UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

For the fiscal year ended December 31, 2014

OR

For the transition period from:   to   

001-34525

(Commission File Number)

 

CAMAC ENERGY INC.

(Exact name of registrant as specified in its charter)

 

 

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

(Address of Principal Executive Office) (Zip Code)

(713) 797-2940

(Registrant’s telephone number, including area code)

 

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

Common Stock, $0.001 par value

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

None

 

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

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

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

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

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

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

 

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $381,212,680 based on an adjusted share price of $0.70. All executive officers and directors of the registrant have been deemed, solely for the purpose of the forgoing calculation, to be “affiliates” of the registrant.

As of March 2, 2015, there were 1,263,289,143 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement or Form 10-K/A relating to the Company’s Annual Meeting of Stockholders to be held in May 2015 are incorporated by reference in Part III of this report.

 

 

 

 

 

 

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CAMAC Energy Inc.

FORM 10-K

TABLE OF CONTENTS

 

 

 

 

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GLOSSARY OF SELECTED OIL AND GAS TERMS

 

The following is a description of the meanings of certain oil and gas industry terms and acronyms used in this report:

 

Bbl - One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons.

 

BOPD - One barrel of oil per day.

 

MBbl - One thousand Bbls.

 

Development well - A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

 

Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or crude oil in another reservoir.

 

Field - An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Gross oil and gas wells or acres - The Company’s gross wells or gross acres represent the total number of wells or acres in which the Company owns a working interest.

 

Net oil and gas wells or acres - Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that the Company owns in such wells or acres represented by the underlying properties.

 

Productive well - A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

 

Prospect - A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

 

Proved developed reserves - Has the meaning given to such term in Rule 4-10(a)(3) of Regulation S-X, which defines proved developed reserves as reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

 

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

Proved undeveloped reserves - Has the meaning given to such term in Rule 4-10(a)(4) of Regulation S-X, which defines proved undeveloped reserves as reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

 

Standardized measure of proved reserves - The present value, discounted at 10%, of the future net cash flows attributable to estimated net proved reserves, as estimated in the Company’s independent engineer’s reserve report.

 

Unproved properties or unevaluated leasehold - Properties with no proved reserves.

 

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2-D seismic data - 2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data.

 

3-D seismic data - 3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data provide more reliable information than 2-D seismic data.

 

 

PART I

 

 

This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions, and are influenced by various factors. As a consequence, actual results may differ materially from those in the forward-looking statements. See Item 1A Risk Factors of this Form 10-K for a discussion of risk factors.

 

Unless the context otherwise requires, the terms “we,” “us,” “our,” “Company” and “the Company” refer to CAMAC Energy Inc., a Delaware corporation, and its subsidiaries. The Company’s corporate headquarters is located in Houston, Texas. For more information about CAMAC Energy Inc., visit www.camacenergy.com.

 

GENERAL

 

CAMAC Energy Inc., a Delaware corporation, is an independent oil and gas exploration and production company focused on energy resources in Africa. Our strategy is to acquire and develop high-potential exploration and production assets in Africa, and to explore and develop those assets through strategic partnerships with national oil companies, indigenous local partners and other independent oil companies. We seek to build and operate a strategic portfolio of high-impact exploration and near-term development projects with significant production, reserves and resources growth potential.

 

We actively manage investments and on-going operations by limiting capital exposure through farm-outs at various stages of exploration and development to share risks and costs. We prioritize on building a strong technical and operational team and place an emphasis on the utilization of modern oil field technologies that mature our assets, reduce the cost of our projects and improve the efficiency of our operations.

 

Our shares are traded on the NYSE MKT under the symbol “CAK” and on the Johannesburg Stock Exchange under the symbol “CME.”

Our asset portfolio consists of nine licenses across four countries covering an area of approximately 10 million acres (approximately 43,000 square kilometers). We own producing properties and conduct exploration activities as an operator offshore Nigeria, conduct exploration activities as an operator onshore and offshore Kenya, conduct exploration activities as an operator offshore the Gambia, and conduct exploration activities as an operator offshore Ghana.

 

Our operating subsidiaries include CAMAC Petroleum Limited (“CPL”), CAMAC Energy Kenya Limited, CAMAC Energy Gambia Limited, and CAMAC Energy Ghana Limited.

 

We conduct certain business transactions with our majority shareholder, CAMAC Energy Holdings Limited (“CEHL”) and its affiliates, which include CAMAC International Nigeria Limited (“CINL”) and Allied Energy Plc (“Allied”). See Note 9 – Related Party Transactions to the Notes to Consolidated Financial Statements for further information.

 

Our 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 conducted with any of the above related party companies and their affiliates.

 

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OIL AND GAS ACTIVITIES

 

Nigeria

 

In December 2009, Allied, CINL, and Nigerian Agip Exploration Limited (“NAE”) commenced production offshore Nigeria from the Oyo field located within a portion of Oil Mining Leases 120 and 121 (the “OMLs”) in which Allied, CINL and NAE each held a participating interest. The first two producing wells in the Oyo field, the Oyo-5 well and Oyo-6 well, were connected to the floating production, storage and offloading vessel (“FPSO”) Armada Perdana. The FPSO can process up to 40,000 barrels of liquid per day, is equipped with gas treatment and re-injection facilities, and has storage capacity of up to one million barrels of crude oil. The first lifting of crude oil from the FPSO occurred in February 2010. The oilfield operations on and disposition of production from the OMLs, including the Oyo field, are governed by a Production Sharing Contract (“PSC”), pursuant to which NAE was initially designated as the operator.

 

In April 2010, we acquired certain economic interests in the Oyo field through the purchase of Allied’s and CINL’s rights in the PSC relating to the Oyo field in exchange for cash and the issuance to CEHL of shares of our Common Stock. As a result of this transaction, CEHL became the majority shareholder of the Company.

During 2010, the gross production rate from the Oyo field decreased as compared to initial rates, due to increased gas incursion into the Oyo-5 well and increased water production principally in the Oyo-6 well. In December 2010, we committed to fund a workover of the Oyo-5 well designed to reduce gas production and increase crude oil production from this well. The Company incurred a total of $59.7 million in costs for the workover. In accordance with our entitlements under the PSC, we recovered the majority of this workover cost from subsequent oil liftings as non-capital costs.

In February 2011, we acquired all of Allied’s and CINL’s rights in the PSC outside the Oyo field for cash and an agreement to make additional payments, contingent upon completion of specified milestones in any future exploration and development area of the OMLs outside of the Oyo field.

In June 2012, Allied acquired all of NAE’s participating interest in the OMLs and all of NAE’s interest in the PSC for $250.0 million in cash subject to certain adjustments. As a result of this transaction, Allied became the operator of the OMLs and the holder of the interests in the PSC apart from the interests previously acquired by the Company in 2010 and 2011.

 

In September 2013, drilling operations commenced on the Oyo-7 development well in OML 120. 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 then producing Pliocene reservoir, with excellent reservoir quality. The well was temporarily suspended, and will be completed as a producing well in the first half of 2015. 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 in OML 120. Hydrocarbons were encountered in three intervals totaling approximately 65 feet, as interpreted from the LWD data. The Company is making plans for further exploratory activities in the Miocene formation.

 

In January 2014, an affiliate of the Company entered into a drilling contract with Northern Offshore Ltd. for the drillship Energy Searcher. The drilling agreement was for an initial term of one year, with a one-year optional extension. The rig arrived on location in the Oyo field in OML 120 in June 2014 and commenced drilling the Oyo-8 well. The drilling contract was terminated by the Company, through its affiliate, in January 2015. See Item 3 – Legal Proceedings for further information.

 

In February 2014, an affiliate of the Company entered into a new long-term contract for the FPSO Armada Perdana. The FPSO was connected to the producing wells Oyo-5 and Oyo-6 and will be connected to the Oyo-7 and Oyo-8 wells once each well is ready to commence production in the first half of 2015. 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.

 

In February 2014, the Company acquired all remaining economic interests in the PSC and related assets, contracts and rights pertaining to the OMLs located offshore Nigeria, including the producing Oyo field (the “Allied Assets”), from Allied (the “Allied Transaction”) pursuant to a Transfer Agreement entered into in November 2013 by the Company and its affiliates, and Allied (the “Transfer Agreement”). In consideration for the Allied Assets, the Company issued 497.5 million shares of the Company’s common stock, delivered to Allied a $50.0 million convertible subordinated promissory note (the “Convertible Subordinated Note”) and paid $170.0 million in cash. As a result of the Allied Transaction, the Company now owns 100% of the economic interest in the OMLs. See Note 4. — Acquisitions to the Notes to Consolidated Financial Statements for additional information on the Allied Transaction.

 

In August 2014, the Oyo-8 well was drilled to a total vertical depth of approximately 6,059 feet (approximately 1,847 meters) and successfully encountered four new oil and gas reservoirs with total gross hydrocarbon thickness of 112 feet in the eastern fault block,

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based on results from the LWD data, reservoir pressure measurement, and reservoir fluid sampling. The well is scheduled to be completed horizontally as a producing well in the Pliocene formation of the Oyo field in the first half of 2015. The Company plans to further evaluate the new oil and gas discoveries in the eastern fault block as part of its exploratory program.

 

In September 2014, the Company shut-in the Oyo-5 and Oyo-6 wells and successfully removed their flow lines and other subsea equipment for relocation to wells Oyo-7 and Oyo-8 as planned. The Company also initiated temporary plug and abandonment activities for well Oyo-5. Current plans are to recomplete well Oyo-5 as a water injection well in 2015.

 

In December 2014, the Company entered into a contract for the semi-submersible rig Sedco Express to complete the Oyo field development campaign. Current plans are to use the Sedco Express to expedite the horizontal completion and production tie-in of wells Oyo-7 and Oyo-8 in the first half of 2015.

In addition to its development plans for the Oyo field, the Company has high-graded four exploration prospects in the OMLs. The Company has commenced a farm-out process for these prospects to identify potential partners to share in the costs and risks associated with drilling into one or more of these prospects. Timing for completion of the farm-out process and drilling of exploratory wells is uncertain at the present time.

 

Kenya

 

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

 

Blocks L1B and L16

 

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, for each block, to i) conduct a gravity and magnetic survey and ii) acquire, process and interpret 2-D seismic data.

 

The gravity and magnetic survey for both blocks was completed in April 2013. In December 2013, the Company initiated an Environmental and Social Impact Assessment (“ESIA”) study that was successfully completed in March 2014 for both blocks.

 

In February 2015, the Company completed its acquisition of 2-D seismic data covering the totality of block L1B and the onshore portion of block L16. The objective of the seismic data acquisition was to identify potential exploration targets in the Paleozoic, Jurassic, Cretaceous, and Middle to Lower Tertiary sections, which are known to be oil-bearing in the East Africa region. The seismic survey, paired with the previously completed airborne gravity and magnetic surveys, will be used to help identify potential drilling targets on the blocks.

 

The Company is currently making plans to acquire 2-D seismic on the offshore portion of block L16, but has satisfied all material contractual obligations under the initial exploration period. The Company 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 additional period.

 

Blocks L27 and L28

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, for each block, i) conduct a regional geological and geophysical study, ii) reprocess and re-interpret previous 2-D seismic data and iii) acquire, process and interpret 1,500 square kilometers of 3-D seismic data.

In March 2014, the Company, through its participation in a multi-client combined gravity/magnetic and 2-D seismic survey, completed its required gravity/magnetic and 2-D seismic data acquisition for both blocks. The acquired data is currently being processed and interpreted. Further, in March 2014, we started the regional geophysical study for these two blocks, which we expect to complete in April 2015.

 

The Company plans to pursue completion of the work program, and is also considering the possibility of farming-out a portion of its rights to both offshore blocks to potential partners. Upon completion of the work program, the Company has the right to apply for up

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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 additional period.

 

The Gambia

 

In May 2012, the Company, through a wholly owned subsidiary, signed two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia, for offshore exploration blocks A2 and A5 (the “Gambia Licenses”). 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 is required, for each block, to i) conduct a regional geological study, ii) acquire, process and interpret 750 square kilometers of 3-D seismic data, and iii) drill one exploration well to a maximum total depth of 5,000 meters below mean sea level and evaluate the drilling results. The first two work obligations (regional geological study and 3-D seismic data acquisition and processing) were required to be completed prior to the end of the second contract year, in May 2014. 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 geological and geophysical study of both blocks. However, as of the date of this report, the Company has not completed the acquisition of 3-D seismic data. The Company contracted with a seismic data acquisition contractor to complete this portion of the work program; however, the Gambian Government has yet to issue the required permits to the seismic vessel. In January 2015, the Gambian Ministry of Petroleum notified the Company that it was in default of its contractual obligation to acquire the 3-D seismic data and granted the Company a period of 120 days, ending April 2015, to remedy such default or face termination of its licenses. The Company is engaged in active discussions with the Gambian Government to resolve the matter, which it believes will be successful, and is also in discussions concerning a potential farm-out of a portion of its rights under the licenses.

 

Ghana

 

In April 2014, the Company, through an indirect 50%-owned subsidiary, signed a Petroleum Agreement with the Republic of Ghana (the “Petroleum Agreement”) relating to the Expanded Shallow Water Tano block offshore Ghana. The Contracting Parties, which hold 90% of the participating interest in the block, are CAMAC Energy Ghana Limited as the operator, GNPC Exploration and Production Company Limited, and Base Energy (collectively the “Contracting Parties”), holding 60%, 25%, and 15% share of the participating interest of the Contracting Parties, respectively. Ghana National Petroleum Company initially has a 10% carried interest through the exploration phase, and will have the option to acquire an additional 10% paying interest following a declaration of commerciality. The Company owns 50% of its CAMAC Energy Ghana Limited subsidiary.  The remaining 50% interest is owned by an affiliate of the Company’s majority shareholder.

 

The block contains three previously discovered fields and the work program requires the Contracting Parties to determine, within nine months of the effective date of the Petroleum Agreement, the economic viability of developing the discovered fields. In addition, the Petroleum Agreement provides for an initial exploration period of two years from the effective date of the Petroleum Agreement, with specified work obligations during that period, including reprocessing of existing 2-D and 3-D seismic data and drilling of one exploration well. The Contracting Parties have the right to apply for a first extension period of one and one-half years and a second extension period of up to two and one-half years. Each extension period has specified additional minimum work obligations, including (i) conducting geological and geophysical studies during the first extension period and (ii) drilling one exploration well during the first extension period and, depending on the length of the extension, one or two wells during the second extension period.

 

In January 2015, the Petroleum Agreement became effective, following the signing of a Joint Operating Agreement between the Contracting Parties. Preliminary work has commenced on the evaluation of the discovered fields to determine economic viability.

 

Segment Information

For information related to our financial performance by segment, see Note 14 — Segment Information to the Notes to Consolidated Financial Statements.

 

DISCONTINUED OPERATIONS

 

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 (the “Leyshon Shares”), a natural resources mining company based in Beijing, China. The Leyshon Shares had a fair market value of $1.9

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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.

 

REGULATION

 

General

 

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

 

 

 

 

 

 

 

 

 

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

 

Environmental and Government Regulation

 

Various federal, state, local and international laws and regulations relating to the discharge of materials into the environment, the disposal of oil and natural gas wastes, or otherwise relating to the protection of the environment may affect our operations and costs. We are committed to the protection of the environment and believe we are in material compliance with the applicable laws and regulations. However, regulatory requirements may, and often do, change and become more stringent, and there can be no assurance that future regulations will not have a material adverse effect on our financial position, results of operations and cash flows. During the years ended December 31, 2014, 2013 and 2012, we did not have any significant expenditures relating to environmental and government regulation.

 

MARKETING AND PRICING

 

We currently derive the totality of our revenue from the sale of crude oil. As a result, our revenues and ultimate profitability, the value of our reserves, our access to capital and our growth are substantially subject to the prevailing prices of crude oil. Prevailing prices for such commodities are subject to wide fluctuations for macro-economic reasons beyond our control. Historically, prices received for crude oil sales have been volatile and unpredictable, and such volatility and unpredictability is expected to continue.

 

COMPETITION

 

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

 

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RISK MANAGEMENT AND INSURANCE PROGRAM

 

Insurance Program

In accordance with industry practice, the Company maintains insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from significant losses resulting from damages to, or the loss of, physical assets or loss of human life and liability claims of third parties, including such occurrences as well blowouts and weather events that result in oil spills and damage to our wells and/or platforms. Our goal is to balance the cost of insurance with our assessment of the potential risk of an adverse event. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and statutory regulations and we regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.

We continuously monitor regulatory changes and regulatory responses and their impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection at optimum levels, weighing the cost of insurance against the potential and magnitude of disruption to our operations and cash flows. 

Currently, the Company has operator’s extra expense insurance coverage up to $250.0 million per occurrence in respect of drilling and $75.0 million per occurrence in respect of all other wells. This includes coverage for re-drilling and restoration of wells as well as coverage for resultant environmental damage, including voluntary clean-up. The Company also carries physical damage coverage on offshore assets that is subject to full replacement cost limits. Both of these coverages, operator’s extra expense and physical damage, are subject to certain customary exclusions and limitations and to deductibles generally ranging from approximately $0.3 million to $2.0 million per occurrence, which must be met prior to recovery. In addition, the Company carries third party liability insurance, which includes pollution insurance, up to a limit of $50.0 million. This program includes coverage for bodily injury and property damage to third parties, including sudden and accidental pollution liability coverage. The company also carries Cargo Insurance of up to $15.0 million per shipment and construction all risks insurance of $25.0 million per occurrence.

Health, Safety and Environmental Program

Our Health, Safety and Environmental (“HSE”) Program is supervised by an HSE officer who reports to senior management to ensure compliance with all applicable state and federal regulations. Its implementation and execution is the direct responsibility of the respective country managers in all the countries in which we operate. We have in place an HSE policy that mandates compliance with all relevant HSE regulations and industry standards in the various countries in which we operate. The policy is designed with the joint goals of zero injuries and accidents, no risk to occupational health, and no damage to the environment.

EMPLOYEES

 

At December 31, 2014, the Company had a total of 86 full-time employees, of which 39 were employed in the United States, and 47 in Africa. We have been successful in attracting a talented team of industry professionals that has been instrumental in achieving significant growth and success for the Company. In addition to our employees, we utilize the services of various independent contractors and service providers to perform certain professional services, as needed.

 

During 2015, the Company expects to hire additional personnel in certain operational positions as needed. The number and skill sets of individual employees will be primarily dependent on the relative rates of growth of the Company’s different projects and the extent to which operations and development activities are executed internally or contracted to outside parties. In order for us to attract and retain qualified personnel, we will have to offer competitive salaries to present and future employees.

 

AVAILABLE INFORMATION

The Company files or furnishes Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registrations statements and other items with the Securities and Exchange Commission (“SEC”). We also make available, free of charge on our Internet website (http://www.camacenergy.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our website. We will also make available to any shareholder, without charge, copies of our Annual Report on Form 10-K as filed with the SEC. Individuals wishing to obtain this report, or any other filing, should submit a request to CAMAC Energy Inc., 1330 Post Oak Boulevard, Suite 2250, Houston, TX 77056, Attention: Investor Relations.

 

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

 

ITEM 1A. RISK FACTORS

 

 

CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION

 

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. All statements, other than statements of historical fact, in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are, or may be deemed to be, forward-looking statements. Such forward-looking statements involve assumptions, known and unknown risks, uncertainties and other factors, which may cause the actual results, performance or achievements of the Company, to be materially different from historical earnings and those presently anticipated or projected or any future results, performance or achievements expressed or implied by such forward-looking statements contained in this report.

 

In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “project,” “should,” “will,” “will likely,” or similar expressions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. We caution you not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Important factors that could affect our financial performance and that could cause actual results for future periods to differ materially from our expectations include, but are not limited to:  

 

 

 

 

 

 

 

 

 

 

 

 

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

 

Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described in this Item 1A. Risk Factors and in other sections of this Annual Report on Form 10-K. Should one or more of these risks or

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uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

 

Risks Related to the Company’s Business

 

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

 

As of December 31, 2014, we had approximately $50.0 million outstanding in aggregate principal under our Convertible Subordinated Note, $100.0 million under the Term Loan Facility and $11.2 million under the Allied Promissory Note, and we may incur additional indebtedness in the future. Our level of indebtedness has, or could have, important consequences to our business because:

 

 

 

 

 

In addition, the terms of the Term Loan Facility restrict, and the terms of any future indebtedness including any future credit facility may restrict our ability to incur additional indebtedness and grant liens because of debt or financial covenants we are, or may be, required to meet. Thus, we may not be able to obtain sufficient capital to grow our business or implement our business strategy and may lose opportunities to acquire interests in oil properties or related businesses because of our inability to fund such growth.

 

Our ability to comply with restrictions and covenants, including those in the Term Loan Facility or in any future credit facility, is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants in the Term Loan Facility could result in a default, which could permit the lenders to accelerate repayments and foreclose on the collateral securing such indebtedness.

Our business requires substantial additional capital. If we are unable to raise additional capital on acceptable terms in the future, our ability to execute our business plan may be impaired. 

 

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

 

 

 

 

 

 

 

 

 

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The recent significant decline in oil and natural gas prices may make it more difficult for us to obtain additional financing. The Company might not generate or sustain cash flows at sufficient levels to finance its business activities. When and if the Company generates significant revenues, if such revenues were to decrease due to lower oil prices, decreased production or other factors, and if the Company were unable to obtain capital through reasonable financing arrangements, its ability to execute its business plan would be limited, and it could be required to discontinue operations.

 

The Company may continue to incur losses for a significant period of time and may not be able to achieve profitability.

 

In addition to our interests in the OMLs, including the Oyo field, we have signed four PSCs in Kenya, two exploration licenses in The Gambia and a petroleum agreement in Ghana. As we are still in the early stages of exploration and have yet to drill on our Kenyan, Gambian, and Ghanaian blocks, we expect to continue to incur significant expenses relating to our identification of drilling prospects and investment costs relating to exploration. Additionally, fixed commitments, including salaries and fees for employees and consultants, rent and other contractual commitments may be substantial and are likely to increase as exploration drilling is scheduled and personnel are retained. Drilling projects generally require a significant period of time before they produce resources and generate profits. Our production in the Oyo field may or may not result in net earnings in excess of our losses on other ventures under development or in the start-up phase. We may not achieve or sustain profitability on a quarterly or annual basis, or at all.

The geographic concentration of our properties offshore Nigeria, Kenya, The Gambia and Ghana subjects us to an increased risk of loss of revenue or curtailment of production from factors specifically affecting offshore Nigeria, Kenya, The Gambia and Ghana.

Our properties are concentrated in four countries: Nigeria, Kenya, The Gambia and Ghana, and all of the value of our production and reserves is concentrated in a single oilfield offshore Nigeria. Any failure to recommence production, production problems or reduction in reserve estimates related to the Oyo field would adversely impact our business.  In addition, some or all of these properties could be affected should such regions experience:

 

 

 

 

 

 

 

 

We maintain insurance coverage for only a portion of these risks. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. We do not carry business interruption insurance.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

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

 

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

 

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Failure to effectively execute our exploration and development projects could result in significant delays and/or cost over-runs, including the delay of any future production, which could negatively impact our operating results, liquidity and financial position.

 

We currently have a number of exploration projects, all of which are in the early stages of the project development life-cycle, in addition to our Oyo field development project. Our exploration projects will require substantial additional evaluation and analysis, including drilling and, in the event a commercial discovery occurs, the expenditure of substantial amounts of capital, prior to preparing a development plan and seeking formal project sanction. First production from these exploration projects, in the event a discovery is made, is not expected for several years. Our Oyo field development project and some of our exploration projects are located in challenging deepwater environments and will entail significant technical and financial challenges, including extensive subsea tiebacks to an FPSO or production platform, pressure maintenance systems, gas re-injection systems, and other specialized infrastructure.

 

This level of development activity and complexity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. In addition, we have increased dependency on third-party technology and service providers and other supply chain participants for these complex projects. We may not be able to fully execute these projects due to:

 

 

 

 

 

 

 

We may not be able to compensate for, or fully mitigate, these risks.

 

The Company’s failure to capitalize on existing petroleum agreements could result in an inability by the Company to generate sufficient revenues and continue operations.

 

The Company has a 100% economic interest in, and operatorship of, the OMLs 120 and 121 in Nigeria, including the Oyo field. The Company has also entered into definitive petroleum agreements with Kenya, The Gambia, and Ghana. The Company’s business strategy includes spreading the risk of oil and natural gas exploration, development and drilling, and ownership of interests in oil and natural gas properties by participating in multiple projects and joint ventures. Failure of the Company to capitalize on its existing contracts could have a material adverse effect on the Company’s business and results of operations.

 

Under the terms of our various petroleum agreements, we are required to drill wells, declare any discoveries and conduct certain development activities in order to retain exploration and production rights and failure to do so may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas.

 

In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified in our various petroleum agreements and leases, our interests in the undeveloped parts of our license areas may lapse and we may be subject to significant penalties or be required to make additional payments in order to maintain such licenses. We can make no assurances that we will receive an extension of the initial exploration period for any of our prospects or what the terms of the extension might be.

 

Our proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves. All of our total estimated proved reserves at December 31, 2014 were proved undeveloped reserves which ultimately may be less than currently estimated.

 

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities. In the case of production sharing contracts, the quantities allocable to a part-interest owner’s share are affected by the assumptions of that owner’s future participation

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in funding of operating and capital costs. Actual future production, prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from estimates. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed. In addition, estimates of proved reserves reflect production history, results of exploration and development, prevailing prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

 

Our exploration projects remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and production.

 

A discovery made by the initial exploration well on a prospect does not ensure that we will ultimately develop or produce hydrocarbons from such prospect or that a development project will be economically viable or successful. Following a discovery by an initial exploration well, substantial additional evaluation, analysis, expenditure of capital and partner and regulatory approvals will need to be performed and obtained prior to official project sanction and development, which may include (i) the drilling of appraisal wells, (ii) the evaluation and analysis of well logs, reservoir core samples, fluid samples and the results of production tests from both exploration and appraisal wells, and (iii) the preparation of a development plan which includes economic assumptions on future oil and gas prices, the costs of drilling development wells, and the construction or leasing of offshore production facilities and transportation infrastructure. Regulatory approvals are also required to proceed with certain development plans.

 

Any of the foregoing steps of evaluation and analysis may render a particular development project uneconomic, and we may ultimately decide to abandon the project, despite the fact that the initial exploration well, or subsequent appraisal or development wells, discovered hydrocarbons. We may also decide to abandon a project based on forecasted oil and gas prices or the inability to obtain sufficient financing. We may not be successful in obtaining partner or regulatory approvals to develop a particular discovery, which could prevent us from proceeding with development and ultimately producing hydrocarbons from such discovery, even if we believe a development would be economically successful.

 

The Company’s oil and gas operations are subject to various risks beyond the Company’s control.

 

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

 

 

 

 

 

 

 

 

 

 

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

 

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The Company is dependent on others for the storage and transportation of all of its oil and gas which could result in significant operational costs to the Company and depletion of capital.

 

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

 

Drilling wells is speculative, often involving significant costs that may be more than our estimates and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

 

Exploring for and developing oil reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating exploration, appraisal and development wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploration wells bear a much greater risk of financial loss than development wells. In the past we have experienced unsuccessful drilling efforts. Moreover, the successful drilling of an oil well does not necessarily result in a profit on investment. A variety of factors, both geological and market-related, can cause a well or an entire development project to become uneconomic or only marginally economic. Our initial drilling sites, and any potential additional sites that may be developed, require significant additional exploration and appraisal, regulatory approval and commitments of resources prior to commercial development. We face additional risks due to a general lack of infrastructure in areas in which we operate and underdeveloped oil and gas industries in areas in which we operate and increased transportation expenses due to geographic remoteness. Thus, this may require either a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development of a commercially viable field. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

 

We contract with third parties to conduct drilling and related services on our development projects and exploration prospects for us. Such third parties may not perform the services they provide us on schedule or within budget. The recent decline in oil and gas prices may have an adverse impact on certain third parties from which we contract drilling, development and related oilfield services, which in turn could affect such companies' ability to perform such services for us and result in delays to our exploration, appraisal and development activities. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business, financial position and results of operations.

 

An interruption in the supply of materials, resources or services, including storage and transportation of oil and gas, could limit the Company’s operations and cause unprofitability.

 

The Company obtains, and will need to obtain materials, resources and services, including, but not limited to, specialized chemicals, specialty muds, drilling fluids, pipe, drill-string and geological and geophysical mapping and interruption services to carry out its operations. There may be only a limited number of manufacturers and suppliers of these materials, resources and services. Additionally, these manufacturers and suppliers may experience difficulty in supplying such materials, resources and services to the Company sufficient to meet its needs or may terminate or fail to renew contracts for supplying these materials, resources or services on terms the Company finds acceptable including, without limitation, acceptable pricing terms. For example, in January 2015, we terminated our drilling contract with Northern Offshore International Drilling Company Ltd. as a result of contractual disputes. The dispute and termination of the contract with this third-party provider resulted in delays to completion of the Oyo-8 well that the Company believes caused significant damage.

 

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The Company does not presently carry business interruption insurance policies in Africa and will be at risk of incurring business interruption loss due to theft, accidents or natural disasters.

 

The Company does not presently carry any policies of insurance in Africa to help protect itself from interruptions to its business. In the event that the Company were to incur business interruption losses with respect to one or more incidents, this could adversely affect its operations, and it may not have the necessary capital to maintain business operations.

 

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

 

Dr. Kase Lawal, the Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is a director of each of CEHL, CINL, and Allied, also entities constituting the CEHL Group.  Dr. Lawal also owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CEHL. CINL and Allied are each wholly owned subsidiaries of CEHL. As a result, Dr. Lawal may be deemed to have an indirect material interest in any transactions with CEHL including the agreements entered into with CEHL in April 2010, the OMLs transaction, the Promissory Note with Allied (see Note 8. — Debt to the Notes to Consolidated Financial Statements for further information regarding the Promissory Note) and the Transfer Agreement with Allied. These relationships may result in conflicts of interest. We may not be able to prove that these agreements are equivalent to arm’s length transactions. Should our transactions not provide the value equivalent of arm’s length transactions, our results of operations may suffer, and we may be subject to costly shareholder litigation.

 

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

 

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

 

Applicable Nigerian income tax rates could adversely affect the value of the OMLs, including the Oyo field.

 

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

 

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

 

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

 

The OMLs are located in an area where there are high security risks which could result in harm to the Oyo field operations and our interest in the Oyo field and the remainder of the OMLs.

 

The Oyo field is located approximately 75 kilometers (46 miles) off the Southern Nigerian coast in deep water. There are risks inherent to oil production in Nigeria. Since December 2005, Nigeria has experienced increased pipeline vandalism, kidnappings and militant takeovers of oil facilities in the Niger Delta. The Movement for the Emancipation of the Niger Delta (MEND) is the main group attacking oil infrastructure for political objectives, claiming to seek a redistribution of oil wealth and greater local control of the sector. Additionally, kidnappings of oil workers for ransom are common. Security concerns have led some oil services firms to pull

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out of the country and oil workers’ unions to threaten strikes over security issues. The instability in the Niger Delta has caused shut-in production and several companies to declare force majeure on oil shipments.

 

Despite undertaking various security measures and being situated 75 kilometers (46 miles) offshore the Nigerian coast, the FPSO vessel currently being used for storing petroleum production in the Oyo field may become subject to terrorist acts and other acts of hostility like piracy. Such actions could adversely impact our overall business, financial condition and operations. Our facilities are subject to these substantial security risks and our financial condition and results of operations may materially suffer as a result. Terrorist acts and regional hostilities around the world in recent years have led to increases in insurance premium rates and the implementation of special “war risk” premiums for certain areas. Such increases in insurance rates may adversely affect our profitability with respect to the Oyo field asset.

 

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

 

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

 

 

 

 

 

Any of these circumstances could adversely affect the operation of the FPSO vessel and result in loss of revenues or increased costs and adversely affect our profitability.

 

Risks Related to the Company’s Industry

 

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

 

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

 

 

 

 

 

 

 

 

 

 

 

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Significant and prolonged declines in crude oil and natural gas prices, such as we have recently experienced, may have the following effects on our business:

 

 

 

 

 

 

 

 

 

The Company may not be successful in finding, acquiring, or developing sufficient petroleum reserves, and a failure to do so could materially adversely affect our financial position, liquidity and ability to continue operations.

 

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

 

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

 

 

 

 

 

 

 

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Our offshore production and exploration activities will involve special risks that could adversely affect operations.

 

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt our operations. As a result, we could incur substantial expenses that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties.

 

Deepwater exploration and production generally involves greater operational and financial risks than on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Such risks are particularly applicable to our deepwater operations in the Oyo field. In addition, there may be production risks of which we are currently unaware. Whether we use existing pipeline infrastructure, participate in the development of new subsea infrastructure or use floating production systems to transport oil from producing wells, if any, these operations may require substantial time for installation, or encounter mechanical difficulties and equipment failures that could result in significant cost overruns and delays. Furthermore, operations in frontier areas generally lack the physical and oilfield service infrastructure present in more mature basins. As a result, a significant amount of time may elapse between a discovery and the marketing of the associated hydrocarbons, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of this infrastructure, oil and gas discoveries we make in the deepwater, if any, may never be economically producible.

 

In addition, in the event of a well control incident, containment and, potentially, cleanup activities for offshore drilling are costly. The resulting regulatory costs or penalties, and the results of third party lawsuits, as well as associated legal and support expenses, including costs to address negative publicity, could well exceed the actual costs of containment and cleanup. As a result, a well control incident could result in substantial liabilities for us, and have a significant negative impact on our earnings, cash flows, liquidity, financial position, and stock price.

 

The energy market in which the Company operates is highly competitive.

 

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

 

Hedging transactions may limit the Company’s potential gains and increase the Company’s potential losses.

 

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

 

The Company may be required to take non-cash asset write-downs.

 

Under applicable accounting rules, the Company may be required to write down the carrying value of oil and natural gas properties if oil and natural gas prices decline or if there are substantial downward adjustments to its estimated proved reserves, increases in its estimates of development costs or deterioration in its exploration results. Accounting standards require the Company to review its long-lived assets for possible impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be

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fully recoverable over time. In such cases, if the asset’s estimated undiscounted future net cash flows are less than its carrying amount, impairment exists. Any impairment write-down, which would equal the excess of the carrying amount of the assets being written down over their estimated fair value, would have a negative impact on the Company’s earnings, which could be material.

 

Cyber incidents may adversely impact our operations.

 

We have become increasingly dependent upon digital technologies to operate our exploration, development and production business. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and communicate with our employees and third-party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption or other operational disruptions in our exploration or production operations. Also, nearly all of the oil and gas distribution systems in the world are dependent on digital technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure or the systems or infrastructure of third parties could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of oil or natural gas, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. We have not suffered any material losses relating to such attacks; however, there is no assurance that we will not suffer such losses in the future. Although historically we have not incurred material expenditures for protective measures related to potential cyber attacks, as cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber attacks. 

 

Risks Related to International Operations

 

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

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

Specifically, foreign governments may enact and enforce laws and regulations requiring increased ownership by businesses and/or state agencies in energy producing businesses and the facilities used by these businesses, which could adversely affect the Company’s ownership interests in then existing ventures. The Company’s ownership structure may not be adequate to accomplish the Company’s business objectives in Nigeria or in any other foreign jurisdiction where the Company may operate. Foreign governments also may impose additional taxes and/or royalties on the Company’s business, which would adversely affect the Company’s profitability and

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value of our foreign assets, including its interests in the OMLs. In certain locations, governments have imposed restrictions, controls and taxes, and in others, political conditions have existed that may threaten the safety of employees and the Company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a foreign government and the Company or other governments may adversely affect its operations. These developments may, at times, significantly affect the Company’s results of operations and must be carefully considered by its management when evaluating the level of current and future activity in such countries.

 

The future success of the Company’s operations may also be adversely affected by risks associated with international activities, including economic and labor conditions, political instability, risk of war, nationalization or other expropriation of private enterprises, repatriation, termination, renegotiation or modification of existing contracts, tax laws (including host-country import-export, excise and income taxes and United States taxes on foreign subsidiaries), restrictions on currency conversion, devaluations of currency, restrictions or prohibitions on dividend payments to stockholders or changes in government policies, laws or regulations. For example, the Ministry of Petroleum of the Republic of The Gambia informed the Company in January 2015 that the Company was in default of certain of its contractual obligations and that it may terminate the Company’s licenses to operate in that country as early as April 2015 if the default is not remedied. The Company is engaged in active discussions with the government of The Gambia regarding an extension however no assurances can be given that such requests will be granted.  Realization of any of these factors could materially and adversely affect our financial position, results of operations and cash flows and result in the loss of all or substantially all of the Company’s assets or in a total loss of your investment in the Company.

 

We are subject to extensive environmental regulations in Nigeria.

 

Our operations are subject to extensive national, state and local environmental regulations in Nigeria. Environmental rules and regulations cover oil exploration and development activities as well as transportation, refining and production activities. These regulations establish, among others, quality standards for hydrocarbon products, air emissions, water discharges and waste disposal, environmental standards for abandoned crude oil wells, remedies for soil, water pollution and the general storage, handling, transportation and treatment of hydrocarbons. As a result of the creation of the Federal Ministry of Environment (“FME”) in 1999 and the enactment of more rigorous laws, such as the Environmental Guidelines and Standards for the Petroleum Industry in Nigeria (EGASPIN) 2002, environmental regulations will substantially impact our operations and business results. Under the Environmental Impact Assessment Act of 1992, all exploratory project drilling must have an environmental impact assessment approved by the FME and must receive an environmental permit from the local authorities. We are required to prevent the escape of petroleum into any water, well, spring, stream river, lake reservoir, estuary or harbor, and government inspectors may examine our premises to ensure that we comply with the regulations. The Department of Petroleum Resources also regulates environmental issues by requiring operators in the oil and gas industry to obtain permits for oil-related effluent discharges from point sources and oil-related project development. Non-compliance with environmental laws may result in fines, restrictions on operations or other sanctions. We are also subject to state and local environmental regulations issued by the regional environmental authorities, which oversee compliance with each state’s environmental laws and regulations by oil and gas companies. If we fail to comply with any of these national or local environmental regulations we could be subject to administrative and criminal penalties, including warnings, fines and facilities closure orders.

 

Compliance and enforcement of environmental laws and regulations, including those related to climate change, may affect operations and cause the Company to incur significant expenditures.

 

Extensive national, regional and local environmental laws and regulations in Africa are expected to have a significant impact on the Company’s operations. These laws and regulations set various standards regulating certain aspects of health and environmental quality, which provide for user fees, penalties and other liabilities for the violation of these standards. As new environmental laws and regulations are enacted and existing laws are repealed, interpretation, application and enforcement of the laws may become inconsistent. Compliance with applicable local laws in the future could require significant expenditures, which may adversely affect the Company’s operations. The enactment of any such laws, rules or regulations in the future may have a negative impact on the Company’s projected growth, which could decrease projected revenues or increase costs. In addition, non-governmental organizations concerned with the environment may take an interest in the Company’s operations and attempt to disrupt or halt operations in areas deemed environmentally sensitive. The Company’s response to these efforts could require unforeseen expenditures, cause delays in execution, and affect operations.

 

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

 

Official corruption and bribery remains a serious concern in Sub-Saharan Africa. The 2014 Transparency International report ranked Nigeria 136 out of 177 countries in terms of corruption perceptions. In an attempt to combat corruption in the oil and gas sector, the National Assembly passed the Nigeria Extractive Industries Transparency Initiative Act 2007. This action permitted Nigeria to become a candidate country under the Extractive Industries Transparency Initiative (“EITI”), the first step in bringing transparency to all material oil, gas and mining payments to the Government of Nigeria. In addition, Nigeria has amended its banking laws to permit

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the government to bring corrupt bank officials to justice. Several notable cases have been brought, but, to date, few significant cases have been successful and bank regulatory oversight remains a concern. Thus, increased diligence may be required in working with or through Nigerian banks or with Nigerian governmental authorities, and interactions with government officials may need to be monitored. To the extent that such efforts to increase transparency are unsuccessful, and any competitors utilize the existence of corruptive practices in order to secure an unfair advantage, our financial condition and results of operations may suffer.

 

A deterioration of relations between the United States and Nigeria or other African governments could have a material adverse effect on the Company, the market price of the Company’s Common Stock and the value of the Company’s investments.

 

At various times during recent years, the United States has had significant disagreements over political, economic and security issues with governments in Sub-Saharan Africa. Additional controversies may arise in the future. Any political or trade controversies, whether or not directly related to the Company’s business, could have a material adverse effect on the Company, the market price of the Company’s Common Stock and the value of the Company’s investments in Sub-Saharan Africa.

 

An epidemic of the Ebola virus disease is ongoing in West Africa and may adversely affect our business operations and financial condition.

 

An epidemic of the Ebola virus disease is ongoing in certain countries of West Africa. A substantial number of deaths have been reported by the World Health Organization (WHO) in these countries, and the WHO has declared it a global health emergency. It is impossible to predict the effect and potential spread of the Ebola virus in West Africa and around the world. Nigeria had reported cases of Ebola in 2014 but was officially declared free of Ebola by the WHO in October 2014.

Should the Ebola virus continue to spread, including to the areas in which we have assets or operations, not be satisfactorily contained or return to Nigeria, our exploration, development and production plans for our operations could be delayed or interrupted and such delays or interruptions could significantly increase costs of operations. Our operations in West Africa require contractors, personnel and equipment to travel to and from the areas that may be affected by announced travel bans to certain West African countries. If existing bans are extended to the countries in which we have assets or operations, including Nigeria, or if contractors or personnel refuse to travel to such areas, our business, results of operations and cash flows could be adversely affected. In addition, costs associated with obtaining services in West Africa could be significantly higher than planned due to fears of the Ebola virus epidemic, which may have an adverse effect on our business, results of operations, and cash flows. 

 

Risks Related to the Company’s Stock

 

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

 

Following the Allied Transaction, CEHL beneficially owned approximately 56.7% of our outstanding shares of Common Stock and continues to own a majority interest. CEHL controls the power to elect our directors, to appoint members of management and to approve all actions requiring the approval of the holders of our Common Stock, including adopting amendments to our Certificate of Incorporation and approving mergers, acquisitions or sales of all or substantially all of our assets, subject to certain restrictive covenants. The interests of CEHL as our controlling stockholder could conflict with your interests as a holder of Company Common Stock. For example, CEHL as our controlling stockholder may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its equity investment even though such transactions might involve risks to you, as minority holders of the Company.

 

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

 

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

 

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

 

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

 

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

 

 

 

 

 

 

 

 

 

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

 

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

 

The market price for shares of the Company’s Common Stock has been, and is expected to continue to be, volatile. Numerous factors beyond the Company’s control may have a significant effect on the market price for shares of the Company’s Common Stock, including the fact that the Company is a small company that is relatively unknown to stock analysts, stock brokers, institutional investors and others in the investment community that generate or influence sales volumes. There may be periods of several days or more when trading activity in the Company’s shares is minimal as compared to a seasoned issuer which has a large and steady volume of trading activity that will generally support continuous sales without an adverse effect on share price. Due to these conditions, investors may not be able to sell their shares at or near ask prices or at all if investors desire to liquidate their shares.

 

We recently listed our Common Stock on the Johannesburg Stock Exchange (“JSE”) however a trading market may not successfully develop on the JSE.

 

An active trading market for our Common Stock may not successfully develop on the JSE. In addition, we cannot assure what effect our listing on the JSE will have on our trading market on the NYSE MKT. In February and May 2014, we issued an aggregate of 376.9 million shares of our Common Stock to the Public Investment Corporation (SOC) Limited (“PIC”) of South Africa in a private placement. If PIC chooses to sell those shares on the JSE, sales of a large number of shares could have a negative effect on the market price of our shares on the JSE, which could have a negative effect on the market price of our shares on the NYSE MKT.

 

Substantial sales of the Company’s Common Stock could cause the Company’s stock price to fall.

 

The Company has registered approximately 945.5 million shares of our Common Stock on currently effective registration statements pursuant to registration rights agreements with stockholders. The potential for substantial amounts of our Common Stock to be sold in the public market may adversely affect prevailing market prices for our Common Stock and could impair the Company’s ability to raise capital through the sale of its equity securities. Additionally, we may issue and register a greater number of shares of Common Stock in order to meet our obligations to pay up to $50.0 million in oil and gas milestone payments under the Transfer Agreement or

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upon conversion of the Convertible Subordinated Note. All of such shares would be eligible for registration under a registration rights agreement.

 

Conversion of the Convertible Subordinated Note may dilute the ownership interest of existing stockholders.

 

The conversion of some or all of the Convertible Subordinated Note may dilute the ownership interests of existing stockholders. The Convertible Subordinated Note is convertible into 69.8 million shares of our common stock, which represents approximately 5.24% of our currently outstanding shares. The Convertible Note is subject to anti-dilution adjustment provisions, including provisions that make it convertible into the same percentage of our outstanding shares if we issue shares of common stock or any convertible security at a price per share less than the conversion price. Any sales in the public market of the shares of our common stock issuable upon such conversion could adversely affect prevailing market prices of our common stock. In addition, the anticipated conversion of the notes into shares of our common stock could depress the price of our common stock.

 

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

 

The Company’s Amended and Restated Certificate of Incorporation authorizes the issuance of up to 50.0 million shares of Preferred Stock, which shares constitute what is commonly referred to as “blank check” Preferred Stock. This Preferred Stock may be issued by the Board of Directors from time to time on any number of occasions, without stockholder approval, as one or more separate series of shares comprised of any number of the authorized but unissued shares of Preferred Stock, designated by resolution of the Board of Directors, stating the name and number of shares of each series and setting forth separately for such series the relative rights, privileges and preferences thereof, including, if any, the: (i) rate of dividends payable thereon; (ii) price, terms and conditions of redemption; (iii) voluntary and involuntary liquidation preferences; (iv) provisions of a sinking fund for redemption or repurchase; (v) terms of conversion to Common Stock, including conversion price; and (vi) voting rights. The designation of such shares could be dilutive of the interest of the holders of our Common Stock. The ability to issue such Preferred Stock could also give the Company’s Board of Directors the ability to hinder or discourage any attempt to gain control of the Company by a merger, tender offer at a control premium price, proxy contest or otherwise.

 

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

 

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

 

 

 

None.

 

 

 

EXECUTIVE OFFICES AND INTERNATIONAL FACILITIES

 

We have five leased office facilities located in Houston, Texas (the “Houston Facility”), Lagos, Nigeria (the “Lagos Facility”), Nairobi, Kenya (the “Kenya Facility”), Banjul, The Gambia (the “Gambia Facility”), and Johannesburg, South Africa (the “Johannesburg Facility”).

 

Our corporate headquarters is located at our Houston Facility at 1330 Post Oak Boulevard, Houston, Texas, 77056. The Houston Facility covers approximately 13,200 square feet of office space and is under a lease which commenced on July 1, 2012 and ends on October 31, 2019. Base rental expense is approximately $27,200 per month plus an allocated share of operating expenses.

 

The Nigeria Facility covers approximately 7,500 square feet of office space and is under short-term arrangements with a related party. Base rental expense is approximately $20,300 a month.

The Kenya Facility covers approximately 5,400 square feet of office space and is under lease which commenced on November 1, 2012 and ends November 30, 2017. Base rental expense is approximately $6,300 per month, plus service charges.

 

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The Gambia Facility covers approximately 2,700 square feet of office space and is under a renewable lease, which commenced on February 14, 2014 for a one-year fixed term. Base rental expense is approximately $1,000 per month.

 

The Johannesburg Facility covers approximately 3,300 square feet of office space under a lease which commenced on February 1, 2015 and ends on February 28, 2020. Base rental expense is approximately $7,000 per month.

 

We do not foresee significant difficulty in renewing or replacing these leases under current market conditions, or in adding additional space when required.

 

OIL AND GAS LEASEHOLDS

 

The map below sets forth a visual representation of the geographical locations of our oil and gas properties on the continent of Africa.

 

 

Nigeria

 

In February 2014, the Company acquired, from a related party, the outstanding economic interests not already owned by the Company in the OMLs (the “OMLs”) offshore Nigeria. Pursuant to this transaction, the Company now owns 100% of the development and exploration rights over approximately 0.4 million acres offshore Nigeria. The OMLs contain the Oyo field which has been in production since December 2009.  

 

Kenya

 

In May 2012, the Company entered into four PSCs with the Government of the Republic of Kenya, covering onshore exploration blocks L1B and L16, and new offshore exploration blocks L27 and L28. The PSCs awarded to the Company cover exploration rights over an area of 3.1 million and 0.9 million acres for blocks L1B and L16, respectively. Exploration rights over approximately 2.6 million acres were awarded each for blocks L27 and L28.

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Gambia

 

In May 2012, the Company signed two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia for offshore exploration blocks A2 and A5. For both blocks, the Company is the operator, with the 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 awarded to the Company cover exploration rights over approximately 0.3 million acres each for blocks A2 and A5.  In January 2015, the Gambian Ministry of Petroleum notified the Company that we were in default of certain contractual obligations, and that the Company was granted a period of 120 days, ending April 2015, to remedy the default or face termination of its licenses. The Company is engaged in active discussions with the government of The Gambia to resolve the matter, and is considering farming-out parts of its rights under the Licenses.

 

Ghana

 

In April 2014, the Company, through a 50% owned Ghanaian subsidiary, signed a Petroleum Agreement relating to the Expanded Shallow Water Tano block in Ghana. The Company, which is a member of a contracting party signatory to the Petroleum Agreement, has been named technical operator and holds an indirect 30% participating interest in the block. The block contains three discovered fields, and the work program requires the consortium to determine, within nine months of the effective date, the economic viability of developing the discovered fields. The Ghana Petroleum Agreement awards the Company exploration rights over approximately 0.4 million gross acres (0.1 million net acres).

RESERVES

 

The information included in this Annual Report on Form 10-K about our rights to our proved reserves as of December 31, 2014, represents evaluations prepared by DeGolyer and MacNaughton (“D&M”), an independent petroleum engineering and geoscience advisory firm. D&M has prepared evaluations on 100 percent of our rights to our proved reserves and the estimates of proved crude oil reserves attributable to our net interests in oil and gas properties as of December 31, 2014. The scope and results of D&M’s procedures are summarized in a letter that is included as an exhibit to this Annual Report on Form 10-K. For further information on reserves, including information on future net cash flows and the standardized measure of discounted future net cash flows, please refer to the Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited) within Item 8 of this report. The totality of our proved reserves are located offshore Nigeria in the OMLs.

 

Internal Controls over Reserve Estimation

 

Our policies regarding internal controls over the recording of reserve estimation require reserves to be in compliance with the SEC definitions and guidance and that they are prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry.

 

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

The reserves estimates shown herein have been independently prepared by D&M, a leading international petroleum engineering consultancy. Within D&M, the technical person primarily responsible for preparing the estimates set forth in the D&M reserves report incorporated herein is Lloyd W. Cade. Mr. Cade has over 32 years of experience in oil and gas reservoir studies and reserve estimations. He is a Registered Professional Engineer in the State of Texas, License No. 74615.

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

 

Our Reservoir Engineering Advisors on staff are Mr. Lanre Dipeolu and Ms. Toyin Badru. They are primarily responsible for the coordination and review of the third-party reserves report provided by D&M. Mr. Lanre Dipeolu has over 29 years of experience in the oil and gas industry and holds a BSc. in Petroleum Engineering from the University of Ibadan, Nigeria and an MBA from Herriot Watt University, Edinburgh, United Kingdom. He is a member of the Society of Petroleum Engineers. Ms. Toyin Badru has over 10 years of experience in the oil and gas industry and holds a BSc. in Petroleum Engineering from the University of Ibadan, Nigeria, and an MS in Petroleum Engineering from Stanford University, California. She has worked in reservoir simulation consulting groups as well as multi-disciplinary asset teams in both Nigeria and the United States. She is a member of the Society of Petroleum Engineers.

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Compliance with reserve bookings is the responsibility of the Company. The reserves estimates prepared by D&M were reviewed and approved by our management. The process performed by D&M to prepare reserve amounts includes the estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, before income tax. In the conduct of their preparation of the reserve estimates, D&M did not independently verify the accuracy and completeness of certain information and data furnished by us with respect to ownership interests, oil production data, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production and various other information and data that were accepted as presented. Furthermore, D&M did not perform a field examination of the properties, as this was not deemed necessary for the preparation of their report. However, if in the course of their evaluation something came to their attention which brought into question the validity or sufficiency of any such information or data, D&M did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.

Technologies Used in Reserves Estimates

 

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

 

When applicable, the volumetric method was used to estimate the original oil in place (“OOIP”). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation.

 

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, other engineering methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

 

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

 

In certain cases, elements of the reserves estimates incorporated information based on analogy with similar reservoirs where more complete data were available.

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

 

Summary of Crude Oil Reserves

Set forth below is a summary of our oil net proved reserves as of December 31, 2014, 2013, and 2012, respectively:

 

 

The Company annually reviews all proved undeveloped reserves (“PUDs”) to ensure an appropriate development plan exists. The Company’s PUDs are generally expected to be converted to proved developed reserves within five years of the date they are first classified as PUDs.

 

The 832 MBbls increase in PUDs in 2014 as compared to 2013 is due to a revision in estimates subsequent to a new full reservoir study of the Oyo field conducted in 2014. The 5,130 MBbls decrease in PUDs in 2013 as compared to 2012 was primarily due to certain PUDs in the eastern fault block of the Oyo field being downgraded to probable reserves as a result of new information.

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Under current development plans, all PUDs as of December 31, 2014 are expected to be developed within two years. The development of these PUDs will be achieved upon completion of the Company’s Oyo field redevelopment campaign, which includes completing the horizontal drilling and production tie-in of wells Oyo-7 and Oyo-8, as well as drilling and completing well Oyo-9 in the OMLs offshore Nigeria.

 

The standardized measure of discounted net future cash flows is the present value of estimated future net cash inflows from proved oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future net cash flows. As of December 31, 2014, the standardized measure of our proved reserves was approximately $237.0 million, as compared to $101.3 million as of December 31, 2013. The increase in the standardized measure of our proved reserves in 2014 as compared to 2013 is primarily due to the downward revisions of certain production and development cost estimates, as well as increases in the estimated quantity of our proved reserves. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties.

 

SEC reporting rules require companies to prepare reserve estimates using reserve definitions and pricing based on 12-month historical un-weighted first-day-of-the-month average prices, rather than year-end prices. Our estimated net proved reserves and standardized measure were determined using index prices for oil and were held constant throughout the life of the assets.  The average first-day-of-the-month commodity prices during the 12-month periods ending on December 31, 2014, 2013, and 2012, were $100.37, $108.63, and $112.77 per barrel of crude oil, respectively, including price differentials.

 

VOLUMES, PRICES, AND PRODUCTION COSTS 

 

Production and sales volumes net to the Company, as well as sales prices and production costs for the years 2014, 2013, and 2012 are shown below. The totality of the production and sales volumes for each period presented were originated from the Oyo field offshore Nigeria.

 

 

The downward trend in production volumes year-over-year is due to the natural decline of production from wells Oyo-5 and Oyo-6 in the Oyo field offshore Nigeria. The Company has initiated a redevelopment campaign for the Oyo field, which should bring two new wells on production in the first half of 2015. Average production costs per barrel of oil produced in the year 2014, 2013, and 2012 were $199.50, $99.61, and $47.17, respectively.

 

DRILLING ACTIVITY

 

In November 2013, the Company drilled the vertical portion of the Oyo-7 well offshore Nigeria. The primary objective of the well was to establish production from the producing Pliocene formation. The well is scheduled to be completed horizontally as a producing well in the first half of 2015. The secondary objective was to explore for the presence of hydrocarbons in the deeper Miocene formation. Hydrocarbons were encountered in three intervals totaling approximately 65 feet, as interpreted by LWD data. Management is making plans to further explore the Miocene formation.

 

In August 2014, the Company drilled the vertical portion of the Oyo-8 well offshore Nigeria. The primary objective of the well was to establish production from the producing Pliocene formation. The well is scheduled to be completed horizontally as a producing well in the first half of 2015. The secondary objective was to confirm the presence of hydrocarbons in an area in the eastern fault block of the Oyo field. The Company successfully encountered four new oil and gas reservoirs in the eastern fault block, with total gross hydrocarbon thickness of 112 feet, based on results from LWD data, reservoir pressure management, and reservoir fluid sampling techniques. Management has commenced a detailed evaluation of the results and plans to further explore the Pliocene formation in the eastern fault block.

 

No drilling activity occurred in the year 2012.

 

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ACREAGE AND PRODUCTIVE WELLS

 

The table below sets forth the acreage under lease and the number of producing oil wells for the Company as of December 31, 2014.

 

 

In Nigeria, wells Oyo-5 and Oyo-6 produced approximately 364,000 net barrels of oil in 2014. They were shut-in in September 2014, and their umbilicals and other subsea equipment were relocated to wells Oyo-7 and Oyo-8, which will be completed as producing wells in the first half of 2015.

 

Remaining lease terms

 

Nigeria

 

The current lease for the Nigeria acreage expires in February 2021.

 

Kenya blocks L1B and L16

 

Total acreage for the Kenya blocks L1B and L16 is approximately 4.0 million, net to the Company. The initial exploration period for both blocks ends in June 2015. The Company has met all material contractual obligations under the initial exploration period. The Company has the right to apply for up to two additional two-year exploration periods, with specified additional minimum work obligations.

 

Kenya blocks L27 and L28

 

Total acreage for the Kenya blocks L27 and L28 is approximately 5.1 million, net to the Company. The initial exploration period for both blocks ends in August 2015. The Company plans to pursue completion of the work program. Upon completion of the work program, the Company has the right to apply for up to two additional two-year exploration periods, with specified additional minimum work obligations.

 

The Gambia

 

The initial exploration period for the Gambia blocks expires in 2016, with certain obligations due in 2014, such as 3-D seismic data acquisition and processing. However, as of the date of this report, the Company has not completed the acquisition of 3-D seismic data. The Company contracted with a seismic data acquisition contractor to complete this portion of the work program; however, the Gambian Government has yet to issue the required permits to the seismic vessel. In January 2015, the Gambian Ministry of Petroleum notified the Company that it was in default of its contractual obligation to acquire the 3-D seismic data and granted the Company a period of 120 days, ending April 2015, to remedy such default or face termination of its licenses. The Company is engaged in active discussions with the Gambian Government to resolve the matter, which it believes will be successful, and is also in discussions concerning a potential farm-out of a portion of its rights under the licenses.

 

Ghana

 

Although the Ghana Petroleum Agreement was signed in April 2014, it only became effective in January 2015 following the signing of a Joint Operating Agreement among the joint venture partners. The remaining lease term for the Ghana acreage under the current exploration period expires in January 2017.

 

Productive Wells

 

Productive wells are producing wells and wells capable of producing in commercial quantities. In September 2014, the Company shut-in the then producing wells Oyo-5 and Oyo-6 and successfully removed their flow lines and other subsea equipment for relocation to wells Oyo-7 and Oyo-8 as planned. The Company also initiated temporary plug and abandonment activities for well Oyo-5. Current plans are to recomplete well Oyo-5 as a water injection well in 2015.

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DELIVERY COMMITMENTS

 

As of December 31, 2014, we had no delivery commitments.

 

 

 

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, 2014, 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 results of operations.

 

In January 2014, an affiliate of CEHL, the Company’s majority shareholder, and Northern Offshore International Drilling Company Ltd. (“Northern”) entered into an International Daywork Drilling Contract pursuant to which Northern agreed to provide the drillship Energy Searcher for the provision of drilling services offshore Nigeria. Pursuant to further contractual arrangements entered into in March 2014, the affiliate provided the drillship to CPL, with CPL assuming payment obligations under the drilling contract and receiving the right to enforce Northern’s obligations under the drilling contract. The Company guaranteed the performance by CPL of its obligations under these contractual arrangements.  The Company, CPL and the CEHL affiliate are referred to hereinafter as the “CAMAC Parties.”

 

On January 2, 2015, the CAMAC Parties received a notice from Northern purporting to terminate the drilling contract for failure to provide the required letter of credit thereunder and stating that the CAMAC Parties are required to pay Northern all outstanding unpaid invoices, the early termination fee, the demobilization fee and amounts due but not yet invoiced for work performed up to the date of termination. On January 7, 2015, the CAMAC Parties responded to Northern disputing the validity of the purported Northern termination, which under English law we believe constitutes a renunciation of the drilling contract and wrongful repudiatory breach thereof because of, among other things, the course of conduct by the parties. Specifically, the CAMAC Parties arranged for, and Northern agreed to and performed work in exchange for, issuing monthly prepayment invoices in lieu of the letter of credit. Because of Northern’s repudiatory breach, the CAMAC Parties elected to terminate the contract with immediate effect.  In addition, the January 7, 2015 letter set out other grounds for termination and claims against Northern for numerous material breaches of the drilling contract.

 

On January 12, 2015, Northern issued a request for arbitration in the London Court of International Arbitration (“LCIA”).  The request repeated the claims of Northern relating to the letter of credit as stated in the January 2, 2015 letter and asserted further breaches of contract, including for failure to pay invoices for work allegedly performed.  The request seeks payment of outstanding unpaid invoices, the early termination fee and the demobilization fee.  On February 10, 2015, the CAMAC Parties lodged their response to the request and outlined claims against Northern for breaches of the drilling contract for, among other things, wrongful termination of the contract, failure to maintain the well control equipment in good condition (including the blowout preventer), failure to maintain and repair the drilling unit, breach of warranty, failure to provide adequately skilled and competent personnel, failure to perform as a reasonable and prudent operator and failure to provide the drilling unit ready to commence operations by May 15, 2014. These breaches caused significant damages and loss to the CAMAC Parties, including wasted marine spread costs in excess of $50.0 million, i.e., the cost of other marine services that were accumulated while the rig incurred downtime, as recognized under English law, and delay damages in excess of $3.0 million due to delays in the commencement of operations.

 

Pursuant to the contract and LCIA rules, a tribunal of three arbitrators, one selected by each of Northern and the CAMAC Parties and the third appointed by the first two arbitrators, has been empaneled. Subsequently, Northern and the CAMAC Parties agreed to stay the arbitration pending mediation, which took place in Houston, Texas on March 6, 2015.

 

 

Not applicable.

 

 

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PART II

 

 

Market Information for Common Stock

 

Our common stock is currently listed on the NYSE MKT under the symbol “CAK”. It commenced listing on the NYSE MKT in November 2009 under the symbol “PAP”. Prior to being listed on the NYSE MKT, our common stock was quoted on the OTC Bulletin Board under the symbol “PFAP.OB” between May 2008 and November 2009. In addition to our listing on the NYSE MKT, in February 2014, our common stock became also listed on the Johannesburg Stock Exchange (“JSE”).

 

The following table sets forth the range of the high and low sales prices per share of our common stock for the periods indicated on the NYSE MKT, the principal market for the trading of our common stock, under the symbol “CAK”:

 

 

The above high and low sales prices per share of our common stock reflect the effect of the Company’s February 21, 2014 Stock Dividend payment, which was accounted for as a stock split, due to its large nature. See Note 4 – Acquisitions to the Notes to Consolidated Financial Statements for further information.

 

Capital Structure

 

Common Stock

 

The Company is authorized to issue up to 2.5 billion shares of $0.001 par value common stock. As of December 31, 2014, there were approximately 1.3 billion such shares issued and outstanding.

 

In May 2014, our shareholders authorized the Company to effect a reverse stock split of our common stock within a range of 1-for-3 to 1-for-6 shares.  As of the date of filing of this report, the reverse stock split has not yet been effected.

 

Preferred Stock

 

The Company is authorized to issue up to 50.0 million shares of $0.001 par value preferred stock and to designate the dividend rate, voting and other rights, restrictions and preferences for each series of preferred stock. No preferred stock was issued and outstanding as of December 31, 2014.

 

Common Stock Warrants and Options

 

As of March 2, 2015, the Company had warrants outstanding to purchase (i) an aggregate of 11.3 million shares of common stock at a price per share of $1.08 and (ii) an aggregate of 1.8 million shares of common stock at a price per share of $0.56.

As of March 2, 2015, an aggregate of approximately 14.4 million shares of common stock were issuable upon exercise of outstanding stock options.

 

Holders of Common Stock

 

As of March 2, 2015, there were approximately 62 holders of record of our common stock. In many instances, a broker or other entity holds shares in street name for one or more customers who beneficially own the shares.

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Dividend Policy

 

The Company has not paid any cash dividends in the past, and does not anticipate paying any cash dividends on its common stock in the foreseeable future.

 

In January 2014, our Board of Directors declared a stock dividend on all shares of our 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 our stockholders of certain proposals related to the Allied Transaction, including a proposal to amend our certificate of incorporation to increase the number of authorized shares of common stock, and (ii) approval of the listing of our common stock on the JSE. 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, we 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.

 

Because the Stock Dividend exceeded 25% of the total shares of common stock outstanding prior to the distribution, it was considered a large stock dividend. Accordingly, 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.

 

Securities Authorized for Issuance under Equity Compensation Plans

 

Upon adoption of the 2009 Equity Incentive Plan (“2009 Plan”) by our Board of Directors in June 2009, our Board of Directors resolved to (i) discontinue further grants and awards of equity securities under the 2007 Stock Plan (the “2007 Plan”), except the issuance of our stock upon exercise of issued and outstanding options issued pursuant to the 2007 Plan, and (ii) amend the 2007 Plan to reduce the number of shares available for issuance under the 2007 Plan to 2.6 million shares, down from 4.0 million shares, and to further reduce the number of shares available for issuance thereunder by such number of shares that from time to time may be returned for issuance under the 2007 Plan upon expiration or termination of any option issued thereunder or repurchase of any restricted stock issued thereunder, and to return all such shares to the Company’s treasury.

 

In February 13, 2014, our stockholders approved the amendment to the 2009 Plan at a special meeting of stockholders. On February 18, 2014, we executed the amendment to the 2009 Plan, thereby increasing the number of shares that may be granted thereunder to 100.0 million shares.

 

The following table sets forth information with respect to the equity compensation plans available to our directors, officers, and employees at December 31, 2014:

 

 

 

The above outstanding common stock warrants and options reflect the effect of the Company’s payment of the February 2014 Stock Dividend.

 

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Performance Graph

 

The following graph compares the yearly percentage change in the Company’s cumulative total stockholder return on its common shares with the cumulative total return of the S&P 500 Index and the SPDR Oil and Gas Exploration and Production Index. The selected indices are accessible to our stockholders in newspapers, the internet and other readily available sources. This graph assumes a $100 investment in CAMAC Energy Inc., the S&P 500 and the Energy Select Sector SPDR at the close of trading on December 31, 2009 and assumes the reinvestment of all dividends, if any.

 

 

This Performance Graph shall not be deemed to be incorporated by reference into our SEC filings and should not constitute soliciting material or otherwise be considered filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

 

Recent Sales of Unregistered Securities

 

In February 2014, as partial consideration for the Allied Transaction, the Company issued approximately 497.5 million unregistered shares of common stock to Allied. Furthermore, the Company issued, in February and May 2014, approximately 376.9 million shares of unregistered common stock to the PIC, pursuant to a Share Purchase Agreement in consideration for a $270.0 million cash investment by the PIC.  See Note 4. — Acquisitions to the Notes to Consolidated Financial Statements for further information.

 

The shares of common stock were subsequently registered with the Securities and Exchange Commission, pursuant to a registration statement filed with the Commission in December 2014.

 

Stock Repurchases

 

The Company did not repurchase any shares of its common stock during the year ended December 31, 2014.

 

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The above presented earnings per share amounts reflect the effect of the Stock Dividend paid in February 2014, which was accounted for as a stock split, due to its large nature.

 

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.

 

 

The following discussion of the Company’s historical performance and financial condition should be read together with Item 6, Selected Financial Data and the consolidated financial statements and related notes in Item 8 of this report and in conjunction with the financial statements filed as exhibits to the current report on Form 8-K filed with the Securities and Exchange Commission on December 19, 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. Risk Factors of this report for the discussion of risk factors.

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

The Company’s operating subsidiaries include CAMAC Petroleum Limited, CAMAC Energy Kenya Limited, CAMAC Energy Gambia Ltd, and CAMAC Energy Ghana Limited. 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 9 – Related Party Transactions to the Notes to Consolidated Financial Statements for further information.

 

OVERVIEW

 

Nigeria

 

In November 2013, the Company entered into a Transfer Agreement with Allied to purchase all of Allied’s interest in the OMLs (the “Allied Assets”). The transaction was effective in February 2014 thereby granting the Company ownership over 100% of the economic interests in the blocks.

 

To fund the cash portion of the purchase of the Allied Assets and a portion of the anticipated capital expenditures for the development of the Oyo field, the Company entered into a Share Purchase Agreement with the Public Investment Corporation (SOC) Limited

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(“PIC”), a state-owned company incorporated in the Republic of South Africa. Pursuant to the Share Purchase Agreement, the Company received a $270.0 million cash investment from the PIC and paid $170.0 million in cash to Allied, as partial consideration for the Allied Assets. See Note 4 – Acquisitions to the Notes to Consolidated Financial Statements for further information.

 

In August 2014 the Company drilled the vertical portion of well Oyo-8. The horizontal completion and production tie-in of the well is planned for the first half of 2015.

 

In September 2014, the Company shut-in the then producing wells Oyo-5 and Oyo-6 and successfully removed their flow lines and other subsea equipment for relocation to wells Oyo-7 and Oyo-8 as planned.  The Company also initiated temporary plug and abandonment activities for well Oyo-5. Current plans are to recomplete well Oyo-5 as a water injection well in 2015.

 

In December 2014, the Company entered into a contract for the semi-submersible rig Sedco Express to expedite the Oyo field development campaign. Current plans are to use the Sedco Express for the horizontal completion and production tie-in of wells Oyo-7 and Oyo-8 in the first half of 2015.

 

Kenya

 

Blocks L1B and L16

 

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, for each block, to i) conduct a gravity and magnetic survey and ii) acquire, process and interpret 2-D seismic data.

 

The gravity and magnetic survey for both blocks 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 for both blocks.

 

In February 2015, the Company completed its acquisition of 2-D seismic data covering the totality of block L1B and the onshore portion of block L16. The objective of the seismic data acquisition was to identify potential exploration targets in the Paleozoic, Jurassic, Cretaceous, and Middle to Lower Tertiary sections, which are known to be oil-bearing in the East Africa region. The seismic survey, paired with the previously completed airborne gravity and magnetic surveys, will be used to help identify potential drilling targets on the blocks.

 

The Company is currently making plans to acquire 2-D seismic on the offshore portion of block L16, but has satisfied all material contractual obligations under the initial exploration period. The Company 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 additional period.

 

Blocks L27 and L28

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, i) a regional geological and geophysical study, ii) reprocess and re-interpret previous 2-D seismic data and iii) acquire, process and interpret 1,500 square kilometers of 3-D seismic data.

In March 2014, the Company, through its participation in a multi-client combined gravity/magnetic and 2-D seismic survey, completed its required gravity/magnetic and 2-D seismic data acquisition for both blocks. The acquired data is currently being processed and interpreted internally.  Further, in March 2014, we started the regional geophysical study for these two blocks, which we expect to complete in April 2015.  

 

The Company plans to pursue completion of the work program, and is considering the possibility of farming out a portion of its rights over both offshore blocks to potential partners. Upon completion of the work program, the Company 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 additional period.

 

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The Gambia

In May 2012, the Company, through a wholly owned subsidiary, signed two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia for offshore exploration blocks A2 and A5 (the “Gambia Licenses”). 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 is required to, on each block, i) conduct a regional geological study, ii) acquire, process and interpret 750 square km of 3-D seismic data, and iii) drill one exploration well to a maximum total depth of 5,000 meters below mean sea level. The first two work obligations (regional geological study and 3-D seismic data acquisition and processing) were due prior to the end of the second contract year, in May 2014. 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 geological and geophysical study of both blocks. However, as of the date of this report, the Company has not completed the acquisition of 3-D seismic data.  The Company contracted with a seismic data acquisition contractor to complete this portion of the work program; however, the Gambian Government has yet to issue the required permits to the seismic vessel. In January 2015, the Gambian Ministry of Petroleum (the “Ministry of Petroleum”) notified the Company that it was in default of its contractual obligation to acquire the 3-D seismic data and granted the Company a period of 120 days, ending April 2015, to remedy such default or face termination of its licenses. The Company is engaged in active discussions with the Gambian Government to resolve the matter, which it believes will be successful, and is also in discussions concerning a potential farm-out of a portion of its rights under the licenses.

 

Ghana

 

In April 2014, the Company, through an indirect 50%-owned subsidiary, signed a Petroleum Agreement with the Republic of Ghana (the “Petroleum Agreement”) for the Expanded Shallow Water Tano block.  The Contracting Parties, which hold 90% of the participating interest in the block, are CAMAC Energy Ghana Limited as the operator, GNPC Exploration and Production Company Limited, and Base Energy (collectively the “Contracting Parties”), holding 60%, 25%, and 15% share of the participating interest of the Contracting Parties, respectively. Ghana National Petroleum Company initially has a 10% carried interest through the exploration phase, and will have the option to acquire an additional 10% paying interest following a declaration of commerciality. The Company owns 50% of its CAMAC Energy Ghana Limited subsidiary.  The remaining 50% interest is owned by an affiliate of the Company’s majority shareholder.

 

The Petroleum Agreement provides for an initial exploration period of two years from the effective date of the Petroleum Agreement, with specified work obligations during that period, including reprocessing of existing 2-D and 3-D seismic data and drilling of one exploration well. The Contracting Parties have the right to apply for a first extension period of one and one-half years and a second extension period of up to two and one-half years. Each extension period has specified additional minimum work obligations, including (i) conducting geological and geophysical studies during the first extension period and (ii) drilling one exploration well during the first extension period and, depending on the length of the extension, one or two wells during the second extension period. In addition, within nine months of the effective date of the Petroleum Agreement, the Contracting Parties will review and evaluate three previously discovered and appraised fields, the North, South and West Tano Fields, and declare whether or not those discoveries are commercial discoveries.

 

In January 2015, the Petroleum Agreement became effective, following the signing of a Joint Operating Agreement between the Contracting Parties. Preliminary work has commenced on the evaluation of the discovered fields to determine economic viability.

 

RESULTS OF OPERATIONS – CONTINUING OPERATIONS

 

Oil Revenues

 

Revenue is recognized when an oil lifting occurs. Crude oil revenues for 2014 were $53.8 million, as compared to revenues of $63.7 million and $74.7 million for 2013 and 2012, respectively. In 2014, the Company sold approximately 506,000 net barrels of oil at an average price of $106.41/Bbl. 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. The decrease in revenues in 2014 compared to 2013 and 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.

 

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During 2014, 2013 and 2012, the net daily production from the Oyo field was approximately 1,300 BOPD, 2,000 BOPD and 2,400 BOPD, respectively. There was no production during the fourth quarter of 2014 due to the shut-in of the two producing wells Oyo-5 and Oyo-6.

 

Operating Costs and Expenses

 

Production Costs

 

Production costs were $94.8 million for 2014, as compared to $70.4 million in 2013 and $41.6 million for 2012. Production costs include costs directly related to the production of hydrocarbons. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized, and are subsequently expensed when crude oil is sold. The impact of capitalizing unsold crude oil inventory caused a higher production cost variance in 2014 of approximately $30.0 million as compared to 2013, partially offset by lower floating, production, storage and offloading vessel (“FPSO”) and other boat costs. In addition, in 2014, the Company recorded a $1.7 million contingent liability for a disputed transaction tax on marine transportation, following recent claims from a Nigerian tax authority.

 

Production costs were higher in 2013 as compared to 2012, primarily because 2013 included twelve months of costs for the acquired Allied Assets, as compared to only six months of costs recorded in 2012 for the same assets.

Exploration Expenses

Exploration expenses were $14.3 million for 2014, as compared to $5.5 million in 2013 and $3.2 million in 2012. Exploration expenses consist of drilling costs for unsuccessful wells, and costs for acquiring and processing seismic data, as well as other geological and geophysical costs as required.

The $14.3 million exploration expenditures in 2014 include $12.1 million in Kenya principally for a 2-D seismic acquisition campaign, $1.3 million in The Gambia for certain contractual lease commitments, $0.5 million in Ghana for the preliminary exploration evaluation study of the block, and $0.4 million in Nigeria for the evaluation of certain oil and gas prospects.

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 The 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 The Gambia, and $0.2 million related to Nigeria.

Depreciation, Depletion, and Amortization (“DD&A”)

DD&A expenses for 2014, including accretion, were $23.8 million, as compared to $16.9 million in 2013 and $51.0 million in 2012. In September 2014, the Company determined that, based on the current operating plan and the equipment to be utilized, its estimated cost to plug and abandon certain wells should be revised upwards; see Note 7 – Asset Retirement Obligations to the Notes to Consolidated Financial Statements for further information. The higher asset retirement cost estimate caused an increase in the oil field asset cost basis, which resulted in an increased average depletion rate.

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 average depletion rates for 2014, 2013 and 2012, were $46.95/Bbl, $28.60/Bbl and $74.70/Bbl, respectively.

General and Administrative (“G&A”)

G&A expenses for 2014 were $14.3 million, as compared to $14.5 million and $11.0 million for 2013 and 2012, respectively. In 2014, G&A expenditures decreased as compared to 2013, primarily due to lower transaction costs incurred, partially offset by higher corporate overhead costs to support the development of the Oyo field offshore Nigeria and the Company’s expanding exploration activities. The increase in G&A expenses for 2013 as compared to 2012 was primarily due to higher consulting and legal costs associated with the Allied Transaction. In addition, the Company incurred non-cash stock-based compensation expenses of $3.1 million, $2.0 million, and $0.7 million for the years 2014, 2013, and 2012, respectively.

 

Other Income (Expense)

 

The Company recorded other expense of $3.0 million in 2014, as compared to other income of $38,000 in 2013 and other expense of $0.6 million in 2012. In 2014, the Company recognized $4.4 million interest expense on borrowings and $0.4 million other tax liabilities in Nigeria, partially offset by $1.8 million gain on foreign currency transactions.

 

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In 2013, the Company recognized 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 sales of securities and incurred $0.1 million in interest expenses associated with the Promissory Note.

 

Income Taxes

 

Income taxes were nil for the years 2014, 2013, and 2012. The Company did not have any taxable income from its oil and gas activities in Nigeria in the years 2014, 2013 and 2012, and was therefore not subject to Petroleum Profit Taxes.

 

Losses From Continuing Operations

 

Losses from continuing operations, including non-controlling interests, were $96.3 million in 2014, as compared to losses of $43.5 million and $32.7 million for 2013 and 2012, respectively. The 2014 losses from continuing operations increased as compared to 2013 primarily due to lower sales volumes, higher production costs, higher depletion expenses, and higher interest expenses in 2014.  

 

The 2013 losses from continuing operations increased as compared to 2012 primarily due to lower sales volumes.

 

In 2014, losses attributable to the non-controlling interest in the Ghana subsidiary were $0.2 million. See Note 9 – Related Party Transactions to the Notes to Consolidated Financial Statements for further information.

 

Headline Earnings

 

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 and publicly disclose 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, 2014, 2013, and 2012, 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 2014, 2013 and 2012 were $(0.08), $(0.05) and $(0.05), respectively.

 

RESULTS OF OPERATIONS – DISCONTINUED OPERATIONS

 

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 13 – Discontinued Operations to the Notes to Consolidated Financial Statements for further information.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Cash Flows

 

The table below sets forth a summary of the Company’s cash flows for the years ended December 31, 2014, 2013, and 2012:

 

 

Cash Flows from Operating Activities

 

The decrease in net cash used in operating activities of $3.1 million in 2014 as compared to 2013 was due to i) a $52.8 million higher net loss in 2014 caused by lower revenues and higher operating costs, ii) a $26.2 million higher negative non-cash adjustment to net income, principally due to a $32.9 million non-cash offset of crude oil sales receivables against a related party liability, partially offset

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by $7.0 million higher non-cash DD&A adjustment, and iii) a $82.0 million positive variance in the changes in operating assets and liabilities, principally due to increased vendor financing and sale of crude oil inventory.

 

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 included 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.

 

Cash Flows from Investing Activities

 

The cash used in investing activities in 2014 consists of a $170.0 million payment to Allied, as partial consideration for the acquisition of the Allied Assets, and $128.5 million addition to property, plant and equipment principally as part of the ongoing Oyo field redevelopment campaign in the OMLs. 

 

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.

 

Cash Flows from Financing Activities

 

The increase in net cash provided by financing activities of $323.5 million in 2014 as compared to 2013 consisted of the $270.0 million investment from the PIC, $108.6 million borrowings, net of debt issuance costs, $0.9 million funding from a non-controlling interest owner for their share of the Ghana exploration expenditures, $0.4 million for the issuance of stock pursuant to employee stock option exercises, partially offset by a $12.4 million adjustment to the net assets of Allied in connection with the Allied Transaction and a $10.4 million funding to an escrow account to secure certain repayments under the Term Loan Facility.

 

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.

 

Capital Resources

The Company’s primary cash requirements are for capital expenditures for the redevelopment of the Oyo field in the OMLs, operating expenditures, exploration activities in our unevaluated leaseholds, working capital needs, and interest and principal payments under current indebtedness.

 

The Company has a $25.0 million borrowing facility under a Promissory Note with Allied, with a maturity date now extended through August 2016. The current terms of the Promissory Note allow for the entire $25.0 million facility amount to be utilized for general corporate purposes. As of December 31, 2014, $11.2 million was outstanding under the Promissory Note. See Note 8 – Debt to the Notes to Consolidated Financial Statements for further information.

 

In conjunction with the Allied Transaction, the Company entered into a Share Purchase Agreement with the PIC. Pursuant to the Share Purchase Agreement, the Company received $270.0 million from the PIC, and remitted $170.0 million to Allied, as partial consideration for the purchase of the Allied Assets. The Company retained a net $100.0 million amount to partially fund the Oyo field redevelopment program. See Note 4 – Acquisitions to the Notes to Consolidated Financial Statements for further information.

 

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 Term Loan Facility is to provide funding for continued expansion and development of the OMLs. As of December 31, 2014, $100.0 million was outstanding under the Term Loan Facility. See Note 8. — Debt to the Notes to Consolidated Financial Statements for further information.

 

In February 2015, the Company received a term sheet from a trading company for a commodity-based Full Recourse Prepayment Facility (the “Prepayment Facility”). The Prepayment Facility would allow the Company to borrow an initial sum, up to $65.0 million, towards the Oyo field redevelopment program. Additional funds, up to $100.0 million, would be available for borrowings post-production.  The Company expects the Full Recourse Prepayment Facility to be finalized in the second quarter of 2015.

 

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In March 2015, the Company entered into a new borrowing facility with Allied for a Convertible Note (the “2015 Convertible Note”) separate from the existing $25.0 million Promissory Note and the $50.0 million Convertible Subordinated Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. The 2015 Convertible Note will mature in December 2016. Interest accrues at the rate of LIBOR plus 5%, and is payable quarterly. See Note 16 – Subsequent Events to the Notes to Consolidated Financial Statements for further information.

 

The Company currently anticipates commencement of production from the Oyo-8 and Oyo-7 wells in March and May 2015, respectively, and expects combined initial production rates from the two wells of approximately 14,000 BOPD.  If the Company experiences significant delays in bringing the Oyo-8 and Oyo-7 wells onto production, if actual production rates are substantially below anticipated rates, or if oil prices decline significantly from current levels, the Company will need to seek additional sources of capital.

 

The Company’s majority shareholder has formally committed to provide the Company with additional funding, the form of which would be determined at the time of funding, sufficient to maintain the Company’s operations and to allow the Company to meet its current and future obligations as they become due for one year from March 12, 2015, the date of said commitment.

 

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 these financial statements are issued.

 

CONTRACTUAL OBLIGATIONS

 

The following table summarizes the Company’s significant estimated future contractual obligations at December 31, 2014:

 

 

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

 

Off-Balance Sheet Arrangements

 

From time-to-time, we may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As of December 31, 2014 material off-balance sheet obligations include obligations under a short-term drilling rig contract, operating leases with the FPSO and certain employment contracts. Other than the material off-balance sheet arrangements discussed above, no other arrangements are likely to have a current or future material effect on our financial condition, results from operations, liquidity, capital expenditures or capital resources.

 

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CRITICAL ACCOUNTING POLICIES

 

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and oil and natural gas reserve quantities. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States.

 

Successful Efforts Method of Accounting for Oil and Gas Activities

 

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 costs 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 range between three to five years, or the lease term if shorter. Repairs and maintenance charges, including workover costs, are charged to expense as incurred.

 

Impairment of Long-Lived Assets

 

The Company reviews its long-lived assets in property, plant and equipment for impairment each reporting period, or 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 proved properties when the estimated undiscounted future cash flows expected to result from the asset are less than its carrying amount. 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.

 

Unevaluated leasehold costs are assessed for impairment at the end of each reporting period and transferred to proved oil and gas properties to the extent they are associated with successful exploration activities. Significant unevaluated leasehold costs are assessed individually for impairment, based on the Company’s current exploration plans, and any indicated impairment is charged to expense.

 

Asset Retirement Obligations

 

We account 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 us 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 7 – Asset Retirement Obligations to the Notes to Consolidated Financial Statements for further information.

 

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Stock-Based Compensation

 

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

 

RECENTLY ISSUED ACCOUNTING STANDARDS

 

In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU No. 2014-08 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. ASU No. 2014-08 is effective for fiscal years beginning after December 15, 2014, and 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 ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which are 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, and this guidance will replace most existing revenue recognition guidance when it becomes effective. ASU No. 2014-09 is effective for interim and annual periods beginning after December 15, 2016, and we will adopt this standards update, as required, beginning with the first quarter of 2017. We are in the process of evaluating the impact, if any, of this guidance on our consolidated financial statements.

 

In June 2014, the FASB issued ASU No. 2014-09, Compensation – Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. 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 ASU No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  ASU No 2014-15 contains 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.  ASU No. 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods thereafter.  We will adopt this standards update, as required, beginning with the first quarter of 2017.  We are in the process of evaluating the impact this guidance will have on our footnote disclosures.

 

In November 2014, the FASB issued ASU No. 2014-17, Business Combinations: Pushdown Accounting. This ASU provides companies with the option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The election to apply pushdown accounting can be made either in the period in which the change of control occurred, or in a subsequent period. This ASU was effective on November 18, 2014. Implementation of this standard is not expected to have a material effect on our consolidated financial statements.

 

 

 

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

 

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Foreign Currency Exchange Risk

 

Our results of operations and financial conditions are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our capital and operating costs in Nigeria are denominated in Naira, the Nigerian local currency. Similarly, portions of our exploration costs in Kenya, The Gambia, and Ghana are denominated in each country’s respective local currency. Historically, the exchange rate between the U.S. dollar and the local currencies in the countries in which we operate has fluctuated widely in response to international political conditions, general economic conditions, and other factors beyond our control.

 

The weighted average exchange rate between the U.S. dollar and the Nigerian Naira was 162.76 Naira per each U.S. dollar in the year ended December 31, 2014. For the year ended December 31, 2014, a 10% fluctuation in the weighted average exchange rate between the U.S. dollar and the Nigerian Naira would have had an approximate $1.6 million impact on our capital and operating costs in Nigeria.

 

To date, we have not engaged in hedging activities to hedge our foreign currency exposure in our foreign operations. In the future, we may enter into hedging instruments to manage our foreign currency exchange risk or continue to be subject to exchange rate risk.

 

Commodity Price Risk

 

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

 

Historically, realized commodity prices received for our crude oil sales have been tied to the Brent oil prices. Prices received have been volatile and unpredictable. For the year ended December 31, 2014, a $10.00 fluctuation in the prices received for our crude oil sales would have had an approximate $ 5.0 million impact on our revenues.

 

We do not currently engage in hedging activities to hedge our exposure to commodity price risks. In the future, we may enter into hedging instruments to manage our exposure to fluctuations in commodity prices.

 

Interest Rate Risk

 

We are exposed to changes in interest rates, primarily from possible fluctuations in the London Interbank Borrowing Rate (“LIBOR”). The interest rates on our debt obligations are stated at floating rates tied to the LIBOR. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. For the year ended December 31, 2014, the weighted average interest rate on our variable rate debt was 8.05%. Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our various debt facilities would result in an increase of our interest expense by $1.8 million over a twelve month period.

 

 

The Company’s Consolidated Financial Statements and the accompanying Notes that are filed as part of this Annual Report are listed under Item 15. Exhibits, Financial Statements and Schedules and are set forth immediately following the signature pages of this Form 10-K.

 

 

None.

 

 

Evaluation of Disclosure Controls and Procedures

 

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

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

 

Management’s Report On Internal Control Over Financial Reporting

 

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

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

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014, based on the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on this assessment, management, including the Company’s CEO and PFO, concluded that our internal control over financial reporting was effective as of December 31, 2014.

 

Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Form 10-K, has audited the effectiveness of our internal control over financial reporting as of December 31, 2014, as stated in their report, which is included herein.

 

Changes in Internal Control Over Financial Reporting

 

No change in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2014, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors and Shareholders

 

CAMAC Energy Inc.

 

We have audited the internal control over financial reporting of CAMAC Energy Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

 

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

 

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

 

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

 

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2014, and our report dated March 16, 2015 expressed an unqualified opinion on those financial statements.

 

/s/ GRANT THORNTON LLP

Houston, Texas

March 16, 2015

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None.

 

 

 

46

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PART III

 

 

The information required by this item will be included in the Company’s Definitive Proxy Statement (the “Proxy Statement”) for its 2015 annual meeting of shareholders, and is incorporated by reference. The Proxy Statement will be filed with the SEC within 120 days subsequent to December 31, 2014.

 

 

The information required under Item 11 of Form 10-K will be set forth in the 2015 Proxy Statement and is incorporated herein by reference.

 

 

The information required under Item 12 of Form 10-K will be set forth in the 2015 Proxy Statement and is incorporated herein by reference.

 

 

The information required under Item 13 of Form 10-K will be set forth in the 2015 Proxy Statement and is incorporated herein by reference.

 

 

The information required under Item 14 of Form 10-K will be set forth in the 2015 Proxy Statement and is incorporated herein by reference.

 

 

 

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PART IV

 

 

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

 

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

 

48

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The following exhibits are filed with the report:

 

49

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50

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51

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SIGNATURES

 

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

 

Dated: March 16, 2015

 

 

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

 

 

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board of Directors and Shareholders

 

CAMAC Energy Inc.

 

We have audited the accompanying consolidated balance sheets of CAMAC Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive loss, changes in equity, and cash flows for each of the three years in the period ended December 31, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2015 expressed an unqualified opinion thereon.

 

/s/ GRANT THORNTON LLP

Houston, Texas

March 16, 2015

 

 

F-1

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CAMAC ENERGY INC.

CONSOLIDATED BALANCE SHEETS

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

 

 

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

 

F-2

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CAMAC ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except for per share amounts)

 

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

 

F-3

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CAMAC ENERGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands) 

 

    

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

 

 

 

F-4

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CAMAC ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(In thousands) 

 

 

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

 

 

 

F-5

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CAMAC ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

 

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

 

 

 

F-6

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

NOTE 1. — COMPANY DESCRIPTION

 

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 Lagos, Nigeria, Nairobi, Kenya, Banjul, The Gambia, Accra, Ghana and Johannesburg, South Africa.

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

 

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 9 – Related Party Transactions for further information.

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.  

 

NOTE 2. — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

 

The accompanying consolidated financial statements include the accounts of the Company and its wholly owned and majority-owned direct and indirect subsidiaries, and have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). All significant intercompany transactions and balances have been eliminated in consolidation. The consolidated financial statements reflect all adjustments that 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 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 effected on February 21, 2014. Because the Stock Dividend exceeded 25% of the total shares of common stock outstanding prior to the distribution, it was considered a large stock dividend. Accordingly, 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 located offshore Nigeria (the “OMLs”), which include the currently producing Oyo field (the “Allied Assets”), from Allied (the “Allied Transaction”). Pursuant to the terms of the Transfer Agreement entered into with Allied, the Company issued approximately 497.5 million shares of common stock to Allied, as partial consideration for the Allied Assets. Allied is a subsidiary of CEHL, the Company’s majority shareholder, and deemed to be under common control. Accordingly, the net assets acquired from Allied were recorded at their respective carrying values as of the acquisition date. The shares issued to Allied and the financial statements presented for all periods included herein are presented as though the transfer of the Allied Assets had occurred in June 2012, the effective date when Allied acquired the Allied Assets from an independent third party. See Note 4 – Acquisitions for further information.

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 13 - Discontinued Operations, for further information.

 

 

F-7

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

Significant Accounting Policies

 

Principles of Consolidation

 

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

 

Use of Estimates

 

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates based on assumptions. Estimates affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenues and expenses during the reporting periods. Accordingly, accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the Company’s consolidated financial statements are appropriate, actual results could differ from those estimates.

 

Estimates that may have a significant effect on the Company’s financial position and results from operations include share-based compensation assumptions, oil and natural gas reserve quantities, depletion and amortization relating to oil and natural gas properties, asset retirement obligation assumptions, and income taxes. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, more experience is acquired, additional information is obtained and our operating environment changes.

 

Cash and Cash Equivalents

 

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

 

Restricted Cash

 

Restricted cash consists of cash deposits that are contractually restricted for withdrawal or required to be maintained in a reserve bank account for a specific period of time, as provided for under certain agreements with third parties.

 

Restricted cash as of December 31, 2014 consists of $10.4 million held in a debt service reserve account to secure certain repayments pursuant to the Term Loan Facility in Nigeria. The Company had no restricted cash balance at December 31, 2013.

 

Accounts Receivable and Allowance for Doubtful Accounts

 

Accounts receivable are accounted for at cost less allowance for doubtful accounts. The Company establishes 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, 2014 and 2013, no allowance for doubtful accounts was necessary.

 

Partner accounts receivables consist of balances owed from joint venture (“JV”) partners. As of December 31, 2014, the Company was owed $0.5 million from its Ghana JV partners for their share of the expenditures incurred in the Shallow Water Tano block, pursuant to the Ghana JV Joint Operating Agreement.

 

Crude Oil Inventory

 

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. The Company had crude oil inventory of $1.1 million and $16.3 million as of December 31, 2014 and 2013, respectively.

Successful Efforts Method of Accounting for Oil and Gas Activities

 

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

F-8

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

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.

 

A portion of the Company’s oil and gas properties include oilfield materials and supplies inventory to be used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or market, which approximates fair value, and they are regularly assessed for obsolescence. Oilfield materials and supplies inventory balances were $30.5 million and $25.4 million at December 31, 2014 and 2013, respectively.

Depreciation, depletion and amortization costs 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 range between three to five years, or the lease term if shorter. Repairs and maintenance charges, including workover costs, are charged to expense as incurred.

 

Impairment of Long-Lived Assets

 

The Company reviews its long-lived assets in property, plant and equipment for impairment each reporting period, or 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 proved properties when the estimated undiscounted future cash flows expected to result from the asset are less than its carrying amount. 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.

 

Unevaluated leasehold costs are assessed for impairment at the end of each reporting period and transferred to proved oil and gas properties to the extent they are associated with successful exploration activities. Significant unevaluated leasehold costs are assessed individually for impairment, based on the Company’s current exploration plans, and any indicated impairment is charged to expense.         

 

Asset Retirement Obligations

 

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

 

Revenues

 

Revenues are recognized when crude oil is delivered to a buyer. The recognition criteria are satisfied when there exists a signed contract with defined pricing, delivery, and acceptance, as defined in a contract, and there is no significant uncertainty of collectability. Crude oil revenues are recorded net of royalties.

 

Income Taxes

 

The Company provides for income taxes using the asset and liability method of accounting for income taxes in accordance with ASC Topic 740 (Income Taxes). Under the asset and liability method, deferred tax assets and liabilities are recognized for temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting purposes and for operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and

F-9

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

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 12 – Income Taxes for further information.

Debt Issuance Costs

Debt issuance costs consist of certain costs paid to lenders in the process of securing a borrowing facility. Debt issuance costs incurred are capitalized and subsequently charged to interest expense over the term of the related debt, using the effective interest rate method.

As of December 31, 2014, unamortized debt issuance costs were $1.9 million, of which $1.3 million was classified as long-term. There were no debt issuance costs as of December 31, 2013.

 

Stock-Based Compensation

 

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

 

Reporting and Functional Currency

 

The Company has adopted the U.S. dollar as the functional currency for all of its foreign subsidiaries. Gains and losses on foreign currency transactions are included in results of operations, in accordance with ASC Topic 830 (Foreign Currency Matters).

Net Earnings (Loss) Per Common Share

The Company computes earnings or loss per share under ASC Topic 260 (Earnings per Share). Basic 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 outstanding at the end of the reporting period. Diluted net earnings or loss per share is computed by dividing net earnings or loss by the fully dilutive common stock equivalent, which consists of shares outstanding, augmented by potentially dilutive shares issuable upon the exercise of the Company’s stock options, unvested restricted stock awards, and stock warrants and conversion of the Convertible Subordinated Note, calculated using the treasury stock method.

The table below sets forth the number of stock options, warrants, non-vested restricted stock, and shares issuable upon conversion of Convertible Subordinated Note that were excluded from dilutive shares outstanding during the years ended December 31, 2014, 2013 and 2012, as these securities are anti-dilutive because the Company was in a loss position each year.

 

 

Upon the occurrence of certain events, the Company is also contingently liable to make additional payments to Allied, under the Transfer Agreement, up to an additional amount totaling $50.0 million in cash, or the equivalent in shares of the Company’s common stock, at Allied’s option. See Note 10 – Commitments and Contingencies for further information.

 

F-10

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

Non-Controlling Interests

 

The Company reports its non-controlling interests as a separate component of equity. The Company also presents the consolidated net loss and the portion of the consolidated net loss allocable to the non-controlling interests and to the shareholders of the Company separately in its consolidated statements of operations. Losses attributable to the non-controlling interests are allocated to the non-controlling interests even when those losses are in excess of the non-controlling interests’ investment basis.

 

As of December 31, 2014, the non-controlling interest recorded in equity was $0.7 million, attributable to the joint ownership of an affiliate in our CAMAC Energy Ghana Limited subsidiary. No non-controlling interests existed as of December 31, 2013.

 

Fair Value of Financial Instruments

 

Fair value is the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between willing market participants at the measurement date.

 

The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, accounts receivable, inventory, deposits, accounts payable and accrued liabilities, and debts at floating interest rates, approximate their fair values at December 31, 2014 and 2013, respectively, principally due to the short-term nature, maturities or nature of interest rates of the above listed items.

 

Reclassification

 

Certain reclassifications have been made to the 2013 and 2012 consolidated financial statements to conform to the 2014 presentation. These reclassifications were not material to the accompanying consolidated financial statements.

 

Recently Issued Accounting Standards

 

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU No. 2014-08 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. ASU No. 2014-08 is effective for fiscal years beginning after December 15, 2014, and the Company 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 the Company’s consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which are 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, and will replace most existing revenue recognition guidance when it becomes effective. ASU No. 2014-09 is effective for interim and annual periods beginning after December 15, 2016, and the Company 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 ASU No. 2014-09, Compensation – Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. 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. The Company 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 its consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. ASU No 2014-15 contains updated guidance on determining when and how reporting entities must disclose going concern uncertainties in its financial statements. The objective of

F-11

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

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. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods thereafter. The Company 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.

 

In November 2014, the FASB issued ASU No. 2014-17, Business Combinations: Pushdown Accounting. This ASU provides companies with the option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The election to apply pushdown accounting can be made either in the period in which the change of control occurred, or in a subsequent period. This ASU was effective on November 18, 2014. Implementation of this standard is not expected to have a material effect on the Company’s consolidated financial statements.

 

NOTE 3. - LIQUIDITY MATTERS

The Company’s primary cash requirements are for capital expenditures for the redevelopment of the Oyo field in the OMLs, operating expenditures, exploration activities in its unevaluated leaseholds, working capital needs, and interest and principal payments under current indebtedness.

 

The Company currently anticipates commencement of production from the Oyo-8 and Oyo-7 wells in March and May 2015, respectively, and expects combined initial production rates from the two wells of approximately 14,000 BOPD.  If the Company experiences significant delays in bringing the Oyo-8 and Oyo-7 wells onto production, if actual production rates are substantially below anticipated rates, or if oil prices decline significantly from current levels, the Company will need to seek additional sources of capital.

 

The following discussion relates to the Company’s liquidity plans to finance the redevelopment of the Oyo field, as well as required operating and exploration expenditures.

 

The Company has a $25.0 million borrowing facility under a Promissory Note with Allied, with a maturity date now extended through August 2016. The current terms of the Promissory Note allow for the entire $25.0 million facility amount to be utilized for general corporate purposes. As of December 31, 2014, $11.2 million was outstanding under the Promissory Note. See Note 8 – Debt for further information.

 

In February 2015, the Company received a term sheet from a trading company for a commodity-based Full Recourse Prepayment Facility (the “Prepayment Facility”). The Prepayment Facility would allow the Company to borrow an initial sum, up to $65.0 million, towards the Oyo field redevelopment program. Additional funds, up to $100.0 million, would be available for borrowings post-production.  The Company expects the Full Recourse Prepayment Facility to be finalized in the second quarter of 2015.

 

In March 2015, the Company entered into a borrowing facility with Allied for a Convertible Note (the “2015 Convertible Note”) separate from the existing $25.0 million Promissory Note and the $50.0 million Convertible Subordinate Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. The 2015 Convertible Note matures in December 2016. Interest accrues at the rate of LIBOR plus 5.0%, and is payable quarterly.

 

The 2015 Convertible Note is convertible into shares of the Company’s common stock upon the occurrence and continuation of an event of default, at the sole option of the holder. The number of shares issuable upon conversion is the conversion amount divided by the conversion price, defined as the volume weighted average of the closing sale prices on the NYSE MKT for a share of common stock for the five complete trading days immediately preceding the conversion date.

 

Upon execution of the 2015 Convertible Note, the Company drew $20.0 million under the note and issued to Allied warrants to purchase approximately 9.8 million shares of the Company’s common stock at a $0.41 strike price.  Additional warrants will be issuable in connection with future draws, with the strike price for those warrants determined based on the market price of the Company’s common stock at the time of such future draws.

    

The Company’s majority shareholder has formally committed to provide the Company with additional funding, the form of which would be determined at the time of funding, sufficient to maintain the Company’s operations and to allow the Company to meet its current and future obligations as they become due for one year from March 12, 2015, the date of said commitment.

 

F-12

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

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 these financial statements are issued.

 

NOTE 4. — ACQUISITIONS

 

The Allied Assets

 

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 $170.0 million in cash, issued approximately 497.5 million shares of the Company’s common stock and delivered a $50.0 million Convertible Subordinated Note to Allied (the “Convertible Subordinated Note”).

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 incorporated in the Republic of South Africa (“PIC”), for an aggregate cash investment of $270.0 million through a private placement of 376.9 million shares of common stock (the “Private Placement”).  See Note 10 – Commitments and Contingencies for information regarding additional payments due to Allied upon the occurrence of certain future events.

 

The table below sets forth a summary of the contractual purchase consideration paid for the Allied Assets (In thousands):

 

     (1) Since the cash and debt consideration exceeds the carrying value of the assets acquired, no value was assigned to the shares issued

 

Because Allied is a wholly owned subsidiary of CEHL, the Company’s majority shareholder, Allied and the Company are deemed under common control. 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.

 

For the periods prior to January 1, 2014, the Allied Assets were recorded as if CEHL had acquired the Allied Assets and contributed them to the Company. This includes the cost to acquire the Allied Assets from a third party in June 2012, as well as costs related to the drilling of the Oyo-7 well incurred by Allied in 2013.

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

 

 

F-13

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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.

 

Award of the Tano Block in Ghana

 

In April 2014, the Company, through an indirect 50%-owned subsidiary, signed a Petroleum Agreement with the Republic of Ghana (the “Petroleum Agreement”) for the Expanded Shallow Water Tano block. The contracting parties, which hold 90% of the participating interest in the block, are CAMAC Energy Ghana Limited as the operator, GNPC Exploration and Production Company Limited, and Base Energy, holding 60%, 25%, and 15% share of the participating interest, respectively. Ghana National Petroleum Company initially has a 10% carried interest through the exploration phase, and will have the option to acquire an additional 10% paying interest following a declaration of commerciality.

 

The Petroleum Agreement provides for an initial exploration period of two years from the effective date of the Petroleum Agreement, with specified work obligations during that period, including reprocessing of existing 2-D and 3-D seismic data and drilling of one exploration well. The Contracting Parties have the right to apply for a first extension period of one and one-half years and a second extension period of up to two and one-half years. Each extension period has specified additional minimum work obligations, including (i) conducting geological and geophysical studies during the first extension period and (ii) drilling one exploration well during the first extension period and, depending on the length of the extension, one or two wells during the second extension period. In addition, within nine months of the effective date of the Petroleum Agreement, the Contracting Parties will review and evaluate three previously discovered and appraised fields, the North, South and West Tano Fields, and declare whether or not those discoveries are commercial discoveries.

 

In January 2015, the Petroleum Agreement became effective, following the signing of a Joint Operating Agreement between the contracting parties. Preliminary work has commenced on the evaluation of the discovered fields to determine economic viability.

 

 

NOTE 5. — PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment were comprised of the following:

 

 

All of the Company’s oilfield assets are located offshore Nigeria in the OMLs. “Work-in-progress and other” includes ongoing drilling costs, as well as warehouse inventory items purchased as part of the redevelopment plan of the Oyo field     .

 

The Company’s unevaluated leasehold costs include costs expended to acquire the rights to the exploration acreage in its various oil and gas properties. The $9.4 million unevaluated leasehold cost in 2014 includes $1.2 million      payment to acquire rights to the Ghana properties.    

    

F-14

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

NOTE 6. — SUSPENDED EXPLORATORY WELL COSTS

 

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. As of December 31, 2014 and 2013, the Company’s suspended exploratory well costs were $26.5 million for the costs related to the Miocene exploratory drilling activities.

 

In August 2014, the Oyo-8 well was drilled to a total vertical depth of approximately 6,059 feet (approximately 1,847 meters) and successfully encountered four new oil and gas reservoirs in the eastern fault block, with total gross hydrocarbon thickness of 112 feet, based on results from the LWD data, reservoir pressure measurement, and reservoir fluid sampling. Management has commenced a detailed evaluation of the results and plans to further explore the Pliocene formation in the eastern fault block and establish the size of the incremental additions. Suspended exploratory well costs were $6.5 million at December 31, 2014 for the costs related to the Pliocene exploration drilling activities in the eastern fault block.

 

              

 

NOTE 7. —ASSET RETIREMENT OBLIGATIONS

 

The Company’s asset retirement obligations primarily represent the estimated fair value of the amounts that will be incurred to plug, abandon and remediate its 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 summarizes changes in the Company’s asset retirement obligations during the years ended December 31, 2014 and 2013:

 

 

The table below shows the current and long-term portions of the Company's asset retirement obligations as of the end of December 31, 2014 and 2013:

 

 

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

 

NOTE 8. — DEBT

 

As of December 31, 2014, the Company’s long-term debt, excluding asset retirement obligations, was $154.2 million, consisting principally of $11.2 million owed under a related party Promissory Note, $50.0 million Convertible Note owed to a related party, and $93.0 million representing the long-term portion of debt owed under a Term Loan Facility.

 

Promissory Note – Long-Term

 

The Company has a $25.0 million borrowing facility under a Promissory Note (the “Promissory Note”) with Allied. Interest accrues on the outstanding principal under the Promissory Note at a rate of the 30-day London Interbank Offered Rate (“LIBOR”) plus 2% per

F-15

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

annum, payable quarterly. The obligations under the Promissory Note have been guaranteed by the Company. In March 2015, the Promissory Note was amended to extend the maturity date by one year to July 2016. The entire $25.0 million facility amount can be utilized for general corporate purposes. As of December 31, 2014 and 2013, the Company owed $11.2 million and $6.5 million, respectively, under the Promissory Note.

 

Convertible Subordinated Note – Long-Term

 

As partial consideration in connection with the February 2014 acquisition of the Allied Assets, the Company issued a $50.0 million Convertible Subordinated Note in favor of Allied (the “Convertible Subordinated Note”). Interest on the Convertible Subordinated Note accrues at a rate per annum of one-month LIBOR plus 5%, payable quarterly in cash until the maturity of the Convertible Subordinated Note five years from the closing of the Allied Transaction.

 

At the election of the holder, the Convertible Subordinated Note is convertible into shares of the Company’s common stock at an initial conversion price of $0.7164 per share, subject to anti-dilution adjustments. The Convertible Subordinated Note is subordinated to the Company’s existing and future senior indebtedness and is subject to acceleration upon an Event of Default (as defined in the Convertible Subordinated Note). The Company may, at its option, prepay the Convertible Subordinated Note in whole or in part, at any time, without premium or penalty, and is subject to mandatory prepayment upon (i) the Company’s issuance of capital stock or incurrence of indebtedness, the proceeds of which the Company does not apply to repayment of senior indebtedness or (ii) any capital markets debt issuance to the extent the net proceeds of such issuance exceed $250.0 million. Allied may assign all or any part of its rights and obligations under the Convertible Subordinated Note to any person upon written notice to the Company. As of December 31, 2014, the Company owed $50.0 million under the Convertible Subordinated Note.

Term Loan Facility

 

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 the OMLs 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 the OMLs 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 the OMLs. The Company was in compliance with all loan covenants as of December 31, 2014.

 

In 2014, the Company recognized an unrealized foreign currency gain of $0.8 million on the Naira portion of the loan, resulting in a net balance of $99.2 million owed as of December 31, 2014, under the Term Loan Facility. Of this amount, $93.0 million was classified as long-term and $6.2 million as short-term. Scheduled principal repayments on the outstanding balance on the Term Loan Facility are as follows (in thousands):

 

 

F-16

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

 

Upon executing the Term Loan Facility, the Company paid a commitment fee of $2.1 million, which was recorded as debt issuance costs in the Company’s consolidated balance sheets. As of December 31, 2014, $1.9 million of the debt issuance costs remained unamortized, of which $1.3 million were classified as long-term.

 

NOTE 9. — RELATED PARTY TRANSACTIONS

 

Assets and Liabilities

 

The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates. The table below sets forth the related party assets and liabilities as of December 31, 2014 and 2013:

 

 

As of December 31, 2014, the Company owed $9.4 million to certain affiliates, primarily for operational expenses incurred during the period. As of December 31, 2013, the Company owed $25.7 million to Allied primarily as reimbursement for costs incurred related to the drilling of development wells in the Oyo field.

As of December 31, 2014, the Company had a long-term note payable balance of $61.2 million owed to an affiliate, consisting of a $50.0 million Convertible Subordinated Note, and $11.2 million in borrowings under the Promissory Note. As of December 31, 2013, the balance under the Promissory Note was $6.5 million, which was classified as a short-term liability.

 

Results from Operations

 

The table below sets forth the transactions incurred with affiliates during the years ended December 31, 2014, 2013, and 2012:

 

 

An affiliate of CEHL, the Company’s majority shareholder, provides procurement and logistical support services to the Company’s Nigerian operations. In 2014, in connection therewith, the Company incurred approximately $20.4 million worth of operating and capital costs with the affiliate.    

    

Non-controlling Interests

 

In April 2014, the Company, through its 50% ownership of its CAMAC Energy Ghana Limited subsidiary, signed a Petroleum Agreement with the Republic of Ghana relating to the Expanded Shallow Water Tano block offshore Ghana. An affiliate of the Company’s majority shareholder owns the remaining 50% non-controlling interest in the CAMAC Energy Ghana Limited subsidiary. See Note 4 – Acquisitions for further information on the acquisition of certain mineral interests in the Expanded Shallow Water Tano block in Ghana.

 

 

F-17

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

NOTE 10. — COMMITMENTS AND CONTINGENCIES

 

Commitments

 

The following table summarizes the Company’s significant future commitments on non-cancellable operating leases and estimated obligations arising from its minimum work obligations at December 31, 2014:

 

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. At December 31, 2014, the annual minimum commitment per the terms of the agreement is approximately $48.4 million for each of the years 2015 through 2020.

In December 2014, the Company entered into a short-term drilling contract with the semi-submersible drilling rig Sedco Express to complete the horizontal drilling portion of wells Oyo-7 and Oyo-8. The minimum contract commitment is for a 45 day period, with a remaining obligation approximating $4.5 million.

 

The Company rents office space and miscellaneous office equipment under non-cancelable operating leases. Office rent expense, net of sublease income, for the years ended December 31, 2014, 2013, and 2012 was $1.0 million, $0.7 million and $0.5 million, respectively. At December 31, 2014, minimum future rental commitments for operating leases were a total of $2.4 million.

The Company has minimum work obligation commitments related to its mineral property interests in four blocks in Kenya, two blocks in The Gambia, and one block in Ghana. The table above sets forth the Company’s future contractual obligations with regards to the minimum work obligations in each country.

 

Contingencies

 

Legal Contingencies

 

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. As of December 31, 2014, and through the filing date of this report, the Company does not believe the ultimate resolution of such actions or potential actions of which the Company is currently aware will have a material effect on its consolidated financial position or results of operations.

 

In January 2014, an affiliate of CEHL, the Company’s majority shareholder, and Northern Offshore International Drilling Company Ltd. (“Northern”) entered into an International Daywork Drilling Contract pursuant to which Northern agreed to provide the drillship Energy Searcher for the provision of drilling services offshore Nigeria. Pursuant to further contractual arrangements entered into in March 2014, the affiliate provided the drillship to CPL, with CPL assuming payment obligations under the drilling contract and receiving the right to enforce Northern’s obligations under the drilling contract. The Company guaranteed the performance by CPL of its obligations under these contractual arrangements.  The Company, CPL and the CEHL affiliate are referred to hereinafter as the “CAMAC Parties.”

 

F-18

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

On January 2, 2015, the CAMAC Parties received a notice from Northern purporting to terminate the drilling contract for failure to provide the required letter of credit thereunder and stating that the CAMAC Parties are required to pay Northern all outstanding unpaid invoices, the early termination fee, the demobilization fee and amounts due but not yet invoiced for work performed up to the date of termination. On January 7, 2015, the CAMAC Parties responded to Northern disputing the validity of the purported Northern termination, which under English law we believe constitutes a renunciation of the drilling contract and wrongful repudiatory breach thereof because of, among other things, the course of conduct by the parties. Specifically, the CAMAC Parties arranged for, and Northern agreed to and performed work in exchange for, issuing monthly prepayment invoices in lieu of the letter of credit. Because of Northern’s repudiatory breach, the CAMAC Parties elected to terminate the contract with immediate effect.  In addition, the January 7, 2015 letter set out other grounds for termination and claims against Northern for numerous material breaches of the drilling contract.

 

On January 12, 2015, Northern issued a request for arbitration in the London Court of International Arbitration (“LCIA”).  The request repeated the claims of Northern relating to the letter of credit as stated in the January 2, 2015 letter and asserted further breaches of contract, including for failure to pay invoices for work allegedly performed.  The request seeks payment of outstanding unpaid invoices, the early termination fee and the demobilization fee.  On February 10, 2015, the CAMAC Parties lodged their response to the request and outlined claims against Northern for breaches of the drilling contract for, among other things, wrongful termination of the contract, failure to maintain the well control equipment in good condition (including the blowout preventer), failure to maintain and repair the drilling unit, breach of warranty, failure to provide adequately skilled and competent personnel, failure to perform as a reasonable and prudent operator and failure to provide the drilling unit ready to commence operations by May 15, 2014. These breaches caused significant damages and loss to the CAMAC Parties, including wasted marine spread costs in excess of $50 million, i.e., the cost of other marine services that were accumulated while the rig incurred downtime, as recognized under English law, and delay damages in excess of $3 million due to delays in the commencement of operations.

 

Pursuant to the contract and LCIA rules, a tribunal of three arbitrators, one selected by each of Northern and the CAMAC Parties and the third appointed by the first two arbitrators, has been empaneled. Subsequently, Northern and the CAMAC Parties agreed to stay the arbitration pending mediation, which took place in Houston, Texas on March 6, 2015.

 

Contingency under the Allied Transfer Agreement

 

As provided for under the Transfer Agreement with Allied, the Company is required to make the following additional payments upon the occurrence of certain future events: (i) $25.0 million cash or the equivalent in shares of the Company’s common stock, within fifteen days following the approval of a development plan by the Nigerian Department of Petroleum Resources with respect to a first new discovery of hydrocarbons in a non-Oyo field area; and (ii) $25.0 million cash or the equivalent in shares of the Company’s common stock, within fifteen days starting from the commencement of the first hydrocarbon production in commercial quantities in a non-Oyo field area. The number of shares to be issued shall be determined by calculating the average closing price of the Company’s common stock over a period of thirty days, counted back from the first business day immediately prior to the approval of a development plan by the Nigerian Department of Petroleum Resources or the date of the first hydrocarbon production in commercial quantities, where applicable.

 

NOTE 11. — STOCK BASED COMPENSATION

 

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 100.0 million shares of common stock. Options awarded expire between five and ten years from the date of the grant, or a shorter term as fixed by the Board of Directors. In February 2014, the Company executed the amendment to the 2009 Plan, thereby increasing the number of shares that may be granted thereunder to 100.0 million shares.

 

F-19

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

Stock Options

 

During 2014, the Company granted approximately 2.4 million stock options with vesting periods from two to three years. The table below sets forth a summary of stock option activity for the year ended December 31, 2014.

 

 

The total intrinsic values of options outstanding and options exercisable were $0.8 million and $0.3 million, respectively, at December 31, 2014. The total intrinsic values realized by recipients on options exercised were $0.9 million in 2014, and nil in both 2013 and 2012.

The Company recorded compensation expense relative to stock options in 2014, 2013 and 2012 of $ 1.3 million, $1.1 million and $0.2 million, respectively. As of December 31, 2014, there were approximately $1.3 million of total unrecognized compensation cost related to stock options, with $0.9 million, and $0.4 million to be recognized during the years ended December 31, 2015 and 2016, 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 and the assumptions used in the model for options awarded in each year under equity incentive plans.

 

 

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

Stock Warrants

 

The table below sets forth a summary of stock warrant activity for the year ended December 31, 2014.

 

 

The total intrinsic values of warrants outstanding and exercisable was nil at December 31, 2014.

 

During the year ended December 31, 2014, as compensation for services received, the Company issued warrants to third parties to purchase 1.8 million shares of common stock at an exercise price of approximately $0.56. The warrants are exercisable at any time starting from the date of issuance and have a five year term. During the year ended December 31, 2014, the Company recognized stock-based compensation expense of $0.1 million related to these warrants, based on the Black-Scholes option pricing model.

The table below shows the weighted-average amounts and the assumptions used in the model for warrants issued during the year ended December 31, 2014.

 

 

Restricted Stock Awards (“RSA”)

 

In addition to stock options, the Company’s 2009 Plan allows for the grant of restricted stock awards (“RSAs”). The Company determines the fair value of RSAs based on the market price of its 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.

 

The table below sets forth a summary of RSA activity for the year ended December 31, 2014.

 

 

The Company recorded compensation expense relative to RSAs in 2014, 2013 and 2012 of $1.7 million, $0.9 million and $0.6 million, respectively.

 

F-21

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

The total grant date fair value of RSA shares that vested during 2014 was approximately $2.8 million. As of December 31, 2014, there were approximately $1.7 million of total unrecognized compensation cost related to non-vested RSAs, with $1.5 million, and $0.2 million to be recognized during the years ended December 31, 2015 and 2016, respectively.

 

NOTE 12. — INCOME TAXES

 

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

 

 

 

Significant components of our deferred tax assets are as follows:

 

 

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, Kenya and Ghana 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 $362.4 million and $264.0 million were recorded as of December 31, 2014 and 2013, respectively.

 

At December 31, 2014 and 2013, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.

 

F-22

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

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

 

 

 

 

NOTE 13. — DISCONTINUED OPERATIONS

 

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:

 

 

NOTE 14. — SEGMENT INFORMATION

 

The Company’s current operations are based in Nigeria, Kenya, The Gambia, and Ghana. 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).

 

F-23

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

The table below sets forth segment activity for the years ended December 31, 2014, 2013, and 2012.

 

 

The table below sets forth the total assets by segment as of December 31, 2014 and 2013.

 

 

NOTE 15. — SELECTED UNAUDITED QUARTERLY FINANCIAL DATA (In Thousands, except for per share amounts)

 

 

F-24

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CAMAC ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands)

 

 

NOTE 16. — SUBSEQUENT EVENTS

 

In February 2015, the Company granted to employees approximately 5.5 million shares of restricted stock, and issued approximately 0.3 million shares of its common stock to third party service providers. 

 

 

 

F-25

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CAMAC ENERGY INC.

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

(In Thousands)

 

The unaudited supplemental information on oil and gas exploration and production activities for 2014, 2013 and 2012 has been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. The totality of the Company’s proved reserves are located offshore Nigeria.

 

Estimated Net Proved Crude Oil Reserves

 

The following estimates of the net proved crude oil reserves in Nigeria are based on evaluations prepared by third-party reservoir engineers DeGolyer and MacNaughton (“D&M”). 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, 2014. 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.

 

 

 

 

S-1

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CAMAC ENERGY INC.

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

(In Thousands)

 

Capitalized Costs

 

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

 

 

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

 

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

 

 

 

Results of Continuing Operations

 

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

 

S-2

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CAMAC ENERGY INC.

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

(In Thousands)

 

 

Standardized Measure of Discounted Future Net Cash Flows

 

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, 2014) 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, 2014, 2013, and 2012, were $100.37, $108.63, and $112.77 per barrel of crude oil, respectively, including price differentials. Amounts below for production sold and production costs exclude royalties. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties.

 

 

Change in Standardized Measure of Discounted Future Net Cash Flows

 

 

S-3