location in the Oyo Field on OML 120 in June 2014 and commenced drilling the Oyo-8 well. The drilling agreement is for an initial term of one year, with an option to extend the contract for an additional one year. The minimum commitment pursuant to the initial term of the agreement is approximately $86.0 million.

In February 2014, a long-term contract was signed for the floating, production, storage, and offloading vessel (“FPSO”) Armada Perdana, which is the vessel currently connected to the Company’s producing wells Oyo-5 and Oyo-6. The contract provides for an initial term of seven years beginning January 1, 2014, with an automatic extension for an additional term of two years unless terminated by the Company with prior notice. The FPSO can process up to 40,000 barrels of liquid per day, with a storage capacity of approximately one million barrels. The annual minimum commitment per the terms of the agreement is approximately $35.0 million in the first year and approximately $48.0 million thereafter.

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, 2013, and through the filing date of this report, we do not believe the ultimate resolution of such actions or potential actions of which we are currently aware will have a material effect on our consolidated financial position or our net income or loss.

The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates. The following tables summarize related party transactions and balances (in thousands):

In June 2011, CPL, a wholly owned subsidiary of the Company, executed a Promissory Note in favor of Allied. See “Note 9 - Note Payable – Related Party,” for additional information relating to the Promissory Note. As of December 31, 2013, $6.5 million was outstanding under the Promissory Note.

The Company’s current operations are based in Nigeria, Kenya and The Gambia. Management reviews and evaluates the operations of each geographic segment separately. Segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues and expenditures are recognized at the relevant geographical location. The Company evaluates each segment based on operating income (loss).

The Company did not previously report separate segment information because management reviewed and evaluated the operations of the Company as a whole. However pursuant to the Allied Transaction and the significant exploration activities undertaken in several of our subsidiaries, management began to evaluate the operations of each geographic segment separately.

	Nigeria			Kenya			The Gambia			Corporate and Other			Total
For the Year Ended December 31,
2013
Revenues	$	63,736		$	-		$	-		$	-		$	63,736
Operating loss	$	(23,705	)	$	(3,404	)	$	(1,070	)	$	(15,348	)	$	(43,527	)

2012
Revenues	$	74,667		$	-		$	-		$	-		$	74,667
Operating loss	$	(18,497	)	$	(1,046	)	$	(498	)	$	(12,083	)	$	(32,124	)

2011
Revenues	$	37,922		$	-		$	-		$	-		$	37,922
Operating loss	$	(7,870	)	$	-		$	-		$	(12,793	)	$	(20,663	)

	Three Months Ended,
	March 31, 2013			June 30, 2013			September 30, 2013			December 31, 2013
Total revenues	$	22,006		$	20,007		$	21,723		$	-
Operating loss	$	(10,484	)	$	(11,924	)	$	(10,401	)	$	(10,718	)
Net loss attributable to CAMAC Energy Inc.	$	(10,488	)	$	(11,930	)	$	(10,417	)	$	(10,690	)
Net loss per common share attributable to CAMAC Energy Inc.:
Basic	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.01	)
Diluted	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.01	)

	Three Months Ended,
	March 31, 2012			June 30, 2012			September 30, 2012			December 31, 2012
Total revenues	$	5,672		$	-		$	44,657		$	24,338
Operating loss	$	(879	)	$	(3,496	)	$	(10,861	)	$	(16,888	)
Net loss attributable to CAMAC Energy Inc.	$	(1,296	)	$	(3,975	)	$	(6,879	)	$	(17,379	)
Net loss per common share attributable to CAMAC Energy Inc.:
Basic	$	(0.00	)	$	(0.01	)	$	(0.01	)	$	(0.02	)
Diluted	$	(0.00	)	$	(0.01	)	$	(0.01	)	$	(0.02	)

In February 2014, the Company completed the Allied Transaction thereby acquiring the Allied Assets. Pursuant to the terms of the Transfer Agreement, the Company, as partial consideration for the Allied Assets, paid $85.0 million in cash to Allied, issued 497,454,857 shares of the Company’s common stock to Allied and delivered a $50.0 million Convertible Subordinated Note (the “Convertible Subordinated Note”) to Allied under which $25.0 million was deemed advanced, with interest accruing per the terms of the Convertible Subordinated Note. Because Allied is a subsidiary of CEHL, the Company’s majority shareholder, it is deemed to be under common control. Accordingly, the shares issued to Allied pursuant to the transaction were accounted for as if issued on June 30, 2012, the effective date when Allied acquired the Allied Assets.

To fund the cash portion of the Allied Transaction and a portion of the anticipated capital expenditures for development of the Oyo Field, the Company also entered into a Share Purchase Agreement (the “Share Purchase Agreement”) with the Public Investment Corporation (SOC) Limited, a state-owned company registered and duly incorporated in the Republic of South Africa (“PIC”), for an aggregate cash investment of $270.0 million through a private placement of 376,884,422 shares of common stock (the “Private Placement”). The Share Purchase Agreement provides that the Private Placement will be completed in two installments. The first installment of $135.0 million (the “First Closing”) in exchange for 188,442,211 shares of the Company’s common stock was completed at the closing of the Allied Transaction. The second installment (the “Second Closing”) of $135.0 million in exchange for 188,442,211 shares of the Company’s common stock was completed in May 2014.

Following the Second Closing with the PIC, the Company was required to pay to Allied the additional $85.0 million in cash, and the additional $25.0 million Convertible Subordinated Note was deemed advanced with interest accruing per the terms of the Convertible Subordinated Note. As of the First Closing and pursuant to the terms of the Transfer Agreement, the Company was obligated for the full $50.0 million Convertible Subordinated Note and accordingly recorded this on the balance sheet at that time.

The Allied Transaction is being accounted for as a transaction between entities under common control, whereby the net assets acquired are combined with the Company’s assets at their historical amounts. Since the cash and debt consideration exceeds the carrying cost of the assets acquired, no value was assigned to the shares issued.

In April 2014, the Company signed a Petroleum Agreement relating to the Expanded Shallow Water Tano block in Ghana. The Company has been named technical operator and will hold an indirect 30% interest in the block. The block contains three discovered

fields, and the work program requires the partners to determine, within nine months, the economic viability of developing the discovered fields.

In September 2014, the Company, through its wholly owned subsidiary CPL, entered into a credit facility with a Nigerian bank for a five-year senior secured term loan providing initial borrowing capacity of up to $100.0 million (the “Term Loan Facility”). U.S. dollar borrowings under the Term Loan Facility bear interest at the rate of LIBOR plus 7.5%, subject to a floor of 9.5%. The obligations under the Term Loan Facility include a legal charge over OMLs 120 and 121 and an assignment of proceeds from oil sales. The obligations of CPL have been guaranteed by the Company and rank in priority with all its other obligations. Proceeds from the Term Loan Facility will be used for the further expansion and development of OMLs 120 and 121 offshore Nigeria, including the Oyo field.

Under the Term Loan Facility, the following events, among others, constitute events of default: CPL failing to pay any amounts due within thirty days of the due date; bankruptcy, insolvency, liquidation or dissolution of CPL; a material breach of the Loan Agreement by CPL that remains unremedied within thirty days of written notice by CPL; or a representation or warranty of CPL proves to have been incorrect or materially inaccurate when made. Upon any event of default, all outstanding principal and interest under any loans will become immediately due and payable.

The Term Loan Facility contains normal and customary covenants including the delivery of the Company’s annual audited financial information each year, and a provision of priority of interest, in which the Company is to procure that its obligations under the Term Loan Facility do and will rank in priority with all its other current and future unsecured and unsubordinated obligations. The Company is also to provide a production and lifting schedule each month displaying the daily production totals and quantities lifted respectively from OMLs 120 and 121.

Upon executing the Term Loan Facility, the Company paid a commitment fee of $1.9 million, which was capitalized and will be amortized over the life of the Term Loan Facility.

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

The unaudited supplemental information on oil and gas exploration and production activities for 2013, 2012 and 2011 has been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Disclosures by geographic area include Africa and the United States.

The following estimates of the net proved crude oil reserves in Nigeria are based on evaluations prepared by third-party reservoir engineers. DeGolyer and MacNaughton (“D&M”) has prepared evaluations on 100 percent of our rights to proved reserves and the estimates of proved crude oil reserves attributable to our net interests in oil and gas properties for the year ended December 31, 2013. 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.

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

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

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

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

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

Standardized Measure of Discounted Future Net Cash Flows reflects the Company’s estimated future net revenues, net of estimated income taxes, to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the average of the first-day-of-the-month commodity prices during the 12-month period ended on December 31, 2013) without giving effect to non-property related expenses such as DD&A expense and discounted at 10% per year. The average first-day-of-the-month commodity prices during the 12-month periods ending on December 31, 2013, 2012, and 2011, were $108.63, $112.77, and $112.26 per barrel of crude oil, respectively, including differentials. Amounts below for production sold and production costs exclude royalties.

	Payments Due By Period
(In thousands)	Total		2014		2015-2016		2017-2018		Thereafter
Minimum obligations - Kenya	$	34,432	$	10,800	$	23,632	$	-	$	-
Minimum obligations - The Gambia		114,000		4,000		110,000		-		-
Operating lease obligations		2,149		360		750		784		255
Total	$	150,581	$	15,160	$	134,382	$	784	$	255

(1)	Consolidated Financial Statements
	Reports of Independent Registered Public Accounting Firms	F-	1
	Consolidated Balance Sheets at December 31, 2013 and 2012	F-	3
	Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011	F-	4
	Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011	F-	5
	Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011	F-	6
	Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	F-	7
	Notes to Consolidated Financial Statements	F-	8
(2)	Consolidated Financial Statement Schedules
	Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)
	Schedules not included have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes.	S-	1
(3)	Exhibits

	As of December 31,
	2013			2012
Wells and production facilities	$	28,874		$	34,725
Proved properties		386,196			386,196
Work in progress and other		86,634			-
Oilfield assets		501,704			420,921
Accumulated depletion		(74,909	)		(65,893	)
Oilfield assets, net		426,795			355,028
Unevaluated leaseholds		8,240			8,240
Oil and gas properties, net		435,035			363,268

Other property and equipment		1,590			989
Accumulated depreciation		(838	)		(533	)
Other property and equipment, net		752			456

Total property, plant and equipment, net	$	435,787		$	363,724

	Years Ended December 31,
	2013			2012			2011
Net loss attributable to CAMAC Energy Inc. before income tax expense	$	(43,525	)	$	(29,529	)	$	(24,913	)
Expected income tax provision at statutory rate of 35%		(15,234	)		(10,335	)		(8,720	)
Increase (decrease) due to:
Foreign-incorporated subsidiaries		-			-			4,102
Net losses not realizable currently for U.S. tax purposes		15,234			10,335			4,618
Total income tax expense	$	-		$	-		$	-

	As of December 31,
	2013			2012
Basis difference in fixed assets	$	(105,007	)	$	(50,121	)
Unused capital allowances		341,540			276,644
Net operating losses		26,650			16,922
Share-based compensation		837			368
		264,020			243,813
Valuation allowance		(264,020	)		(243,813	)
Net deferred income tax assets	$	-		$	-

	Foreign
	Currency
	Gain (Loss)
Balance at December 31, 2012	$	224
Realized foreign currency gain		(224	)
Balance at December 31, 2013	$	-

United States:	2007 - 2013
Nigeria:	2010 - 2013
Kenya:	2012 - 2013
Gambia:	2012 - 2013

						Weighted-Average
	Shares					Remaining
	Underlying			Weighted-Average		Contractual Term
	Options			Exercise Price		(Years)
Stock Options
Outstanding at January 1, 2013		6,124,703		$	0.37		3.5
Granted		8,003,874		$	0.28		4.3
Exercised		-
Forfeited		(353,046	)	$	0.69
Outstanding as of December 31, 2013		13,775,531		$	0.31	3.7

Expected to vest		13,775,531		$	0.31	3.7
Exercisable at December 31, 2013		3,376,648		$	0.37		2.7

				Weighted-Average
				Grant Date Fair
	Shares			Value
Restricted Stock
Nonvested at January 1, 2013		2,676,724		$	0.32
Granted		4,163,374		$	0.26
Vested		(2,301,312	)	$	0.32
Forfeited		-
Nonvested as of December 31, 2013		4,538,786		$	0.27

	Year Ended December 31,
	2013			2012		2011
CEHL, total operating (income) and expenses	$	(1,167	)	$	81	$	3,243
CEHL, other expense, net		99			122		120

	Crude Oil
	(MBbls)
International
December 31, 2010		5,288
Revisions		(2,288	)
Production		(337	)
December 31, 2011		2,663
Revisions		2,986
Acquisition		9,043
Production		(683	)
December 31, 2012		14,009
Revisions		(4,878	)
Production		(591	)
December 31, 2013		8,540

Proved developed reserves
December 31, 2011		92
December 31, 2012		660
December 31, 2013		321

Proved undeveloped reserves
December 31, 2011		2,571
December 31, 2012		13,349
December 31, 2013		8,219