Wrap Text
financial results for the year ended 31 December 2013
CAMAC ENERGY INCORPORATED
(Previously Pacific Asia Petroleum Inc.)
(Incorporated and registered in Delaware, United States of America)
Share code on the NYSE MKT: CAK
Share code on the JSE: CME
ISIN: US1317451011
USA ISIN: US1317451011
(“Camac” or “the company”)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
OR
- TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
001-34525
(Commission File Number)
CAMAC ENERGY INC.
(Exact name of registrant as specified in its charter)
Delaware 30-0349798
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
1330 Post Oak Blvd., Suite 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 ?
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 ?
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 ? No ?
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter)
during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes - No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is
not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ?
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in
Rule 12b-2 of the Exchange Act.
Large accelerated filer Accelerated filer - Non-accelerated filer Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes No -
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 $35,977,130 based on a
adjusted share price of $0.23. 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 5, 2014, there were 1,070,343,982 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement or Form 10-K/A relating to the Company’s Annual Meeting of Stockholders to be
held on May 14, 2014 are incorporated by reference in Part III of this report.
GLOSSARY OF OIL AND GAS TERMS
- Bbl – One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
- BOPD – One barrel of oil per day.
- MBbl – One thousand Bbls.
- 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.
- Royalty interest. A real property interest entitling the owner to receive a specified portion of the gross proceeds of the
sale of oil and natural gas production, or if the conveyance creating the interest provides, a specific portion of oil and
natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A
royalty interest owner has no right to consent to or approve the operation and development of the property, while the
owners of the working interests have the exclusive right to exploit the minerals on the land.
- Working interest. A real property interest entitling the owner to receive a specified percentage of the proceeds of the
sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest
to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a
portion of the working interest may participate either as operator or by voting their percentage interest to approve or
disapprove the appointment of an operator and drilling and other major activities in connection with the development
and operation of a property.
- Seismic data. Oil and gas companies use seismic data as their principal source of information to locate oil and gas
deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To
gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected
back to the surface by underground formations, where they are detected by geophones which digitize and record the
reflected waves. Computers are then used to process the raw data to develop an image of underground formations.
- 2-D seismic data. 2-D seismic 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 is a more reliable indicator of potential oil and natural gas reservoirs in the area
evaluated.
- Cost oil - The amounts recoverable for operating costs and capital costs incurred.
- Profit oil - The proceeds available after the allocation of cost oil, royalty oil and tax oil.
- Royalty oil – The portion of the available proceeds owned by the royalty interests.
- Tax oil – The amount of petroleum profit tax owed on the sale of crude oil.
PART I
ITEM 1. DESCRIPTION OF BUSINESS
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 of this Form 10-K for the discussion of risk factors.
Unless the context otherwise requires, the terms “we”, “us”, “our”, “Company” and “CAMAC” 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. is engaged in exploration, development and production of oil and gas outside the United States.
Members of the Company’s senior management team have experience in the fields of international business development,
geology, petroleum engineering, strategy, government relations and finance and previously held key positions in international
energy companies. Management will seek to utilize their experience, expertise and contacts to create value for CAMAC
shareholders. The Company’s exploration, development and production activities are currently focused in Sub-Saharan
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. Our shares are traded on the NYSE MKT under the symbol “CAK” and, as of February 24, 2014,
on the Johannesburg Stock Exchange under the symbol “CME”.
The Company’s asset portfolio consists of eight licenses in three countries covering an area of approximately 41,000 square
kilometers (approximately 10 million acres). The Company owns producing properties and conducts exploration activities as
a non-operator in Nigeria, conducts explorations activities as an operator onshore and offshore Kenya, and conducts
exploration activities as an operator in The Gambia.
CAMAC’s operating subsidiaries are CAMAC Energy Limited (“CEL”), CAMAC Petroleum Limited (“CPL”), CAMAC
Energy International Limited (“CEIL”), CAMAC Energy Ghana Limited, CAMAC Energy Kenya Limited, CAMAC Energy
Gambia A5 Limited, and CAMAC Energy Gambia A2 Limited and CAMAC Energy Sierra Leone Limited. Related parties
include CAMAC Energy Holdings Limited (“CEHL”), CAMAC International Nigeria Limited (“CINL”), CAMAC
International Limited (“CIL”) and Allied Energy PLC (“Allied”).
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 the above listed related parties. Dr. Lawal also owns 27.7% of CIL, which indirectly owns 100% of
CEHL. As a result, Dr. Lawal may be deemed to have an indirect material interest in transactions contemplated with any of
the above companies and their affiliates named above as the Company’s related parties.
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 SEC. We also make available, free of charge on or through our Internet
website (http://www.camacenergy.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the
Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our
website. The Company will also make available to any shareholder, without charge, copies of its 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.
The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street
NE, Washington, DC 20549-0213. The public may obtain information on the operation of the Public Reference Room by
calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and
information statements, and other information regarding issuers, including us, that file electronically with the SEC. The
public can obtain any documents that we file with the SEC at http://www.sec.gov.
Oil and Gas Activities
Nigeria
The Company currently owns 100% of the economic interests under a Production Sharing Contract (“PSC”) and related
assets, contracts and rights pertaining to those certain Oil Mining Leases 120 and 121 (“OMLs 120 and 121”) including the
producing Oyo Field which is located in deep-water (200-500 meters) approximately 75 km (46 miles) offshore Nigeria.
In December 2009, Allied, CINL and Nigerian Agip Exploration Limited (“NAE”) announced commencement of production
from the Oyo Field, located within a portion of the OMLs 120 and 121 in which Allied, CINL and NAE each held a
participating interest. The producing wells in the Oyo Field, the Oyo-5 well and the Oyo-6 well, have been connected to the
floating, production, storage, and offloading system (“FPSO”) Armada Perdana. The FPSO has a treatment capacity of
40,000 barrels of liquids per day, with gas treatment and re-injection facilities, and is capable of storing up to one million
barrels of crude oil. The first lifting (sale) of crude oil from the FPSO occurred in February 2010. As of December 31, 2013,
approximately 7.0 million Bbls of crude oil have been lifted from producing wells Oyo-5 and Oyo-6. Some of the associated
gas has been re-injected into the Oyo Field reservoir by a third well to minimize flaring and to maximize recovery. The
oilfield operations on and disposition of production from the OMLs 120 and 121, including the Oyo Field, were governed by
the PSC.
In April 2010, the Company acquired certain economic interests in the Oyo Field through the purchase of that portion 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
the Company’s Common Stock. In the 2010 transaction, CEHL became the majority shareholder of the Company. As part of
the transaction, the Company gave CEHL registration rights with respect to these shares.
In February 2011, the Company acquired all of Allied’s and CINL’s rights in the PSC outside the Oyo Field (the “Non-Oyo
Contract Rights”) for cash and the Company’s agreement to make additional payments, contingent upon completion of
specified milestones in any future exploration and development of the OMLs outside of the Oyo Field. Dr. Kase Lawal was
at that time the Company’s non-executive Chairman and member of the board of directors, and also a director of each of
CEHL and Allied, with indirect ownership of 27.7% of CEHL.
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. Beginning in December 2010,
the Company funded 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. The Company is entitled to recover such
costs from oil liftings as non-capital costs under the PSC, and as of December 31, 2013, $44.1 million of costs have been
recovered as revenue.
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 well in OML 120. In October 2013, the preliminary results
from the Oyo-7 well were announced. Based on logging while drilling (“LWD”) data, the well encountered gross oil pay of
133 feet (net oil pay of 115 feet) and gross gas pay of 103 feet (net gas pay of 93 feet) in the gas cap from the currently
producing Pliocene reservoir, with excellent reservoir quality. The top of the reservoir was penetrated at 5,564 feet. Shortl y
after in November 2013, the Company announced that the Oyo-7 well had 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 of the
Oyo Field. Hydrocarbons were encountered in three intervals totaling approximately 65 feet, as interpreted from the LWD
data. Currently, the Oyo-7 well has been temporarily plugged and suspended but is expected to be re-entered and completed
in the Pliocene reservoir as an oil producer in mid-2014.
In November 2013, the Company entered into a Transfer Agreement (the “Transfer Agreement”) pursuant to which the
Company agreed to acquire from Allied Energy Plc (“Allied”), a wholly owned subsidiary of CEHL (the 57.2% majority
stockholder of the Company), all remaining economic interests in the PSC and related assets, contracts and rights pertaining
to OMLs 120 and 121 including the currently producing Oyo Field (the “Allied Assets”). In consideration for the Allied
Assets, the Company agreed to issue 497,454,857 shares of the Company’s Common Stock, deliver to Allied a $50.0 million
convertible subordinated promissory note (the “Convertible Subordinated Note”) and pay $170.0 million in cash (the “Allied
Transaction”). The Allied Transaction closed February 21, 2014. Please see Note 15 – Subsequent Events of the Notes To
Consolidated Financial Statements for additional information on the Allied Transaction.
In January 2014, a long-term drilling contract was signed with Northern Offshore Ltd. (OLSO: NOF.OL) for the drillship
Energy Searcher. The rig is expected to be delivered to the Oyo Field in OML 120 in the first half of 2014 to commence
completion activities for the Oyo-7 well, drill and complete the Oyo-8 well, and potentially drill both the Oyo-9 well and one
Miocene exploration well. The agreement covers an initial term of one year, with an option to extend the contract for an
additional one year.
In February 2014, a long-term contract was signed for the floating, production, storage, and offloading system (“FPSO”)
Armada Perdana, the vessel that is currently connected to the Company’s producing wells Oyo-5 and Oyo-6 in OML 120.
The contract provides for an initial term of five 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.
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 exploration blocks L1B and L16, and new offshore exploration blocks L27
and L28. For all blocks, the Company is the operator, with the Government having the right to participate up to 20%, either
directly or through an appointee, in any area subsequent to declaration of a commercial discovery. The Company is
responsible for all exploration expenditures.
The Kenya PSCs for blocks L1B and L16 each provide for an initial exploration period of two years with specified minimum
work obligations during that period. Prior to the end of the initial exploration period, the Company will conduct, for each
block, a gravity and magnetic survey and acquire, process and interpret 2D seismic data. The gravity and magnetic survey on
blocks L1B and L16 was completed in April 2013. 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 3D seismic data and the
drilling of one exploratory well on each block during each such additional period. In December 2013, the Company initiated
an Environmental and Social Impact Assessment (“ESIA”) study in blocks L1B and L16 in order to obtain the license to
carry out a 2D seismic survey.
The Kenya PSCs for blocks L27 and L28 each provide for an initial exploration period of three years with specified
minimum work obligations during that period. Prior to the end of the initial exploration period, the Company will conduct,
for each block, a regional geological and geophysical study, acquire 2D seismic data and acquire, process and interpret 3D
seismic data. The Company has the right to apply for up to two additional two-year exploration periods with specified
additional minimum work obligations, including the drilling of one exploratory well on each block, during each such
additional period. CAMAC is participating in a multi-client combined gravity / magnetic and 2D seismic survey which is
currently underway in blocks L27 and L28.
In addition to the minimum work obligations, each of the Kenya PSCs requires annual surface rental payments, training fund
payments and contributions to local community development projects.
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 exploration blocks A2 and A5. For both blocks, the Compan y is
the operator, with the Gambian National Petroleum Company (“GNPC”) having the right to elect to participate up to a 15%
interest, following approval of a development and production plan. The Company is responsible for all expenditures prior to
such approval even if the GNPC elects to participate.
The Gambia Licenses for both blocks provide for an initial exploration period of four years with specified minimum work
obligations during that period. Prior to the end of the initial exploration period, the Company will conduct, for each block, a
regional geological study, acquire, process and interpret 750 sq. km of 3D seismic data, drill one exploration well to the total
depth of 5,000 meters below mean sea level and evaluate drilling results, with the first two work obligations (regional
geological study and 3D seismic data acquisition and processing) due prior to the end of the second year. The Company has
the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations,
including the drilling of one exploration well during each additional period for each block.
In addition to the minimum work obligations, The Gambia Licenses require annual rental payments, training and community
fees.
Reserves
The information included in this Annual Report on Form 10-K about our rights to proved reserves as of December 31,
2013, 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 right to proved reserves and the estimates of
proved crude oil reserves attributable to our net interests in oil and gas properties as of December 31, 2013. The scope and
results of D&M’s procedures are summarized in a letter which is included as an exhibit to this Annual Report on Form 10-K.
For further information on reserves, including information on future net cash flows and the standardized measure of
discounted future net cash flows, please refer to the “Supplemental Data on Oil and Gas Exploration and Producing
Activities (Unaudited)” within Part II, Item 8 of the Notes To Consolidated Financial Statements of this report.
Internal Controls for Reserve Estimation
Our policies regarding internal controls over the recording of reserve estimation require reserves to be in compliance with the
SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. The
reserve estimates prepared by D&M are 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 information and data furnished by us with respect to
ownership interests, oil production, well test data, historical costs of operation and development, product prices or any
agreements relating to current and future operations of the properties and sales of production. However, if in the course of its
work, something came to its attention which brought into question the validity or sufficiency of any such information or data,
D&M did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.
Technologies Used in Reserves Estimates
Proved reserves are those quantities of oil, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree
of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve
reasonable certainty, our independent petroleum consultants employed technologies that have been demonstrated to yield
results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves
include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost
information and property ownership interests. The accuracy of the estimates of our reserves is a function of:
• the quality and quantity of available data and the engineering and geological interpretation of that data;
• estimates regarding the amount and timing of future operating costs, taxes, development costs and workovers, and our
estimated participation in funding of future operating costs and capital expenditures, and ability to raise money to fund
these costs, all of which may vary considerably from actual results;
• the accuracy of various mandated economic assumptions such as the future prices of oil and natural gas; and
• the judgment of the persons preparing the estimates.
Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results,
reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.
Qualifications of Reserves Preparers and Advisors
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 31 years of practical experience in
petroleum engineering, with over 28 years in estimations and evaluation of reserves. He is a Registered Professional
Engineer in the State of Texas, License No. 74615.
We have on staff a Reservoir Engineering Advisor and Geological Advisor 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 Advisor, Mr. Lanre Dipeolu and Geological Advisor, Dr. Cesar Abeigne are primarily
responsible for the coordination of the third-party reserves report provided by D&M. Mr. Lanre Dipeolu has over 28 years of
experience in the oil industry and holds a BSc. in Petroleum Engineering from University of Ibadan, Nigeria and a MBA
from Herriot Watt University, Edinburgh, United Kingdom. He is a member of the Society of Petroleum Engineers. Dr.
Abeigne has over 20 years of international experience in oil and gas industry and holds a Ph.D. in Geosciences from
Montpellier University II, France. He has extensive experience in seismic to static modeling and advanced workflows on
naturally and stimulated fractured reservoirs in Petrel. He has owned a consulting firm in Houston and Dallas areas for more
than 10 years and is a member of the American Association of Petroleum Geologists (A.A.P.G.), Society of Exploration
Geophysicists (S.E.G.), Houston Geological Society (H.G.S.) and National Association of Black Geoscientists (N.A.B.G.).
Summary of Crude Oil Reserves
All of our rights to oil and gas reserves are located in Africa. Unaudited information regarding the estimated net quantities of
all our proved reserves and the standardized measure of discounted future net cash flows from the reserves is presented in the
“Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)” within Part II, Item 8 of the Notes To
Consolidated Financial Statements of this report. The reserves estimates have been prepared by D&M and were estimated in
accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”). Reserves
estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas
properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.
Set forth below is a summary of our oil and gas net proved reserves as of December 31, 2013, 2012, and 2011, respectively.
As of December 31,
2013 2012 2011
Proved developed Reserves 92 55 92
Proved undeveloped Reserves 2,389 3,043 2,571
Total proved reserves 2,481 3,098 2,663
Standardized measure of proved reserves
(thousands) $ 22,689 $ 65,712 $ 61,687
Development of Proved Undeveloped Reserves
Under current development plans, all proved undeveloped reserves as of December 31, 2013, are expected to be developed
within five years from the date of initial recognition of these reserves.
Oil and Gas Production, Prices and Production Costs — Significant Fields
The Oyo Field in Nigeria contains our entire total proved reserves as of December 31, 2013, 2012, and 2011, respectively.
Our share of average daily net production (excluding royalty) was 276 barrels per day in 2013, 401 barrels per day in 2012,
and 923 barrels per day in 2011. The weighted average sales price was $107.85 per barrel in 2013, $112.60 per barrel in
2012, and $112.91 per barrel in 2011. Production cost per barrel was $(9.12) per barrel in 2013, $6.34 per barrel in 2012 and
$8.61 per barrel in 2011.
Drilling Activity
In 2013, the company successfully drilled the Oyo-7 well and plans to complete the well and begin production in 2014. In
2012 and 2011 there were no new development or exploratory wells completed in the Company’s Nigeria interests in OML
120 and 121, including the Oyo Field.
Delivery Commitments
As of December 31, 2013, the Company had no delivery commitments.
Productive Wells
At December 31, 2013, the Company had rights to an interest in the Oyo Field, Offshore Nigeria. Currently there are two
gross productive wells in Nigeria. The number of net productive wells (net economic interest) in Nigeria at a particular date
under our Production Sharing Contract is affected by our percentage of Cost Oil and Profit Oil realized in each lifting. This
percentage has varied significantly between 2013 and 2012. Therefore, a calculation of net productive wells interest for a
particular year-end is not meaningful.
Acreage
Interests in developed and undeveloped acreage follow:
December 31, 2013
Developed Acres Undeveloped Acres Total Acres
Gross Net Gross Net Gross Net
Kenya 9,121,482 9,121,482 9,121,482 9,121,482
Gambia 658,822 658,822 658,822 658,822
Nigeria 8,600 5,200 434,900 260,900 443,500 266,100
Total 8,600 5,200 10,215,204 10,041,204 10,223,804 10,046,404
Pursuant to meeting the renewal requirements of each PSC, the Company has no acreage on which leases are scheduled to
expire within the three years after December 31, 2013.
Regulation
General
Our operations and our ability to finance and fund our growth strategy are affected by political developments and laws and
regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are
affected by:
- change in governments;
- civil unrest;
- price and currency controls;
- limitations on oil and natural gas production;
- tax, environmental, safety and other laws relating to the petroleum industry;
- changes in laws relating to the petroleum industry;
- changes in administrative regulations and the interpretation and application of such rules and regulations; and
- changes in contract interpretation and policies of contract adherence.
In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are
periodically changed, sometimes retroactively, for a variety of political, economic, environmental and other reasons.
Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry,
some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industr y
increases our cost of doing business and our potential for economic loss.
Competition
The Company competes with numerous large international oil companies and smaller oil companies that target opportunities
in markets similar to the Company’s, including the natural gas and petroleum markets. Many of these companies have far
greater economic, political and material resources at their disposal than the Company. The Company’s management team has
prior experience in the fields of petroleum engineering, geology, field development and production, operations, international
business development, finance and experience in management and executive positions with international energy companies.
Nevertheless, the markets in which we operate and plan to operate are highly competitive and the Company may not be able
to compete successfully against its current and future competitors. See Part I, Item 1A. Risk Factors for risk factors
associated with competition in the oil and gas industry.
Environmental and Government Regulation
Various federal, state, local and international laws and regulations relating to the discharge of materials into the environment,
the disposal of oil and natural gas wastes, or otherwise relating to the protection of the environment may affect our operations
and costs. We are committed to the protection of the environment and believe we are in 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, 2013, 2012 and 2011, we did not have any significant
expenditures relating to environmental and government regulation.
Employees
At December 31, 2013, the Company had 23 full-time employees in the United States and 24 full-time employees in Africa.
During 2014, the Company expects to hire additional personnel in certain operational and other areas as required for its
expansion efforts, and to maintain focus on its then-existing and new projects. The number and skill sets of individual
employees will be primarily dependent on the relative rates of growth of the Company’s different projects, and the extent to
which operations and development are executed internally or contracted to outside parties. In order for us to attract and retain
qualified personnel, we will have to offer competitive salaries to future employees.
ITEM 1A. RISK FACTORS
CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
All statements, other than statements of historical fact, included in this Form 10-K, including without limitation the
statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” are, or may be
deemed to be, forward-looking statements. Such forward-looking statements involve assumptions, known and unknown
risks, uncertainties and other factors, which may cause the actual results, performance or achievements of the Company, to be
materially different from any future results, performance or achievements expressed or implied by such forward-looking
statements contained in this Form 10-K.
In our capacity as Company management, we may from time to time make written or oral forward-looking statements with
respect to our long-term objectives or expectations which may be included in our filings with the SEC, reports to
stockholders and information provided on our web site.
The words or phrases “will likely,” “are expected to,” “is anticipated,” “is predicted,” “forecast,” “estimate,” “project,”
“plans to continue,” “believes,” or similar expressions identify “forward-looking statements.” Such forward-looking
statements are subject to certain risks and uncertainties that could cause actual results to differ materially from historical
earnings and those presently anticipated or projected. We wish to caution you not to place undue reliance on any such
forward-looking statements, which speak only as of the date made. We are calling to your attention important factors that
could affect our financial performance and could cause actual results for future periods to differ materially from any opinions
or statements expressed with respect to future periods in any current statements.
The following list of important factors may not be all-inclusive, and we specifically decline to undertake an obligation to
publicly revise any forward-looking statements that have been made to reflect events or circumstances after the date of such
statements or to reflect the occurrence of anticipated or unanticipated events. Among the factors that could have an impact on
our ability to achieve expected operating results and growth plan goals and/or affect the market price of our stock are:
- -Limited operating history, operating revenue or earnings history.
- Ability to raise capital to fund our current and future operations.
- Ability to develop oil and gas reserves.
- Dependence on key personnel, technical services and contractor support.
- Fluctuation in quarterly operating results.
- Possible significant influence over corporate affairs by significant stockholders.
- Ability to enter into definitive agreements to formalize foreign energy ventures and secure necessary exploitation
rights.
- Ability to successfully integrate and operate acquired or newly formed entities and multiple foreign energy ventures
and subsidiaries.
- Competition from large petroleum companies and other energy interests.
- Changes in laws and regulations that affect our operations and the energy industry in general.
- Risks and uncertainties associated with exploration, development and production of oil and gas, and drilling and
production risks.
- Expropriation and other risks associated with foreign operations.
- Risks associated with anticipated and ongoing third party pipeline construction and transportation of oil and gas.
- The lack of availability of oil and gas field goods and services.
- Environmental risks and changing economic conditions.
The Company’s operations and its securities are subject to a number of risks. The Company has described below all
significant material risks that are known to the Company that could materially impact the Company’s financial results of
operations or financial condition. If any of the following risks actually occur, the financial condition or operating results of
the Company and the trading price or value of its securities could be materially adversely affected.
Risks Related to the Company’s Business
The Company’s limited operating history makes it difficult to predict future results and raises substantial doubt as to its
ability to successfully develop profitable business operations.
The Company’s limited operating history makes it difficult to evaluate its current business and prospects or to accurately
predict its future revenue or results of operations, and raises substantial doubt as to its ability to successfully develop
profitable business operations beyond the Oyo Field interest rights we acquired in April 2010 (the Oyo Contract Rights) and
the Non-Oyo Contract Rights acquired in February 2011. We had no previous operating history in the Africa area prior to
2010. The Company’s revenue and income potential are unproven.
All of the value of our production and reserves is concentrated in a single block offshore Nigeria, and any production
problems or reductions in reserve estimates related to this property would adversely impact our business.
All of the value of our production and reserves is concentrated in a single block offshore Nigeria OML 120. Any production
problems or reduction in reserve estimates related to this property would adversely impact our business.
The Company may continue to incur losses for a significant period of time.
In addition to the Oyo Contract Rights we acquired from CEHL in May 2012 we signed four PSC’s in Kenya and two
exploration licenses with The Gambia. As we are still in the early stages of exploration and have yet to drill on our Kenyan
and Gambian blocks, we expect to continue to incur significant expenses relating to our identification of new ventures and
investment costs relating to these ventures. Additionally, fixed commitments, including salaries and fees for employees and
consultants, rent and other contractual commitments may be substantial and are likely to increase as additional ventures are
entered into and personnel are retained. Energy ventures, such as oil well drilling projects, generally require a significant
period of time before they produce resources and in turn generate profits. The Oyo and Non-Oyo Contract Rights may or
may not result in net earnings in excess of our losses on other ventures under development or in the start-up phase. We may
not achieve or sustain profitability on a quarterly or annual basis, or at all.
The Company’s ability to execute its business strategy and diversify risks by participating in multiple projects and joint
ventures depends upon its ability to raise capital and the availability of suitable prospects, and any failure to raise needed
capital and secure suitable projects would negatively affect the Company’s ability to operate and could result in the
curtailment or cessation of the Company’s operations.
The Company’s business strategy includes spreading the risk of oil and natural gas exploration, development and drilling,
and ownership of interests in oil and natural gas properties, by participating in multiple projects and joint ventures. If the
Company is unable to secure sufficient attractive projects as a result of its inability to raise sufficient capital or otherwise, the
average quality of the projects and joint venture opportunities may decline and the risk of the Company’s overall operations
could increase.
Insufficient funds will prevent the Company from implementing its business plan and will require it to delay, scale back, or
eliminate certain of its programs or to license to third parties rights to commercialize fields that it would otherwise seek to
develop itself.
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.
Failure by the Company to generate sufficient cash flow from operations could eventually result in the cessation of the
Company’s operations and require the Company to seek outside financing or discontinue operations.
The Company’s business activities require substantial capital from outside sources as well as from internally-generated
sources. The Company’s ability to finance a portion of its working capital and capital expenditure requirements with cash
flow from operations will be subject to a number of variables, such as:
- Level of production from existing wells;
- Prices of oil and natural gas;
- Success and timing of development of proved undeveloped reserves;
- Cost overruns;
- Remedial work to improve a well’s producing capability;
- Direct costs and general and administrative expenses of operations;
- Reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells;
- Indemnification obligations of the Company for losses or liabilities incurred in connection with the Company’s
activities; and
- General economic, financial, competitive, legislative, regulatory and other factors beyond the Company’s control.
The Company might not generate or sustain cash flow at sufficient levels to finance its business activities. When and if the
Company generates significant revenues, if such revenues were to decrease due to lower oil prices, decreased production or
other factors, and if the Company were unable to obtain capital through reasonable financing arrangements, such as a credit
line, or otherwise, its ability to execute its business plan would be limited and it could be required to discontinue operations.
The Company’s failure to capitalize on existing definitive production agreements and/or enter into additional agreements
could result in an inability by the Company to generate sufficient revenues and continue operations.
The Company has active interests in definitive production contracts for the Oyo and Non-Oyo Contract Rights. The
Company has entered into definitive exploration agreements with Kenya and The Gambia. The Company’s ability to
consummate one or more additional ventures is subject to, among other things, (i) the amount of capital the Company raises
in the future; (ii) the availability of land for exploration and development in the geographical regions in which the
Company’s business is focused; (iii) the nature and number of competitive offers for the same projects on which the
Company is bidding; and (iv) approval by government and industry officials. The Company may not be successful in
executing definitive agreements in connection with any other ventures, or otherwise be able to secure any additional ventures
it pursues in the future. Failure of the Company to capitalize on its existing contracts and/or to secure one or more additional
business opportunities would have a material adverse effect on the Company’s business and results of operations, and could
result in the cessation of the Company’s business operations.
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant
inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of
our reserves. A significant percentage of our total estimated proved reserves at December 31, 2013 were proved
undeveloped reserves which ultimately may be less than currently estimated.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and
many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any
significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities. In the case of
production sharing contracts, the quantities allocable to a part-interest owner’s share are affected by the assumptions of that
owner’s future participation in funding of operating and capital costs. Actual future production, prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from
estimates. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed. In
addition, estimates of proved reserves reflect production history, results of exploration and development, prevailing prices
and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage,
the estimates of future production associated with such properties may be subject to greater variance to actual production
than would be the case with properties having a longer production history.
The Company’s oil and gas operations will involve many operating risks that can cause substantial losses.
The Company expects to produce, transport and market potentially toxic materials, and purchase, handle and dispose of other
potentially toxic materials in the course of its business. The Company’s operations will produce byproducts, which may be
considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or
as a result of new findings on the effects 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:
- Fires and explosions;
- Blow-outs and oil spills;
- Pipe or cement failures and casing collapses;
- Uncontrollable flows of oil, gas, formation water, or drilling fluids;
- Embedded oilfield drilling and services tools;
- Abnormally pressured formations;
- Natural disaster;
- Vandalism and terrorism; and
- Environmental hazards.
In the event that any of the foregoing events occur, the Company could incur substantial losses as a result of (i) injury or loss
of life; (ii) severe damage or destruction of property, natural resources or equipment; (iii) pollution and other environmental
damage; (iv) investigatory and clean-up responsibilities; (v) regulatory investigation and penalties; (vi) suspension of its
operations; or (vii) repairs to resume operations. If the Company experiences any of these problems, its ability to conduct
operations could be adversely affected. Additionally, offshore operations are subject to a variety of operating risks, such as
capsizing, collisions and damage or loss from typhoons or other adverse weather conditions. These conditions can cause
substantial damage to facilities and interrupt production.
The Company may not be able to manage our anticipated growth.
Subject to our receipt of additional capital, we plan to significantly expand operations to accommodate additional
development projects and other opportunities. This expansion may strain our management, operations, systems and financial
resources. We may need to hire additional personnel in certain operational and other areas during 2014 and future years.
The company will be dependent upon others for the storage and transportation of oil and gas, which could result in
significant operational costs to the company and depletion of capital.
The company does not own storage or transportation facilities and, therefore, will depend upon third parties to store and
transport all of its oil and gas resources when and if produced. The company will likely be subject to price changes and
termination provisions in any contracts it may enter into with these third-party service providers. The company may not be
able to identify such third-parties for any particular project. Even if such sources are initially identified, the company may not
be able to identify alternative storage and transportation providers in the event of contract price increases or termination. In
the event the company is unable to find acceptable third-party service providers, it would be required to contract for its own
storage facilities and employees to transport the company’s resources. The company may not have sufficient capital available
to assume these obligations, and its inability to do so could result in the cessation of its business.
An interruption in the supply of materials, resources and services, including storage and transportation of oil and gas, the
Company plans to obtain from third party sources could limit the Company’s operations and cause unprofitability.
Once it has identified, financed, and acquired projects, the Company will need to obtain other materials, resources and
services, including, but not limited to, specialized chemicals and specialty muds and drilling fluids, pipe, drill-string,
geological and geophysical mapping and interruption services. There may be only a limited number of manufacturers and
suppliers of these materials, resources and services. These manufacturers and suppliers may experience difficulty in
supplying such materials, resources and services to the Company sufficient to meet its needs or may terminate or fail to
renew contracts for supplying these materials, resources or services on terms the Company finds acceptable including,
without limitation, acceptable pricing terms.
The Company does not presently carry liability insurance and business interruption insurance policies in Africa and will
be at risk of incurring personal injury claims for its employees and subcontractors, and incurring business interruption
loss due to theft, accidents or natural disasters.
The Company does not presently carry any policies of insurance in Africa to cover the risks discussed above. In the event
that the Company were to incur substantial liabilities or business interruption losses with respect to one or more incidents,
this could adversely affect its operations and it may not have the necessary capital to pay its portion of such costs and
maintain business operations.
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.
Our majority shareholder, CEHL, is one of the entities constituting our business partner, CEHL. Dr. Kase Lawal, the
Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is a director of each of
CEHL, CINL, and Allied, also entities constituting CEHL Group. Dr. Lawal also owns 27.7% of CAMAC International
Limited, which indirectly owns 100% of CEHL. 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 120 and 121 Transaction, the Promissory Note with Allied 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, CEHL sale or transfer of its interest in the Company or otherwise, we
may lose our status as an indigenous Nigerian oil and gas operator. As a result, we would lose one of our key advantages in
the Nigerian oil and gas market and our results of operations could materially suffer.
Applicable Nigerian income tax rates could adversely affect the value of the OMLs 120 and 121 asset, including the Oyo
Field.
Income derived from the Oyo Contract Rights and the Non-Oyo Contract Rights, and CPL, as acquiring subsidiary in these
transactions, are subject to the jurisdiction of the Nigerian taxing authorities. The Nigerian government applies different
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 120 and 121 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 120 and 121 for a
tax year. While we believe the petroleum profit tax rate applicable to the OMLs 120 and 121 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 120
and 121.
The passage into law of the Nigerian Petroleum Industry Bill could create additional fiscal and regulatory burdens on the
parties to the OMLs 120 and 121, which could have a material adverse effect on the profitability of the production.
A Petroleum Industry Bill (“PIB”) is currently undergoing legislative process at the Nigerian National Assembly. To date,
the PIB has failed to pass the Nigerian Senate. The draft PIB seeks to introduce significant changes to legislation governing
the oil and gas sector in Nigeria, including new fiscal regulatory and tax obligations and expanded fiscal and regulatory
oversight that may impose additional operational and regulatory burdens on the 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 120 and 121.
OMLs 120 and 121 are subject to the instability of the Nigerian Government and instability in the country of Nigeria.
The government of Nigeria originally granted the rights to OMLs 120 and 121 to CEHL. The government and country of
Nigeria have historically experienced instability, which is out of management’s control. The Company’s ability to exploit its
interests in this area pursuant to the OMLs 120 and 121 may be adversely impacted by unanticipated governmental action. In
addition, the financial viability of the OMLs 120 and 121 may also be negatively affected by changing economic, political
and governmental conditions in Nigeria. Moreover, we operate in a sector of the economy that is likely to be adversely
impacted by the effects of political instability, terrorist or other attacks, war or international hostilities.
OMLs 120 and 121 is located in an area where there are high security risks, which could result in harm to the Oyo Field
operations and our interest in the Oyo Field and the remainder of OMLs 120 and 121.
The Oyo Field is located approximately 75 km (46 miles) off the Southern Nigerian coast in deep-water. There are some
risks inherent to oil production in Nigeria. Since December 2005, Nigeria has experienced increased pipeline vandalism,
kidnappings and militant takeovers of oil facilities in the Niger Delta. The Movement for the Emancipation of the Niger
Delta (MEND) is the main group attacking oil infrastructure for political objectives, claiming to seek a redistribution of oil
wealth and greater local control of the sector. Additionally, kidnappings of oil workers for ransom are common. Security
concerns have led some oil services firms to pull out of the country and oil workers unions to threaten strikes over security
issues. The instability in the Niger Delta has caused shut-in production and several companies to declare force majeure on oil
shipments.
Despite undertaking various security measures and being situated 75 km (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.
Maritime disasters and other operational risks may adversely impact our reputation, financial condition and results of
operations.
The operation of the FPSO vessel has an inherent risk of maritime disaster, environmental mishaps, cargo and property losses
or damage and business interruptions caused by, among others:
- Mechanical failure and dry-dock repairs;
- Vessel off hire periods and labor strikes;
- Human error and adverse weather;
- Political action, civil conflict, terrorism and piracy in vessel’s home country;
- Political action, civil conflict, terrorism and piracy in vessel’s operation site; and
- Political action, civil conflict, terrorism and piracy to vessel’s supply lines.
Any of these circumstances could adversely affect the operation of the FPSO vessel, and result in loss of revenues or
increased costs and adversely affect our profitability. Terrorist acts and regional hostilities around the world in recent ye ars
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.
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 under the OMLs 120 and 121 will heavily influence our revenue,
profitability, access to capital and future rate of growth. Oil is a commodity and, therefore, its price is subject to wide
fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil has been volatile.
This market will likely continue to be volatile in the future. The prices received for production under the OMLs 120 and 121
and the levels of its production depend on numerous factors beyond the control of the Oyo field’s operator. These factors
include the following:
- Changes in global supply and demand for oil;
- Organization of petroleum exporting countries’ actions;
- Price and quantity of imports of foreign oil;
- Political and economic conditions;
- Embargoes and adverse weather;
- Effects from the actions of other oil producing countries actions;
- Global oil exploration and productions levels;
- Global oil inventory levels;
- Price and availability of alternative fuels;
- Energy consumption technological advances;
- Domestic and foreign governmental regulations; and
- Proximity and capacity of transportation pipelines and facilities.
Lower oil prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil that the
Company can produce economically with respect to the Oyo Field. A substantial or extended decline in oil prices may
materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance
planned capital expenditures.
Risks Related to the Company’s Industry
The Company may not be successful in finding, acquiring, or developing sufficient petroleum reserves, and if it fails to do
so, the Company will likely cease operations.
The Company will be operating primarily in the petroleum extractive business; therefore, if it is not successful in finding
crude oil and natural gas sources with good prospects for future production, and exploiting such sources, its business will not
be profitable and it may be forced to terminate its operations. Exploring and exploiting oil and gas or other sources of energy
entails significant risks, which risks can only be partially mitigated by technology and experienced personnel. The Company
or any ventures it acquires or participates in may not be successful in finding petroleum or other energy sources; or, if it is
successful in doing so, the Company may not be successful in developing such resources and producing quantities that will
be sufficient to permit the Company to conduct profitable operations. The Company’s future success will depend in large part
on the success of its drilling programs and creating and maintaining an inventory of projects. Creating and maintaining an
inventory of projects depends on many factors, including, among other things, obtaining rights to explore, develop and
produce hydrocarbons in promising areas, drilling success, and ability to bring long lead-time, capital intensive projects to
completion on budget and schedule, and efficient and profitable operation of mature properties. The Company’s inability to
successfully identify and exploit crude oil and natural gas sources would have a material adverse effect on its business and
results of operations and would, in all likelihood, result in the cessation of its business operations.
In addition to the numerous operating risks described in more detail in this report, 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:
- Adverse weather conditions;
- Unexpected drilling conditions;
- Irregularities in formations;
- Pressure irregularities;
- Equipment failures or accidents;
- Inability to comply with governmental requirements;
- Shortages or delays in the availability of drillings rigs;
- Shortages or delays in the availability of delivery equipment; and
- Shortages or unavailability of qualified labor to complete the drilling programs according to the business plan schedule.
The energy market in which the Company operates is highly competitive and the Company may not be able to compete
successfully against its current and future competitors, which could seriously harm the Company’s business.
Competition in the oil and gas industry is intense, particularly with respect to access to drilling rigs and other services, the
acquisition of properties and the hiring and retention of technical personnel. The Company expects competition in the market
to remain intense because of the increasing global demand for energy, and that competition will increase significantly as new
companies enter the market and current competitors continue to seek new sources of energy and leverage existing sources.
Many of the Company’s competitors, including large oil companies, have an established presence in the areas we do business
and have longer operating histories, significantly greater financial, technical, marketing, development, extraction and other
resources and greater name recognition than the Company does. As a result, they may be able to respond more quickly to
new or emerging technologies, changes in regulations affecting the industry, newly discovered resources and exploration
opportunities, as well as to large swings in oil and natural gas prices. In addition, increased competition could result in lower
energy prices, and reduced margins and loss of market share, any of which could harm the Company’s business.
Furthermore, increased competition may harm the Company’s ability to secure ventures on terms favorable to it and may
lead to higher costs and reduced profitability, which may seriously harm its business.
The Company’s business depends on the level of activity in the oil and gas industry, which is significantly affected by
volatile energy prices, which volatility could adversely affect its ability to operate profitably.
The Company’s business depends on the level of activity in the oil and gas exploration, development and production in
markets worldwide. Oil and gas prices, market expectations of potential changes in these prices and a variety of political and
economic and weather-related factors significantly affect this level of activity. Oil and gas prices are extremely volatile and
are affected by numerous factors, including:
- Domestic and foreign supply of oil and natural gas;
- OPEC production levels;
- OPEC pricing levels;
- Price and availability of alternative fuels;
- Weather conditions;
- Level of consumer demand;
- Global economic conditions;
- Political conditions in oil and gas producing regions; and
- Shortages or unavailability of qualified labor to complete the drilling programs according to the business plan schedule.
If the Company does not hedge its exposure to reductions in oil and gas prices, it may be subject to the risk of significant
reductions in prices; alternatively, use by the Company of oil and gas price hedging contracts could limit future revenues
from price increases.
To date, the Company has not entered into any hedging transactions but may do so in the future. In the event that the
Company chooses not to hedge its exposure to reductions in oil and gas prices by purchasing futures and by using other
hedging strategies, it could be subject to significant reduction in prices which could have a material negative impact on its
profitability. Alternatively, the Company may elect to use hedging transactions with respect to a portion of its oil and gas
production to achieve more predictable cash flow and to reduce its exposure to price fluctuations. The use of hedging
transactions could limit future revenues from price increases and could also expose the Company to adverse changes in basis
risk, the relationship between the price of the specific oil or gas being hedged and the price of the commodity underlying the
futures contracts or other instruments used in the hedging transaction. Hedging transactions also involve the risk that the
counterparty does not satisfy its obligations.
The Company may be required to take non-cash asset write-downs if oil and natural gas prices decline or if downward
revisions in net proved reserves occur, which could have a negative impact on the Company’s earnings.
Under applicable accounting rules, the Company may be required to write down the carrying value of oil and natural gas
properties if oil and natural gas prices decline or if there are substantial downward adjustments to its estimated proved
reserves, increases in its estimates of development costs or deterioration in its exploration results. Accounting standards
require the Company to review its long-lived assets for possible impairment whenever changes in circumstances indicate that
the carrying amount of an asset may not be fully recoverable over time. In such cases, if the asset’s estimated undiscounted
future 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.
Risks Related to International Operations
The Company’s international operations will subject it to certain risks inherent in conducting business operations in
Nigeria and other foreign countries, including political instability and foreign government regulation, which could
significantly impact the Company’s ability to operate in such countries and impact the Company’s results of operations.
The Company conducts substantially all of its business in Africa. The Company’s present and future international operations
in foreign countries are, and will be, subject to risks generally associated with conducting businesses in foreign countries,
such as:
- Foreign laws and regulations that may be materially different from those of the United States;
- Changes in applicable laws and regulations;
- Challenges to, or failure of, title;
- Labor and political unrest;
- Foreign currency fluctuations;
- Changes in foreign economic and political conditions;
- Export and import restrictions;
- Tariffs, customs, duties and other trade barriers;
- Difficulties in staffing and managing foreign operations;
- Longer time period and difficulties in collecting accounts receivable and enforcing agreements;
- Possible loss of properties due to nationalization or expropriation; and
- Limitations on repatriation of income or capital.
Specifically, foreign governments may enact and enforce laws and regulations requiring increased ownership by businesses
and/or state agencies in energy producing businesses and the facilities used by these businesses, which could adversely affect
the Company’s ownership interests in then existing ventures. The Company’s ownership structure may not be adequate to
accomplish the Company’s business objectives in Nigeria or in any other foreign jurisdiction where the Company may
operate. Foreign governments also may impose additional taxes and/or royalties on the Company’s business, which would
adversely affect the Company’s profitability and value of our foreign assets, including the rights to interests in OMLs 120
and 121. In certain locations, governments have imposed restrictions, controls and taxes, and in others, political conditions
have existed that may threaten the safety of employees and the Company’s continued presence in those countries. Internal
unrest, acts of violence or strained relations between a foreign government and the Company or other governments may
adversely affect its operations. These developments may, at times, significantly affect the Company’s results of operations,
and must be carefully considered by its management when evaluating the level of current and future activity in such
countries.
The future success of the Company’s operations may also be adversely affected by risks associated with international
activities, including economic and labor conditions, political instability, risk of war, expropriation, repatriation, termination,
renegotiation or modification of existing contracts, tax laws (including host-country import-export, excise and income taxes
and United States taxes on foreign subsidiaries) and changes in the value of the U.S. dollar versus the local currencies in
which future oil and gas producing activities may be denominated in certain cases. Changes in exchange rates may also
adversely affect the Company’s future results of operations and financial condition. Realization of any of these factors could
materially and adversely affect our financial position, results of operations and cash flows.
Compliance and enforcement of environmental laws and regulations, including those related to climate change, may
cause the Company to incur significant expenditures and require resources, which it may not have.
Extensive national, regional and local environmental laws and regulations in Africa are expected to have a significant impact
on the Company’s operations. These laws and regulations set various standards regulating certain aspects of health and
environmental quality, which provide for user fees, penalties and other liabilities for the violation of these standards. As new
environmental laws and regulations are enacted and existing laws are repealed, interpretation, application and enforcement of
the laws may become inconsistent. Compliance with applicable local laws in the future could require significant
expenditures, which may adversely affect the Company’s operations. The enactment of any such laws, rules or regulations in
the future may have a negative impact on the Company’s projected growth, which could in turn decrease its projected
revenues or increase its cost of doing business.
A foreign government could change its policies towards private enterprise or even nationalize or expropriate private
enterprises, which could result in the total loss of the Company’s investment in that country.
The Company’s business is subject to significant political and economic uncertainties and may be adversely affected by
political, economic and social developments in Africa or in any other foreign jurisdiction in which it operates.
Changes in policies, laws and regulations or in their interpretation or the imposition of confiscatory taxation, restrictions on
currency conversion, restrictions or prohibitions on dividend payments to stockholders, devaluations of currency or the
nationalization or other expropriation of private enterprises could have a material adverse effect on the Company’s business.
Nationalization or expropriation could even result in the loss of all or substantially all of the Company’s assets and in the
total loss of your investment in the Company.
The continued existence of official corruption and bribery in Africa, and the inability or unwillingness of Nigerian
authorities to combat such corruption, may negatively impact our ability to fairly and effectively compete in the Nigerian
oil and gas market.
Official corruption and bribery remain a serious concern in Nigeria. The 2013 Transparency International report ranked
Nigeria 144 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 the government to bring corrupt bank officials to justice. Several notable cases have
been brought, but, to date, few significant cases have been successful and bank regulatory oversight remains a concern. Thus,
increased diligence may be required in working with or through Nigerian banks or with Nigerian governmental authorities,
and interactions with government officials may need to be monitored. To the extent that such efforts to increase transparency
are unsuccessful, and any competitors utilize the existence of corruptive practices in order to secure an unfair advantage, our
financial condition and results of operations may suffer.
If relations between the United States and Nigeria were to deteriorate, investors might be unwilling to hold or buy the
Company’s stock and its stock price may decrease.
At various times during recent years, the United States has had significant disagreements over political, economic and
security issues with Nigeria. Additional controversies may arise in the future between the United States and Nigeria. Any
political or trade controversies between the United States and Nigeria, whether or not directly related to the Company’s
business, could adversely affect the market price of the Company’s Common Stock.
The Company’s stockholders may not be able to enforce United States civil liabilities claims.
Many of the Company’s assets are, and are expected to continue to be, located outside the U.S. and held through one or more
wholly-owned and majority-owned subsidiaries incorporated under the laws of foreign jurisdictions. A substantial part of the
Company’s operations are, and are expected to continue to be, conducted in Africa. In addition, some of the Company’s
directors and officers, including directors and officers of its subsidiaries, may be residents of countries other than the U.S. All
or a substantial portion of the assets of these persons may be located outside the U.S. As a result, it may be difficult for
shareholders to effect service of process within the U.S. upon these persons. In addition, there is uncertainty as to whether the
foreign courts would recognize or enforce judgments of U.S. courts obtained against the Company or such persons predicated
upon the civil liability provisions of the securities laws of the U.S. or any state thereof, or be competent to hear original
actions brought in these countries against the Company or such persons predicated upon the securities laws of the U.S. or any
state thereof.
Risks Related to the Company’s Stock
CAMAC Energy Holdings Limited is our majority stockholder, and it may take actions that conflict with the interests of
the other stockholders.
Following our acquisition of the Oyo Contract Rights, CEHL beneficially owned approximately 62.74% of our outstanding
shares of Common Stock and continues to own a majority interest at present. CEHL controls the power to elect our directors,
to appoint members of management and to approve all actions requiring the approval of the holders of our Common Stock,
including adopting amendments to our Certificate of Incorporation and approving mergers, acquisitions or sales of all or
substantially all of our assets, subject to certain restrictive covenants. The interests of CEHL as our controlling stockholder
could conflict with your interests as a holder of Company Common Stock. For example, CEHL as our controlling
stockholder may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment,
could enhance its equity investment, even though such transactions might involve risks to you, as minority holders of the
Company.
The market price of the Company’s stock may be adversely affected by a number of factors related to the Company’s
performance, the performance of other energy-related companies and the stock market in general.
The market prices of securities of energy companies are extremely volatile and sometimes reach unsustainable levels that
bear no relationship to the past or present operating performance of such companies.
Factors that may contribute to the volatility of the trading price of the Company’s Common Stock include, among others:
- Financial predictions and recommendations by stock analysts concerning energy companies and companies competing
in the Company’s market in general, and concerning the Company in particular;
- Variance between the Company’s actual quarterly results of operations and predictions by stock analysts;
- Public announcements of regulatory changes or new ventures relating to the Company’s business, new products or
services by the Company or its competitors, or acquisitions, joint ventures or strategic alliances by the Company or its
competitors;
- Investor perception of the Company’s business prospects or the oil and gas industry in general;
- Public reports concerning the Company’s services or those of its competitors;
- The operating and stock price performance of other companies that investors or stock analysts may deem comparable to
the Company;
- Large purchases or sales of the Company’s Common Stock;
- The Company’s quarterly results of operations; and
- General economic and financial conditions.
In addition to the foregoing factors, the trading prices for equity securities in the stock market in general, and of energy-
related companies in particular, have been subject to wide fluctuations that may be unrelated to the operating performance of
the particular company affected by such fluctuations. Consequently, broad market fluctuations may have an adverse effect on
the trading price of the Common Stock, regardless of the Company’s results of operations.
The limited market for the Company’s Common Stock may adversely affect trading prices or the ability of a shareholder
to sell the Company’s shares in the public market at or near ask prices or at all if a shareholder needs to liquidate its
shares.
The market price for shares of the Company’s Common Stock has been, and is expected to continue to be, very
volatile. Numerous factors beyond the Company’s control may have a significant effect on the market price for shares of the
Company’s Common Stock, including the fact that the Company is a small company that is relatively unknown to stock
analysts, stock brokers, institutional investors and others in the investment community that generate or influence sales
volumes. Even if we came to the attention of such persons, they tend to be risk-averse and may be reluctant to follow an
unproven, early stage company such as the Company or purchase or recommend the purchase of its shares until such time as
the Company becomes more seasoned and viable. There may be periods of several days or more when trading activity in the
Company’s shares is minimal as compared to a seasoned issuer which has a large and steady volume of trading activity that
will generally support continuous sales without an adverse effect on share price. Due to these conditions, investors may not
be able to sell their shares at or near ask prices or at all if investors need money or otherwise desire to liquidate their shares.
In addition to the listing of our Common Stock on the NYSE MKT, we recently listed our Common Stock on the
Johannesburg Stock Exchange (“JSE”), but we cannot assure you that a trading market will successfully develop on the
JSE.
We cannot assure you that an active trading market for our Common Stock will develop on the JSE. In addition, we cannot
assure you what effect our listing on the JSE will have on our trading market on the NYSE MKT. In February 2014, we
issued 188,442,211 shares of our Common Stock to the Public Investment Corporation (SOC) Limited (“PIC”) of South
Africa in a private placement and expect to issue another 188,442,211 shares to PIC in the near future. If those shares become
eligible to be sold on the JSE and 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 entered into registration rights agreements with stockholders covering an estimated 1,044,380,323 shares
of our Common Stock using a price of $0.70 per share, which was the closing price of our Common Stock on March 5, 2014.
The possibility that substantial amounts of our Common Stock may 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. We may need to issue a greater number of shares of Common Stock other than the estimated
1,044,380,323 shares because we have received approval to list an indeterminate number of shares of Common Stock to meet
our obligations to pay up to $50.0 million in oil and gas milestone payments under the Transfer Agreement. All of the shares
payable as milestone payments would be eligible for registration under a registration rights agreement.
The Company’s issuance of Preferred Stock could adversely affect the value of the Company’s Common Stock.
The Company’s Amended and Restated Certificate of Incorporation authorizes the issuance of up to 50 million shares of
Preferred Stock, which shares constitute what is commonly referred to as “blank check” Preferred Stock. This Preferred
Stock may be issued by the Board of Directors from time to time on any number of occasions, without stockholder approval,
as one or more separate series of shares comprised of any number of the authorized but unissued shares of Preferred Stock,
designated by resolution of the Board of Directors, stating the name and number of shares of each series and setting forth
separately for such series the relative rights, privileges and preferences thereof, including, if any, the: (i) rate of dividends
payable thereon; (ii) price, terms and conditions of redemption; (iii) voluntary and involuntary liquidation preferences; (iv)
provisions of a sinking fund for redemption or repurchase; (v) terms of conversion to Common Stock, including conversion
price; and (vi) voting rights. The designation of such shares could be dilutive of the interest of the holders of our Common
Stock. The ability to issue such Preferred Stock could also give the Company’s Board of Directors the ability to hinder or
discourage any attempt to gain control of the Company by a merger, tender offer at a control premium price, proxy contest or
otherwise.
The 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 they were to act together,
would be able to control all matters requiring approval by stockholders, including the election of Directors and the approval
of significant corporate transactions. This concentration of ownership may also have the effect of delaying, deterring or
preventing a change in control and may make some transactions more difficult or impossible to complete without the support
of these stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
The Company has four leased office facilities: Houston, Texas (the “Houston Facility”), Nairobi, Kenya (the “Kenya
Facility”), Banjul, The Gambia (“Gambia Facility”) and Lagos, Nigeria (“Lagos Facility”).
The Houston Facility covers approximately 11,500 square feet of office space and is under a lease which commenced on
October 1, 2013 and ends on October 31, 2019. Rental expense is approximately $39,000 per month plus an allocated share
of operating expenses.
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. Rental expense is approximately $6,000 per month plus service charges.
The Gambia Facility covers approximately 2,700 square feet of office space and is under lease which commenced on
February 14, 2013 and ended February 13, 2014 and continues month to month thereafter. Rental expense is approximately
$1,000 per month.
The Nigeria Facility covers approximately 5,900 square feet of office space and is under short-term arrangements with a
related party. Rental expense is approximately $16,000 a month.
The Company does not foresee significant difficulty in renewing or replacing these leases under current market conditions, or
in adding additional space when required.
ITEM 3. LEGAL PROCEEDINGS
From time to time we may be involved in various legal proceedings and claims in the ordinary course of our business. As of
December 31, 2013, and through the filing date of this report, we do not believe the ultimate resolution of such actions or
potential actions of which we are currently aware will have a material effect on our consolidated financial position or our
results of operations.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information for Common Stock
Our Common Stock is currently listed on the NYSE MKT under the symbol “CAK”. It commenced listing on the NYSE
MKT on November 5, 2009 under the symbol “PAP”. Prior to being listed on the NYSE MKT, the Common Stock was
quoted on the OTC Bulletin Board under the symbol “PFAP.OB” between May 8, 2008 and November 4, 2009.
The following table sets forth the range of the high and low sales prices per share of our Common Stock for the periods
indicated:
Period High Low
2013
First quarter $ 0.31 $ 0.22
Second quarter $ 0.29 $ 0.20
Third quarter $ 0.39 $ 0.23
Fourth quarter $ 0.64 $ 0.31
2012
First quarter $ 0.43 $ 0.32
Second quarter $ 0.43 $ 0.23
Third quarter $ 0.27 $ 0.18
Fourth quarter $ 0.33 $ 0.16
The above high and low sales prices per share of our Common Stock reflect the effect of Company's February 21, 2014 Stock
Dividend payment.
In addition to our listing on the NYSE MKT, in February 2014, our Common Stock also became listed on the Johannesburg
Stock Exchange (“JSE”).
Common Stock Warrants and Options
As of March 5, 2014, the Company had warrants outstanding to purchase (i) an aggregate of 11,345,747 shares of Common
Stock at a price per share of $1.08; (ii) an aggregate of 680,979 shares of Common Stock at a price per share of $1.13; (iii) an
aggregate of 365,141 shares of Common Stock at a price per share of $2.05; and (iv) an aggregate of 302,839 shares of
Common Stock at a price per share of $2.17.
As of March 5, 2014, an aggregate of 13,775,531 shares of Common Stock were issuable upon exercise of outstanding stock
options.
The above outstanding Common Stock Warrants and Options reflect the effect of the Stock Dividend on all shares of the
Company's Common Stock that was paid by the Company on February 21, 2014, and pursuant to which all stockholders of
record as of close of business on February 13, 2014, received 1.4348 additional shares of Common Stock for every one share
of Common Stock held.
Holders
As of March 5, 2013, there were 57 registered holders of record of our Common Stock, and there are an estimated 6,000
beneficial owners of our Common Stock, including shares held in street name.
Dividend Policy
The Company has not paid any cash dividends on its Common Stock as of December 31, 2013. Any future determination as
to the payment of dividends on the Common Stock will depend upon the results of operations, capital requirements, the
financial condition of the Company and other relevant factors.
Our Board of Directors has complete discretion on whether to pay dividends. Even if our Board of Directors decides to pay
dividends, the form, frequency and amount will depend upon our future operations and earnings, capital requirements and
surplus, general financial condition, contractual restrictions and other factors that the Board of Directors may deem relevant.
On January 24, 2014 the Company’s Board of Directors declared the Stock Dividend. Payment of the Stock Dividend was
conditioned on (i) approval of the Company’s stockholders at the special meeting of stockholders to be held on February 13,
2014 of certain proposals related to the Allied Transaction, including a proposal to amend the Company’s certificate of
incorporation to increase the number of authorized shares of Common Stock and (ii) approval of the listing of the Company’s
Common Stock on the JSE. On February 13, 2014, the Company held a special meeting of its stockholders to consider and
vote upon the proposals mentioned above and other related agenda items. All of the proposals presented at the meeting
received the requisite stockholders approval and the approval of the JSE listing was successfully obtained. On February 21,
2014, the Company paid the Stock Dividend pursuant to which each share of Common Stock of record as of the close of
the business on February 13, 2014, carried the right to receive 1.4348 shares of Common Stock for every one share of
Common Stock held.
Per Accounting Standard Codification (“ASC”) 505, Equity, the above Stock Dividend is to be accounted for as a Stock Split
due to its large nature (exceeds 25% of the total shares outstanding prior to the distribution). The effect is a retroactive
adjustment to the financial statements as if the dividend had occurred in the first period presented.
Securities Authorized for Issuance under Equity Compensation Plans
Upon adoption of the 2009 Equity Incentive Plan (“2009 Plan”) by the Board of Directors in June 2009, the Company’s
Board of Directors resolved to (i) discontinue further grants and awards of equity securities under the 2007 Plan, except the
issuance of Company 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 2,628,000 from 4,000,000, 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.
Subject to stockholder approval and the completion of the Allied Transaction, the Private Placement and the Stock Dividend,
the Board of Directors approved an amendment to the 2009 Plan to increase the number of shares that may be granted during
the life of the 2009 Plan from 12,000,000 to 100,000,000 shares. On February 13, 2014, the stockholders approved the
amendment to the 2009 Plan at a special meeting of the stockholders. On February 18, 2014, the Company executed the
amendment to the 2009 Plan thereby increasing the number of shares that may be granted thereunder to 100,000,000.
The following table sets forth information with respect to the equity compensation plans available to directors, officers, and
employees of the Company at December 31, 2013:
Number of
Securities
Available For
Future
Number of Issuance
Securities to Weighted- Under 2009
be Issued Average Equity
Upon Exercise Price Compensation
Exercise of of Plan
Outstanding Outstanding (Excluding
Options, Options, Securities
Warrants and Warrants and Reflected in
Rights Rights Column (a))
Plan Category (a) (b) (c)
Equity compensation plans approved by security holders 13,775,531(1) $ 0.31 2,255,654
1,347,615(2) $ 1.61
15,123,146 $ 2,255,654
(1) Includes the 2007 and 2009 Equity Incentive Plans.
(2) Remaining placement warrants exercisable for shares of Common Stock, originally issued in 2007 and 2010 to placement
agents, for which issuance was approved by stockholders of the Company.
The above outstanding Common Stock Warrants and Options reflect the effect of the Company's payment of the Stock
Dividend.
Recent Sales of Unregistered Securities
None during the year ended December 31, 2013.
Stock Repurchases
The Company did not repurchase any shares of its Common Stock during the year ended December 31, 2013.
Performance Graph
The following information compares the Company’s cumulative, total stockholder return with a general market index (the
“S&P 500”) and the Energy Select Sector SPDR. 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, 2008 and assumes the reinvestment of all dividends,
if any.
INDEXED RETURNS
Years Ending
Company / Index 12/31/08 12/31/09 12/31/10 12/31/11 12/31/12 12/31/13
Camac Energy Inc. $ 100 $ 778 $ 332 $ 168 $ 98 $ 247
S&P 500 Index 100 120 135 135 153 199
Energy Select Sector
SPDR 100 114 136 138 142 176
This Performance Graph shall not be deemed to be incorporated by reference into our SEC filing 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.
ITEM 6. SELECTED FINANCIAL DATA
Years Ended December 31,
2013 2012 2011 2010 2009
Statement of Income Data (In thousands, except per share data)
Total revenues $ 7,873 $ 16,624 $ 37,922 $ 20,229 $ 67
Net loss attributable to CAMAC Energy
Inc. $ (15,948) $ (6,091) $ (24,913) $ (230,468) $ (11,489)
Net loss per common share attributable to
CAMAC Energy Inc.
Basic $ (0.04) $ (0.02) $ (0.07) $ (0.80) $ (0.11)
Diluted $ (0.04) $ (0.02) $ (0.07) $ (0.80) $ (0.11)
Cash Flow Data
Cash (Used in) provided by operating
activities $ (7,391) $ (5,897) $ (14,654) $ 8,572 $ (6,872)
As of December 31,
2013 2012 2011 2010 2009
Balance Sheet Data (In thousands)
Working capital $ (18,049) $ (6,960) $ (5,380) $ 1,650 $ 3,910
Property plant and equipment, net $ 185,160 $ 189,086 $ 196,222 $ 204,979 $ 451
Total assets $ 187,343 $ 200,055 $ 230,870 $ 247,843 $ 7,436
Note payable - Related party $ 6,496 $ 872 $ 6,000 $ - $ -
The above presented earnings per share amounts reflect the effect of the Company's payment of the Stock Dividend.
For more information on results of operations and financial condition, see Item 7. – Management’s Discussion and Analysis
of Financial Condition and Results of Operations.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW
The Company operates as an independent oil and gas exploration and production company focused on energy resources in
Africa.
The Company’s asset portfolio consists of eight licenses in three countries covering an area of approximately 41,000 square
kilometers (approximately 10 million acres). The Company owns producing properties and conducts exploration activities as
a non-operator in Nigeria, conducts explorations activities as an operator onshore and offshore Kenya, and conducts
exploration activities as an operator in The Gambia.
In August 2012, the Company divested its wholly owned Hong Kong subsidiary Pacific Asia Petroleum Limited for net cash
consideration of $2.4 million and 9.6 million fully paid ordinary shares, net of selling expenses, of Leyshon Resources
Limited, a natural resources mining company based in Beijing, China. The Leyshon shares had a fair market value of $1.9
million, and have since been sold. As a result of the transaction, the Company is reporting its China operations, including
other inactive operations not involved in this sale, for all presented periods in discontinued operations.
In September 2013, drilling operations commenced on the Oyo-7 well in OML 120. In October 2013, the preliminary results
from the Oyo-7 well were announced. Based on logging while drilling (“LWD”) data, the well encountered gross oil pay of
133 feet (net oil pay of 115 feet) and gross gas pay of 103 feet (net gas pay of 93 feet) in the gas cap from the currently
producing Pliocene reservoir, with excellent reservoir quality. The top of the reservoir was penetrated at 5,564 feet. Shortl y
after in November 2013, the Company announced that the Oyo-7 well had 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 of the
Oyo Field. Hydrocarbons were encountered in three intervals totaling approximately 65 feet, as interpreted from the LWD
data. Currently, the Oyo-7 well has been temporarily plugged and suspended but is expected to be re-entered and completed
in the Pliocene reservoir as an oil producer mid-2014.
In November 2013, the Company entered into a Transfer Agreement pursuant to which the Company agreed to acquire the
Allied Assets from Allied in connection with the Allied Transaction. The Allied Transaction closed February 21, 2014.
Please see Note 15 – Subsequent Events of the Notes To Consolidated Financial Statements for additional information on the
Allied Transaction.
During 2013, the Company completed shooting airborne gravity and magnetic geophysical surveys on its Kenya onshore
Lamu Basin blocks L1B and L16. The data acquisition covers essentially the entire 12,129 square kilometers in block L1B
and the entire 3,613 square kilometers in block L16 and satisfies the gravity and magnetic survey requirements for each block
under the relevant PSC. The Company is currently in negotiations with a leading geophysical services company to acquire a
new 2-D seismic survey on both onshore blocks.
RESULTS OF OPERATIONS – CONTINUING OPERATIONS
Oil Revenues
Revenue is recognized when a lifting (sale) occurs. Crude oil revenues for 2013 were $7.9 million, as compared to revenues
of $16.6 million and $37.9 million for 2012 and 2011, respectively. In 2013, the Company sold approximately 73,000 net
barrels of oil at an average price of $107.85/Bbl. In 2012, the Company sold approximately 148,000 net barrels of oil at an
average price of $112.60/Bbl. In 2011, the Company sold approximately 337,000 net barrels of oil at an average price of
$112.91/Bbl. The decrease in revenues year over year is primarily due to the natural decline in production, leading to lower
sales volumes.
During 2013, 2012 and 2011, the average gross daily production from the Oyo Field was 2,233 BOPD, 2,759 BOPD and
3,714 BOPD, respectively. The average net daily production was 276 BOPD, 401 BOPD and 923 BOPD for the years 2013,
2012 and 2011, respectively.
From the gross proceeds of each crude oil liftings, the Company’s net revenue entitlements are computed after a deduction of
the Company’s share of royalty (Royalty Oil) and a provision for recovery of the Company’s share of prior operating and
capital costs (Cost Oil), added to the Company’s share of Profit Oil.
Operating Costs and Expenses
Production costs were a negative $0.7 million for 2013, as compared to expenses of $0.3 million in 2012 and $30.9 million in
2011, respectively. In 2013, the Company spent $0.6 million in production related expenditures, partially offset by a cost
reduction of $1.3 million recorded for billings to Allied under the Technical Services Agreement. In 2012, the Company
spent $0.3 million in production related expenditures. In 2011, the Company spent $30.8 million for the Oyo 5 workover
costs and $0.1 million in other production related expenditures.
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 in Kenya, $0.6 million in Gambia, and $0.3 million in 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 in Kenya, $0.5 million in Gambia, and $0.3 million in Nigeria. In 2011, the Company incurred $0.9 million for
exploration activities, including $0.7 million at the corporate level for exploration activities and $0.2 million in Nigeria.
Depreciation, depletion and amortization (“DD&A”) expenses for 2013 were $4.5 million, as compared to $10.8 million and
$13.5 million for 2012 and 2011, respectively. The 2013 DD&A expenses decreased as compared to 2012 primarily due to
both lower sales volumes and lower depletion rates. The 2012 DD&A expenses decreased as compared to 2011 primarily due
to lower sales volumes, partially offset by increased depletion rates. The average depletion rates for 2013 were $58.23/Bbl, as
compared to $71.72/Bbl and $38.60/Bbl for 2012 and 2011, respectively.
General and administrative expenses for 2013 were $14.5 million, as compared to $11.0 million and $13.3 million for 2012
and 2011, respectively. The increase in general and administrative expenses for 2013 as compared to 2012 was primarily due
to higher consulting and legal costs associated with the Allied Transaction. The decrease in general and administrative
expenses for 2012 as compared to 2011 was primarily due to lower administrative expenses associated with staffing
reductions. The Company incurred non-cash based stock compensation expenses of $2.0 million, $0.7 million, and $2.5
million for the years 2013, 2012, and 2011, respectively.
Other Income (Expense)
Other income was $38.0 thousand in 2013, as compared to other expense of $0.6 million and $0.3 million in 2012 and 2011,
respectively. In 2013, the Company recognized realized foreign currency gains of $0.3 million, partially offset by $0.2
million in interest expense and other taxes associated with the Promissory Note. In 2012, the Company recognized realized
losses of $0.5 million on sale of securities and incurred $0.1 million in interest expenses associated with the Promissory
Note. In 2011, the Company incurred $0.1 million in interest expense and $0.2 million in other adjustments.
Income Taxes
Income taxes were nil for each of the years 2013, 2012, and 2011. The Company was exempt from petroleum profit taxes in
the years 2013, 2012, and 2011 because it benefitted from a tax exemption in Nigeria.
Losses From Continuing Operations
Losses from continuing operations was $15.9 million in 2013, as compared to losses of $9.3 million and $21.0 million for
2012 and 2011, respectively. In 2013, losses from continuing operations increased by $6.6 million as compared to 2012
primarily as the result of lower sales volumes. In 2012, losses from continuing operations decreased by $11.7 million as
compared to 2011 primarily as the result of both lower sales volumes and higher production expenses caused by the Oyo -5
well workover in 2011.
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 Headline Earnings Per Share (“HEPS”) which, per the SEC, is considered a non-
GAAP measurement.
As defined in the Circular 3/2009 of The South African Institute of Chartered Accountants, headline earnings is an additional
earnings number that excludes separately identifiable remeasurements, net of related tax, and related non-controlling interest.
The number of shares used to calculate basic and diluted HEPS is the same as basic and diluted EPS. In the years ended
December 31, 2013, 2012, and 2011, there were no seperate indentifable remeasurements based on the criteria outlined in
circular 3/2009 and headline earnings was the same as net loss per share from continuing operations as disclosed on the
audited consolidated statements of operations. Therefore, HEPS for the years ended 2013, 2012 and 2011 were $(0.04),
$(0.02) and $(0.06), respectively.
RESULTS OF OPERATIONS –DISCONTINUED OPERATIONS
Discontinued operations includes the results of operations of the Company’s China business, which was divested in 2012. In
2012, the Company recognized a gain of $4.2 million, net of selling expenses, associated with the sale. For details of the sale
and results of operations, see Note 3 – Discontinued Operations within the Notes To Consolidated Financial Statements of
this Form 10-K.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
As of December 31, 2013, the Company had a net working capital (current assets minus current liabilities) deficit of $18.0
million including cash and cash equivalents of $0.2 million.
Years Ended December 31,
2013 2012 2011
(In thousands)
Net cash used in operating activities $ (7,391) $ (5,897) $ (14,654)
Net cash (used in) provided by investing (602) 1,219 (6,860)
activities
Net cash provided by (used in) financing
activities 4,350 (5,125) 6,177
Effect of exchange rate changes on cash - (17) 45
Net decrease in cash and cash equivalents (3,643) (9,820) (15,292)
Net cash used in operating activities was $7.4 million, $5.9 million, and $14.7 million for the years 2013, 2012, and 2011,
respectively. Cash used in operating activities increased by $1.5 million in 2013 as compared to 2012 primarily due to both a
$9.9 million increase in net loss and a $1.0 million decrease in non-cash adjustments to net income, partially offset by a $9.4
million positive variance in changes in operating assets and liabilities. Cash used in operating activities decreased by $8.7
million in 2012 as compared to 2011 primarily due to both an $18.9 million decrease in net loss and a $0.6 million positive
variance in operating assets and liabilities, partially offset by a $10.8 million decrease in non-cash adjustments to net income.
Net cash used in investing activities for 2013 was $0.6 million, compared to net cash provided by investing activities of $1.2
million in 2012 and net cash used in investing activities of $6.9 million in 2011. Net cash used in investing activities of $ 0.6
million in 2013 consisted primarily of office infrastructure expenditures. In 2012, net cash provided by investing activities
consisted primarily of the $2.4 million net cash proceeds from the China divestiture and the $2.4 million proceeds from the
sale of the long-term investments, partially offset by $3.6 million paid for capital expenditures. In 2011, net cash used in
investing activities was primarily for $7.2 million capital expenditures, partially offset by $0.3 million sale of available for
sale securities.
Net cash provided by financing activities for 2013 was $4.3 million as compared to net cash used in financing activities of
$5.1 million in 2012 and net cash provided by financing activities of $6.2 million in 2011. The changes in net cash flows
from financing activities for the years shown was primarily due to borrowings and repayments of the Promissory Note (as
defined below). See below for details of the Promissory Note with Allied.
In June 2011, CPL, a wholly owned subsidiary of the Company, executed a promissory note in favor of Allied (the
“Promissory Note”). Under the initial terms of the Promissory Note, Allied agreed to make loans to CPL from time to time
for purposes of making payments relating to the workover of the Oyo well #5 in an aggregate sum of up to $25.0 million.
Interest accrues on the outstanding principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum. In
September 2013, the Company and Allied amended the Promissory Note and the Guaranty to add the Company as a
borrower, to allow for borrowings of up to $10.0 million for general corporate purposes and to pledge the stock of the
subsidiary of CEI that holds the exploration licenses in The Gambia and Kenya as collateral pursuant to an equitable share
mortgage arrangement. As of December 31, 2013, the book value of the exploration licenses in The Gambia and Kenya was
$3.2 million. Pursuant to the initial terms of the Promissory Note, the outstanding principal amount of all loans was to mature
on June 6, 2013. In August 2012, the Promissory Note was amended to extend the maturity date to October 15, 2013, and in
March 2013 the Promissory Note was again amended to extend the maturity date to July 15, 2014. In January 2014, Allied
agreed to amend the Promissory Note and extend the maturity date to July 15, 2015 in the event the Company is not
successful in obtaining external financing arrangements by June 30, 2014. The Company has guaranteed all of CPL’s
obligations under the Promissory Note. As of December 31, 2013, $6.5 million was outstanding under the Promissory Note.
On February 21, 2014, the Company completed the Allied Transaction and the First Closing of the Private Placement in
accordance with the terms of the Transfer Agreement and the Share Purchase Agreement, respectively. Pursuant to the terms
of the Transfer Agreement, the Company, as partial consideration for the Allied Assets, paid $85.0 million in cash to Allied,
issued 497,454,857 shares of the Company’s Common Stock to Allied and delivered the Convertible Subordinated Note to
Allied under which $25.0 million was deemed to be advanced. Within two business days following the Second Closing of the
Private Placement, the Company will be required to pay to Allied an additional $85.0 million in cash, as may be adjusted
pursuant to the Transfer Agreement, and an additional $25.0 million will be deemed to be advanced to Allied under the
Convertible Subordinated Note. The Second Closing of the Private Placement is expected to take place in mid 2014.
Although there are no assurances that the Company’s plans will be realized, based upon the above announcement and current
cash flow projections, management believes that the Company will have sufficient capital resources to meet projected cash
flow requirements for the next twelve months from the date of filing this report.
Capital Expenditures
In 2013, the Company invested $0.6 million in property and equipment additions primarily for office infrastructure support
costs. In 2012, the company invested $3.6 million in property and equipment additions, primarily associated with leasehold
acquisition costs of $2.0 and $1.2 million in Gambia and Kenya, respectively, and $0.4 million in office infrastructure
support costs. In 2011, the Company invested $5.0 million in property and equipment additions primarily for acquisition of
an economic interest in the Oil Mining Lease 121 offshore Nigeria.
Oil and Gas Exploration Costs
As described above, the Company uses the successful efforts method of accounting for its oil and gas exploration and
development costs. All expenditures related to exploration, with the exception of costs of drilling exploration wells, are
charged as an expense when incurred. The costs of exploration wells are capitalized pending determination of whether
commercially producible oil and gas reserves have been discovered. If the determination is made that a well did not
encounter potentially economic oil and gas quantities, the well costs are charged as an expense. 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 in Kenya, $0.6 million in Gambia, and $0.3 million in Nigeria. In 2012, the Company incurred $3.2 million of
exploration expenses, including $1.6 million spent at the corporate level for exploration activities, $1.0 million in Kenya,
$0.5 million in Gambia, and $0.3 million in Nigeria. In 2011, the Company incurred $0.9 million for exploration activities,
including $0.7 million at the corporate level for exploration activities and $0.2 million in Nigeria.
Contractual Obligations
The following table summarizes the Company’s significant estimated future contractual obligations at December 31, 2013:
Payments Due By Period
Total 2014 2015-2016 2017-2018 Thereafter
(In thousands)
Minimum obligations - Kenya $ 34,432 $ 10,800 $ 23,632 $ - $ -
Minimum obligations - The Gambia 114,000 4,000 110,000 - -
Operating lease obligations 2,149 360 750 784 255
Total $ 150,581 $ 15,160 $ 134,382 $ 784 $ 255
The minimum obligations for both Kenya and The Gambia require annual rental payments, training and community fees, all
of which have been included in the above table.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements, other than normal operating leases and employee contracts, that have or are
likely to have a current or future material effect on our financial condition, changes in financial condition, revenues,
expenses, results of operations, liquidity, capital expenditures or capital resources.
CRITICAL ACCOUNTING POLICIES
The following describes the critical accounting policies used by the Company in its financial condition and results of
operations. In some cases, accounting standards allow more than one alternative accounting method for reporting; such is the
case with accounting for oil and gas activities described below. In those cases, the Company’s results of operations would be
different should it implement an alternative accounting method.
Successful Efforts Method of Accounting for Oil and Gas Activities
The Company follows the successful efforts method of accounting of its costs of acquisition, exploration and development of
oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with
exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or
not successful, are capitalized when incurred. Drilling costs of exploratory wells are capitalized pending determination that
proved reserves have been found. If the determination is dependent upon the results of planned additional wells and require
additional capital expenditures to develop the reserves, the drilling costs will be capitalized as long as sufficient reserves
have been found to justify completion of the exploratory well as a producing well, and additional wells are underway or
firmly planned to complete the evaluation of the well. Exploratory wells not meeting the criteria for continued capitalization
are expensed when such a determination is made. Other exploration costs are expensed as incurred.
Depreciation, depletion and amortization for productive oil and gas properties are recorded on a unit-of-production basis. For
other depreciable property, depreciation is recorded on a straight line basis over the estimated useful life of the assets which
ranges between three to five years or the lease term. Repairs and maintenance costs are charged to expense as incurred.
Impairment of Long-Lived Assets
The Company reviews its long-lived assets in property, plant and equipment for impairment in accordance with ASC Topic
360, (Property, Plant and Equipment). Review for impairment of long-lived assets occurs whenever changes in
circumstances indicate that the carrying amount of assets may not be fully recoverable. Possible indicators of impairment
include current period losses combined with a history of losses, significant downward oil and gas reserve revisions, or when
changes in other circumstances indicate the carrying amount of an asset may not be recoverable. An impairment loss is
recognized for assets to be held and used when the estimated undiscounted future cash flows expected to result from the
asset, including ultimate disposition, are less than its carrying amount. In the case of oil and gas properties, the Company
estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash
flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future
economic conditions during the remaining useful life of the asset. The Company’s cash flow projections into the future
include assumptions on variables such as future sales, sales prices, operating costs, economic conditions, market competition,
and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the
marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount
over the fair value of the assets. No impairment charges were recorded for the years ended December 31, 2013, 2012 or
2011, respectively.
Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with ASC Topic 410 (Asset Retirement and
Environmental Obligations), which requires that the fair value of a liability for an asset retirement obligation be recognized
in the period in which it is incurred. ASC 410 requires the Company to record a liability for the present value using a credit-
adjusted risk free interest rate of the estimated site restoration costs with a corresponding increase to the carrying amount of
the related long-lived assets. As of December 31, 2013 and 2012, the Company did not have the obligation to participate in
any of the capital expenditures for OMLs 120 and 121, and therefore did not have any asset retirement obligations.
RECENTLY ISSUED ACCOUNTING STANDARDS
In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other
Comprehensive Income. The amendments in ASU 2013-02 to Topic 220, Comprehensive Income, update, supersede and
replace the presentation requirements for reclassifications out of accumulated other comprehensive income in ASUs 2011-05
and 2011-12. ASU 2013-02 requires either in a single note or parenthetically on the face of the financial statements, the
effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its
source and the income statement line items affected by the reclassification. The new guidance is effective prospectively for
reporting periods beginning after December 15, 2012. The Company adopted the guidance required as of January 1, 2013.
The required disclosures have been included in Note 5, Accumulated Other Comprehensive Income (Loss) of the Notes to
Consolidated Financial Statements.
In February 2013, the FASB issued ASU 2013-04, Obligations Resulting From Joint and Several Liability Arrangements for
Which the Total Amount of the Obligation is Fixed at the Reporting Date. The amendments in ASU 2013-04 to Topic 405,
Liabilities, provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several
liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting
date, except for obligations addressed with existing U.S. GAAP. The guidance requires an entity to measure those obligations
as the sum of the amount the reporting entity agreed to pay on behalf of its co-obligors. The guidance also requires an entity
to disclose the nature and amount of the obligation, as well as other information about those obligations. The amendment is
effective retrospectively for reporting periods beginning after December 15, 2013. Early adoption is permitted. The adoption
of this guidance is not expected to have a material impact on the Company’s consolidated financial statements.
In April 2013 the FASB issued ASU 2013-07, Liquidation Basis of Accounting. The amendments in ASU 2013-07 to Topic
205, Presentation of Financial Statements, clarify when an entity should apply the liquidation basis of accounting and
provide principles for the recognition and measurement of associated assets and liabilities. In accordance with the
amendments, the liquidation basis is used when liquidation is imminent. Liquidation is considered imminent when the
likelihood is remote that the organization will return from liquidation and either: (a) a plan for liquidation is approved by the
person or persons with the authority to make such a plan effective and the likelihood is remote that the execution of the plan
will be blocked by other parties; or (b) a plan for liquidation is being imposed by other forces. The amendments in ASU
2013-07 are effective prospectively for entities that determine liquidation is imminent for reporting periods beginning after
December 15, 2013, with early adoption permitted. The adoption of this guidance is not expected to have a material impact
on the Company’s consolidated financial statements.
In July 2013 the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss
Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The amendments in ASU 2013-11 to Topic 740,
Income Taxes, clarify that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the
financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a t ax
credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In
situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the
reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity
does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the
financial statements as a liability and should not be combined with deferred tax assets. The amendments in ASU 2013-11 are
effective prospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013.
Retrospective application is permitted. The Company is currently evaluating the possible impact of ASU 2013-11, but does
not anticipate that it will have a material impact on the Company’s consolidated financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company may be exposed to certain market risks related to changes in foreign currency exchange, interest rates, and
commodity prices.
Foreign Currency Exchange Risk
In addition to the U.S. dollar, the Company pays some of its Nigeria, The Gambia, and Kenya expenses in Naira, Dalasi, and
Shillings respectively. Therefore we are subject to foreign currency exchange risk on non-U.S. dollar denominated
transactions on cash flows.
To date the Company has not engaged in hedging activities to hedge our foreign currency exposure in Nigeria. In the future,
the Company may enter into hedging instruments to manage its foreign currency exchange risk or continue to be subject to
exchange rate risk.
Commodity Price Risk
As an independent oil producer, our revenue, other income and profitability, reserve values, access to capital and future rate
of growth are substantially dependent upon the prevailing prices of crude oil. Prevailing prices for such commodities are
subject to wide fluctuations in response to relatively minor changes in supply and demand and a variety of additional factors
beyond our control. Historically, prices received for oil production have been volatile and unpredictable, and such volatilit y
is expected to continue.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The Company’s Financial Statements and the accompanying Notes that are filed as part of this Annual Report are listed
under Part IV, Item 15. Exhibits, Financial Statements and Schedules, and are set forth immediately following the signature
pages of this Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be
disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is
recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such
information is accumulated and communicated to management, including its Chief Executive Officer (“CEO”) and Principal
Financial Officer (“PFO”), as appropriate, to allow timely decisions regarding required disclosure.
Management of the Company, with the participation of its CEO and PFO, evaluated the effectiveness of the Company’s
disclosure controls and procedures. Based on their evaluation, as of the end of the period covered by this Form 10-K, the
Company’s CEO and PFO have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-
15(e) and 15d-15(e) under the Exchange Act were effective.
Management’s Report On Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the
Exchange Act as a process designed by, or under the supervision of, our principal executive and principal financial officers
and is effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles (“GAAP”) and includes those policies and procedures that:
• Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and
dispositions of our assets,
• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial
statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with
authorizations of management and directors of the Company, and
• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of
our assets that could have a material effect on the financial statements.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable
assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal
controls over financial reporting may vary over time. Our system contains self-monitoring mechanisms, and actions are taken
to correct deficiencies as they are identified.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the
criteria described in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (“COSO”).
Based on this assessment, management, including the Company’s CEO and PFO, concluded that our internal control over
financial reporting was effective as of December 31, 2013.
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 year ended December 31, 2013, that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
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, 2013, based on criteria established in the 1992 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, 2013, based on criteria established in the 1992 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, 2013, and our report dated
March 14, 2014 expressed an unqualified opinion on those financial statements.
GRANT THORNTON LLP
Houston, Texas
March 14, 2014
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is incorporated herein by reference to the 2014 Proxy Statement or Form 10-K/A
which will be filed with the SEC not later than 120 days subsequent to December 31, 2013.
ITEM 11. EXECUTIVE COMPENSATION
Information called for by Item 11 of Form 10-K will be set forth in the 2014 Proxy Statement or Form 10-K/A, which is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Information called for by Item 12 of Form 10-K will be set forth in the 2014 Proxy Statement or Form 10-K/A, which is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information called for by Item 13 of Form 10-K will be set forth in the 2014 Proxy Statement or Form 10-K/A, which is
incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information called for by Item 14 of Form 10-K will be set forth in the 2014 Proxy Statement or Form 10-K/A, which is
incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES
(a) Documents filed as part of this Annual Report:
The following is an index of the financial statements, schedules and exhibits included in this Form 10-K or incorporated
herein by reference.
(1) Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm F-1
Consolidated Balance Sheets at December 31, 2013 and 2012 F-3
Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011 F-4
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011 F-5
Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011 F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 F-7
Notes to Consolidated Financial Statements F-8
(2) Consolidated Financial Statement Schedules
Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)
Schedules not included have been omitted because they are not applicable or the required information is shown in S-1
the consolidated financial statements or notes.
(3) Exhibits
The following exhibits are filed with the report:
Exhibit Number Description
2.1 Transfer Agreement, dated as of November 19, 2013, by and among CAMAC Energy Inc.,
CAMAC Petroleum Limited, CAMAC Energy Holdings Limited, CAMAC International
(Nigeria) Limited and Allied Energy Plc (incorporated by reference to Exhibit 2.1 of our
Form 8-K filed on November 22, 2013).
3.1 Amended and Restated Certificate of Incorporation, as amended, of the Company, dated
February 13, 2014 (incorporated by reference to Exhibit 3.1 of our Form 8-K filed on
February 19, 2014).
3.2 Amended and Restated Bylaws of the Company as of April 11, 2011 (incorporated by
reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed on May 3, 2011).
4.1 Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of our Form
10-SB (No. 000-52770) filed on August 15, 2007).
4.2 Form of Common Stock Warrant (incorporated by reference to Exhibit 4.2 of our Form 10-
SB (No. 000-52770) filed on August 15, 2007).
4.3 Company 2007 Stock Plan (incorporated by reference to Exhibit 10.1 of our Form 10-SB
(No. 000-52770) filed on August 15, 2007). *
4.4 Company 2009 Equity Incentive Plan (incorporated by reference to Registration Statement
on Form S-8 (No. 333-175294) filed on July 1, 2011).*
4.5 First Amendment to the Company’s Amended 2009 Equity Incentive Plan, dated February
18, 2014 (incorporated by reference to Exhibit 99.1 of our Form 8-K filed on February 19,
2014).
4.6 Form of Series A Warrant (incorporated by reference to Exhibit 4.1 of our Current Report
on Form 8-K filed on February 12, 2010).
4.7 Form of Series C Warrant (incorporated by reference to Exhibit 4.1 of our Current Report
on Form 8-K filed on March 3, 2010).
4.8 Registration Rights Agreement, by and between the Company and CAMAC Energy
Holdings Limited, dated April 7, 2010 (incorporated by reference to Exhibit 4.1 of our
Current Report on Form 8-K filed on April 13, 2010).
4.9 Form of Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-
K filed on December 23, 2010).
4.10 Registration Rights Agreement, dated as of February 15, 2011, by and among the Company,
CAMAC Energy Holdings Limited, Allied Energy Plc, and CAMAC International (Nigeria)
Limited (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed
on February 16, 2011).
4.11 Registration Rights Agreement, dated February 21, 2014, by and between the Company and
Allied Energy Plc (incorporated by reference to Exhibit 4.1 of our Current Report on Form
8-K filed on February 27, 2014).
4.12 Registration Rights Agreement, dated February 21, 2014, by and between the Company and
The Public Investment Corporation (SOC) Limited (incorporated by reference to Exhibit 4.3
of our Current Report on Form 8-K filed on February 27, 2014).
10.1 Form of Securities Purchase Agreement, dated February 10, 2010 (incorporated by
reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 12, 2010).
10.2 Company 2007 Stock Plan form of Stock Option Agreement (incorporated by reference to
Exhibit 10.2 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). *
10.3 Company 2007 Stock Plan form of Restricted Stock Agreement (incorporated by reference
to Exhibit 10.3 of our Form 10-SB (No. 000-52770) filed on August 15, 2007). *
10.4 Form of Indemnification Agreement for Officers (incorporated by reference to Exhibit 10.4
of our Annual Report on Form 10-K filed on April 15, 2013). *
10.5 Form of Indemnification Agreement for Directors (incorporated by reference to Exibit 10.5
of our Annual Report on Form 10-K filed on April 15, 2013). *
10.6 Company 2009 Equity Incentive Plan form of Stock Option Agreement (incorporated by
reference to Exhibit 10.5 of our Annual Report on Form 10-K (No. 001-34525) filed on
March 2, 2010).*
10.7 Purchase and Sale Agreement, dated November 18, 2009, by and among the Company,
CAMAC Energy Holdings Limited, CAMAC International (Nigeria) Limited, and Allied
Energy Plc. (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K
(No. 001-34525) filed on November 23, 2009).
10.8 Form of Securities Purchase Agreement, dated March 2, 2010 (incorporated by reference to
Exhibit 10.1 of our Current Report on Form 8-K filed March 3, 2010).
10.9 Production Sharing Contract , dated July 22, 2005, by and between Allied Energy
Resources Nigeria Limited, CAMAC International (Nigeria) Limited, and Nigerian Agip
Exploration Limited (incorporated by reference to Annex E on our Form DEF 14A filed
March 19, 2010).
10.10 Agreement Novating Production Sharing Contract, by and among Allied Energy Plc,
CAMAC International (Nigeria) Limited, Nigerian Agip Exploration Limited, and CAMAC
Petroleum Limited, dated April 7, 2010 (incorporated by reference to Exhibit 10.1 of our
Current Report on Form 8-K dated April 13, 2010).
10.11 The Oyo Field Agreement, by and among Allied Energy Plc, CAMAC Energy Holdings
Limited and CAMAC Petroleum Limited, dated April 7, 2010 (incorporated by reference to
Exhibit 10.2 of our Current Report on Form 8-K filed on April 13, 2010).
10.12 The Right of First Refusal Agreement, by and among the Company, CAMAC Energy
Holdings Limited, CAMAC International (Nigeria) Limited, and Allied Energy Plc, dated
April 7, 2010 (incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K
filed on April 13, 2010).
10.13 Purchase and Continuation Agreement, dated December 10, 2010, by and among CAMAC
Energy Inc., CAMAC Petroleum Limited, CAMAC Energy Holdings Limited, Allied
Energy Plc, and CAMAC International (Nigeria) Limited (incorporated by reference to
Exhibit 10.1 of our Current Report on Form 8-K filed on December 13, 2010).
10.14 Form of Securities Purchase Agreement (incorporated by reference to Exhibit 10.1 of our
Current Report filed on December 23, 2010).
10.15 Limited Waiver Agreement Related to Purchase and Continuation Agreement, dated as of
February 15, 2011, by and among CAMAC Energy Inc., CAMAC Petroleum Inc., CAMAC
Energy Holdings Limited, Allied Energy Plc, and CAMAC International (Nigeria) Limited
(incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on
February 16, 2011).
10.16 Second Agreement Novating Production Sharing Contract, dated as of February 15, 2011,
by and among Allied Energy Plc, CAMAC International (Nigeria) Limited, Nigerian Agip
Exploration Limited, and CAMAC Petroleum Limited (incorporated by reference to Exhibit
10.2 of our Current Report on Form 8-K filed on February 16, 2011).
10.17 Amended and Restated Oyo Field Agreement Hereby Renamed OML 120/121 Management
Agreement, dated as of February 15, 2011, by and among CAMAC Petroleum Limited,
CAMAC Energy Holdings Limited, and Allied Energy Plc (incorporated by reference to
Exhibit 10.4 of our Current Report on Form 8-K filed on February 16, 2011).
10.18 Promissory Note Agreement dated June 6, 2011 by and among CAMAC Petroleum Limited
and Allied Energy Plc. (incorporated by reference to Exhibit 10.2 of our Current Report on
Form 8-K filed on June 9, 2011).
10.19 Guaranty Agreement dated June 6, 2011 by and among CAMAC Energy Inc. and Allied
Energy Plc. (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K
filed on June 9, 2011).
10.20 Executive Employment Agreement dated September 1, 2011 by and between Nicholas J.
Evanoff and the Company (incorporated by reference to Exhibit 10.1 of our Current Report
on Form 8-K filed on September 7, 2011).*
10.21 Executive Employment Agreement dated September 1, 2011 by and between Babatunde
Omidele and the Company (incorporated by reference to Exhibit 10.2 of our Current Report
on Form 8-K filed on September 7, 2011).*
10.22 Executive Consulting Agreement effective March 1, 2012 by and between Earl W. McNiel
and the Company (incorporated by reference to Exhibit 10.47 of our Annual Report on
Form 10-K filed on March 15, 2012).*
10.23 Production Sharing Contract, by and between the Government of the Republic of Kenya and
CAMAC Energy Kenya Limited, dated May 10, 2012, relating to Block L1B (incorporated
by reference to Exhibit 10.4 of our Form 10-Q filed on May 9, 2012).
10.24 Production Sharing Contract, by and between the Government of the Republic of Kenya and
CAMAC Energy Kenya Limited, dated May 10, 2012, relating to Block L16 (incorporated
by reference to Exhibit 10.5 of our Form 10-Q filed on May 9, 2012).
10.25 Production Sharing Contract, by and between the Government of the Republic of Kenya and
CAMAC Energy Kenya Limited, dated May 10, 2012, relating to Block L27 (incorporated
by reference to Exhibit 10.6 of our Form 10-Q filed on May 9, 2012).
10.26 Production Sharing Contract, by and between the Government of the Republic of Kenya and
CAMAC Energy Kenya Limited, dated May 10, 2012, relating to Block L28 (incorporated
by reference to Exhibit 10.7 of our Form 10-Q filed on May 9, 2012).
10.27 Petroleum (Exploration, Development and Production) License, by and between the
Republic of The Gambia and CAMAC Energy A2 Gambia Ltd., dated May 24, 2012,
relating to Block A2 (incorporated by reference to Exhibit 10.8 of our Form 10-Q filed on
May 9, 2012).
10.28 Petroleum (Exploration, Development and Production) License, by and between the
Republic of The Gambia and CAMAC Energy A5 Gambia Ltd., dated May 24, 2012,
relating to Block A5 (incorporated by reference to Exhibit 10.9 of our Form 10-Q filed on
May 9, 2012).
10.29 Share Sale and Purchase Agreement, by and between Leyshon Resources Limited and
CAMAC Energy Inc., dated July 22, 2012 (incorporated by reference to Exhibit 10.1 of our
Form 10-Q filed on November 9, 2013).
10.30 Executive Employment Agreement dated February 27, 2013 by and between Earl W.
McNiel and the Company (incorporated by reference to Exhibit 10.38 of our Annual Report
on Form 10-K filed April 15, 2013).*
10.31 Amended and Extended Maturity Date of the Promissory Note dated June 6, 2011, amended
August 3, 2012, by and among CAMAC Petroleum Limited and Allied Energy Plc
(incorporated by reference to Exhibit 10.39 of our Form 10-K filed on April 15, 2013).
10.32 Amended and Extended Maturity Date of the Promissory Note dated June 6, 2011, amended
March 25, 2013, by and among CAMAC Petroleum Limited and Allied Energy Plc
(incorporated by reference to Exhibit 10.40 of our Form 10-K filed on April 15, 2013).
10.33 Technical Services Agreement, by and between Allied Energy Plc and CAMAC Petroleum
Limited, dated January 10, 2013 (incorporated by reference to Exhibit 10.41 of our Form
10-K filed on April 15, 2013).
10.34 Amended and Restated Promissory Note, effective September 10, 2013, by and among
CAMAC Petroleum Limited and Allied Energy Plc (incorporated by reference to Exhibit
10.1 of our Form 10-Q filed on November 14, 2013).
10.35 Amendment no. 1 to Guaranty Agreement, effective September 10, 2013, by and among the
Company and Allied Energy Plc (incorporated by reference to Exhibit 10.2 of our Form 10-
Q filed on November 14, 2013).
10.36 Equitable Share Mortgage Arrangement, effective September 10, 2013, by and among the
Company and Allied Energy Plc (incorporated by reference to Exhibit 10.3 of our Form 10-
Q filed on November 14, 2013).
10.37 Executive Employment Agreement, dated September 1, 2013, by and between Heidi Wong
and the Company (incorporated by reference to Exhibit 10.4 of our Form 10-Q filed on
November 14, 2013).*
10.38 Share Purchase Agreement, effective as of November 18, 2013, by and between CAMAC
Energy Inc. and Public Investment Corporation (SOC) Limited (incorporated by reference
to Exhibit 10.1 of our Form 8-K filed on November 22, 2013).
10.39 Third Agreement Novating Production Sharing Contract, dated as of November 19, 2013,
by and among Allied Energy Plc, CAMAC International (Nigeria) Limited and CAMAC
Petroleum Limited (incorporated by reference to Exhibit 10.2 of our Form 8-K filed on
November 22, 2013).
10.40 Convertible Subordinated Note, dated February 21, 2014, by and between the Company and
Allied Energy Plc (incorporated by reference to Exhibit 4.2 of our Form 8-K filed on
February 27, 2014).
10.41 Assignment and Bill of Sale, dated February 21, 2014, by and between Allied Energy Plc
and CAMAC Petroleum Limited (incorporated by reference to Exhibit 10.1 of our Form 8-
K filed on February 27, 2014).
10.42 Right of First Refusal and Corporate Opportunities Agreement, dated February 21, 2014, by
and among the Company and CAMAC Energy Holdings Limited (incorporated by reference
to Exhibit 10.2 of our Form 8-K filed on February 27, 2014).
21.1 Subsidiaries of the Company
23.1 Consent of Grant Thornton LLP, Independent Registered Public Accounting Firm, filed
herewith.
23.2 Consent of RBSM LLP, Independent Registered Public Accounting Firm, filed herewith.
23.3 Consent of DeGolyer and MacNaughton
31.1 Certification of Chief Executive Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Principle Financial and Accounting Officer Pursuant to 15 U.S.C. § 7241, as
Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Certification of Chief Executive Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification of Principle Financial and Accounting Officer Pursuant to 18 U.S.C. § 1350, as
Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1 Report of DeGolyer and MacNaughton
101. INS XBRL Instance Document.
101. SCH XBRL Schema Document.
101. CAL XBRL Calculation Linkbase Document.
101. DEF XBRL Taxonomy Extension Definition Linkbase Document
101. LAB XBRL Label Linkbase Document.
101. PRE XBRL Presentation Linkbase Document.
* Indicates a management contract or compensatory plan or arrangement.
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 14, 2014
CAMAC Energy Inc.
By: /s/ Dr. Kase Lukman Lawal
Dr. Kase Lukman Lawal
Chief Executive Officer
(Principal Executive Officer)
By: /s/ Earl W. McNiel
Earl W. McNiel
Senior Vice President and Chief Financial
Officer
(Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of registrant and in the capacities and on the dates indicated.
Title Date
/s/ DR. KASE LUKMAN LAWAL Director and Chief Executive Officer March 14, 2014
Dr. Kase Lukman Lawal (Principal Executive Officer)
/s/ EARL W. MCNIEL Senior Vice President and Chief Financial Officer March 14, 2014
Earl W. McNiel (Principal Financial Officer)
Vice President, Controller and Chief Accounting
/s/ ADAMA TRAORE March 14, 2014
Officer
Adama Traore (Principal Accounting Officer)
/s/ DR. LEE PATRICK BROWN Director March 14, 2014
Dr. Lee Patrick Brown
/s/ WILLIAM J. CAMPBELL Director March 14, 2014
William J. Campbell
/s/ J KENT FRIEDMAN Director March 14, 2014
J. Kent Friedman
/s/ JOHN HOFMEISTER Director March 14, 2014
John Hofmeister
/s/ IRA WAYNE MCCONNELL Director March 14, 2014
Ira Wayne McConnell
/s/ HAZEL O'LEARY Director March 14, 2014
Hazel O'Leary
GRANT THORNTON LLP
CERTIFIED PUBLIC ACCOUNTANTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
CAMAC Energy, Inc.
We have audited the accompanying consolidated balance sheets of CAMAC Energy, Inc. (a Delaware corporation) and
subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations,
comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the two years in the period ended
December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financi al
position of CAMAC Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and
their cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles
generally accepted in the United States of America.
We 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, 2013, based on criteria established in the 1992
Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated March 14, 2014 expressed an unqualified opinion thereon.
/s/ GRANT THORNTON LLP
Houston, Texas
March 14, 2014
RBSM LLP
CERTIFIED PUBLIC ACCOUNTANTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
CAMAC Energy Inc.
Houston, TX
We have audited CAMAC Energy Inc. and its subsidiaries’ (the “Company”) accompanying consolidated statements of
operations, comprehensive income (loss), changes in equity and cash flows for the year ended December 31, 2011. These
financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
these financial statements based upon our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States
of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatements. An audit includes examining on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our
audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of
CAMAC Energy Inc. and its subsidiaries’ operations and its cash flows for the year ended December 31, 2011 in conformity
with accounting principles generally accepted in the United States of America.
New York, New York
March 15, 2012, except for paragraph 6 of Note 2,
as to which the date is March 14, 2014
CAMAC ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except for share and per share data)
As of December 31,
2013 2012
ASSETS
Current assets:
Cash and cash equivalents $ 163 $ 3,806
Accounts receivable 1,112 6,103
Prepaids and other current assets 857 1,013
Total current assets 2,132 10,922
Property, plant and equipment, net:
Oil and gas properties (successful efforts method of accounting), net 184,408 188,630
Other property and equipment, net 752 456
Total property, plant and equipment, net 185,160 189,086
Other assets 51 11
Noncurrent assets of discontinued operations - 36
Total Assets $ 187,343 $ 200,055
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 6,239 $ 15,112
Accrued expenses 7,446 2,770
Note payable - related party 6,496 -
Total current liabilities 20,181 17,882
Long-term note payable - related party - 872
Other long-term liabilities 67 55
Total liabilities 20,248 18,809
Commitments and Contingencies
Equity
Stockholders' equity - CAMAC Energy Inc.
Preferred stock $0.001 par value - 50,000,000 shares authorized, none issued and
outstanding - -
Common stock $0.001 par value - 730,440,000 shares authorized, 382,362,236 and
380,060,948 shares issued and outstanding as of December 31, 2013 and 2012,
respectively 382 380
Paid-in capital 464,590 462,577
Accumulated deficit (297,877) (281,929)
Accumulated other comprehensive income (loss) - 224
Total stockholders' equity - CAMAC Energy Inc. 167,095 181,252
Noncontrolling interests of discontinued operations - (6)
Total equity 167,095 181,246
Total liabilities and equity $ 187,343 $ 200,055
The accompanying notes are an integral part of these consolidated financial statements.
CAMAC ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for per share amounts)
Years Ended December 31,
2013 2012 2011
Continuing Operations
Crude oil sales, net of royalties $ 7,873 $ 16,624 $ 37,922
Operating costs and expenses:
Production costs (666) 326 30,882
Exploratory expenses 5,501 3,236 890
Depreciation, depletion and amortization 4,528 10,750 13,477
General and administrative expenses 14,460 10,998 13,336
Total operating costs and expenses 23,823 25,310 58,585
Operating loss (15,950) (8,686) (20,663)
Other income (expense), net 38 (582) (328)
Loss from continuing operations before income taxes (15,912) (9,268) (20,991)
Income tax expense - - -
Net loss from continuing operations (15,912) (9,268) (20,991)
Discontinued Operations
Net loss from discontinued operations, net of tax (36) (991) (4,012)
Gain on divestiture, net - 4,160 -
Net income (loss) from discontinued operations (36) 3,169 (4,012)
Net loss (15,948) (6,099) (25,003)
Noncontrolling interests - discontinued operations - 8 90
Net loss attributable to CAMAC Energy Inc. $ (15,948) $ (6,091) $ (24,913)
Net (loss) income per common share attributable to CAMAC Energy
Inc. - basic
Continuing operations $ (0.04) $ (0.02) $ (0.06)
Discontinued operations $ (0.00) $ 0.01 $ (0.01)
Total $ (0.04) $ (0.02) $ (0.07)
Net (loss) income per common share attributable to CAMAC Energy
Inc. - diluted
Continuing operations $ (0.04) $ (0.02) $ (0.06)
Discontinued operations $ (0.00) $ 0.01 $ (0.01)
Total $ (0.04) $ (0.02) $ (0.07)
Weighted average common shares outstanding:
Basic 381,255 379,373 376,312
Diluted 381,255 379,373 376,312
The accompanying notes are an integral part of these consolidated financial statements.
CAMAC ENERGY INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
Years Ended December 31,
2013 2012 2011
Net loss $ (15,948) $ (6,099) $ (25,003)
Other comprehensive income (loss):
Foreign currency transactions (224) 94 (31)
Unrealized gain (loss) on investments, net of taxes - 395 (114)
Total other comprehensive income (loss) (224) 489 (145)
Comprehensive loss (16,172) (5,610) (25,148)
Comprehensive loss attributable to noncontrolling interests - 8 88
Comprehensive loss attributable to CAMAC Energy Inc. $ (16,172) $ (5,602) $ (25,060)
The accompanying notes are an integral part of these consolidated financial statements.
CAMAC ENERGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(In thousands)
Accumulated
Additional Other Total
Common Stock Paid-in Accumulated Comprehensive Noncontrolling Stockholders'
Shares Amount Capital Deficit Income (Loss) Interest Equity
At December 31, 2010 374,014 $ 374 $ 458,303 $ (250,925) $ (120) $ (643) $ 206,989
Stock issued for services 2,045 2 705 - - - 707
Exercise of warrants and
options 786 1 176 - - - 177
Vesting of restricted stock 1,488 1 (1) - - - -
Stock-based employee
compensation 2,484 - - - 2,484
Adjustments to
noncontrolling interest (733) - - 735 2
Net loss - (24,913) - (90) (25,003)
Other comprehensive
income (loss):
Foreign currency gain
(loss) - - (31) - (31)
Unrealized loss on
investments, net of taxes - - (114) - (114)
At December 31, 2011 378,333 $ 378 $ 460,934 $ (275,838) $ (265) $ 2 $ 185,211
Exercise of warrants and
options 17 - 3 - - - 3
Vesting of restricted stock 1,251 1 - - - - 1
Contingent consideration
stock issued 460 1 889 - - - 890
Stock-based employee
compensation 739 - - - 739
Net loss - (6,091) - (8) (6,099)
Other comprehensive
income (loss):
Foreign currency gain
(loss) 12 - 94 - 106
Unrealized gain on
investments, net of taxes - - 395 - 395
At December 31, 2012 380,061 $ 380 $ 462,577 $ (281,929) $ 224 $ (6) $ 181,246
Vesting of restricted stock 2,301 2 - - - - 2
Stock-based employee
compensation 2,013 - - - 2,013
Realized foreign currency
gain - - (224) - (224)
Adjustments to
noncontrolling interest - - - 6 6
Net loss - (15,948) - - (15,948)
At December 31, 2013 382,362 $ 382 $ 464,590 $ (297,877) $ - $ - $ 167,095
The accompanying notes are an integral part of these consolidated financial statements.
CAMAC ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
2013 2012 2011
Cash flows from operating activities
Net loss $ (15,948) $ (6,099) $ (25,003)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization 4,528 10,758 13,530
Stock-based compensation 2,013 739 2,484
Currency transaction (gain) loss (224) 22 (31)
Dry hole costs - (37) 2,176
Gain on divestiture, net - (4,160) -
Other 16 55 -
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable (3,046) 12,836 (8,528)
Decrease in other current assets 156 649 1,841
Decrease in inventories - - 72
Increase (decrease) in accounts payable 438 (20,772) 35,834
Increase (decrease) in accrued expenses 4,676 112 (37,029)
Net cash used in operating activities (7,391) (5,897) (14,654)
Cash flows from investing activities
Capital expenditures (602) (3,576) (7,159)
Proceeds on divestiture, net - 2,364 -
Net sales of available for sale securities - - 256
Decrease in other assets - 465 43
Proceeds on long-term investments - 1,966 -
Net cash (used in) provided by investing activities (602) 1,219 (6,860)
Cash flows from financing activities
Proceeds from note payable - related party 4,350 5,000 31,000
Repayments of note payable - related party - (10,128) (25,000)
Proceeds from exercise of warrants and stock options - 3 177
Net cash provided by (used in) financing activities 4,350 (5,125) 6,177
Effect of exchange rate on cash and cash equivalents - (17) 45
Net decrease in cash and cash equivalents (3,643) (9,820) (15,292)
Cash and cash equivalents at beginning of period 3,806 13,626 28,918
Cash and cash equivalents at end of period $ 163 $ 3,806 $ 13,626
Supplemental disclosure of cash flow information
Cash paid for:
Interest, net $ 99 $ 117 $ 120
Contingent consideration stock $ - $ 890 $ -
Supplemental disclosure of non-cash investing and financing
activities:
Nonsubsidiary common stock received as partial proceeds for
divestiture, net $ - $ 1,877 $ -
Common stock issued for services $ - $ - $ 706
Related party accounts payable, net, settled with note payable -
related party $ 1,274 $ - $ -
The accompanying notes are an integral part of these consolidated financial statements
CAMAC ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 8 licenses in 3
countries covering an area of approximately 41,000 square kilometers (approximately 10 million acres). The Company owns
producing properties and conducts exploration activities as a non-operator in Nigeria, conducts explorations activities as an
operator onshore and offshore Kenya, and conducts exploration activities as an operator in The Gambia.
The Company’s corporate headquarters is located in Houston, Texas and has offices in Nairobi, Kenya, Banjul, The Gambia
and Lagos, Nigeria.
CAMAC’s operating subsidiaries are CAMAC Energy Limited (“CEL”), CAMAC Petroleum Limited (“CPL”), CAMAC
Energy International Limited (“CEIL”), CAMAC Energy Ghana Limited, CAMAC Energy Kenya Limited, CAMAC Energy
Gambia A5 Limited, and CAMAC Energy Gambia A2 Limited.
CAMAC’s related parties are CAMAC Energy Holdings Limited (“CEHL”), CAMAC International Nigeria Limited
(“CINL”), CAMAC International Limited (“CIL”) and Allied Energy PLC (“Allied”).
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 the above listed related parties. Dr. Lawal also owns 27.7% of CIL, which indirectly owns 100% of
CEHL. As a result, Dr. Lawal may be deemed to have an indirect material interest in transactions contemplated with any of
the above companies and their affiliates named above as the Company’s related.
NOTE 2. --- BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The terms “we,” “us,” “our,” “Company,” and “our Company” refer to CAMAC and its subsidiaries and affiliates.
The accompanying consolidated financial statements include the accounts of the Company and its wholly owned and
majority-owned direct and indirect subsidiaries and have been prepared in accordance with generally accepted accounting
principles in the United States (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange
Commission (the “SEC”). All significant intercompany transactions and balances have been eliminated in consolidation. The
consolidated financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair
presentation of the consolidated financial position and results of operations for the indicated periods. All such adjustments
are of a normal recurring nature.
In August 2012, the Company divested its wholly owned Hong Kong subsidiary Pacific Asia Petroleum Limited for cash and
shares of stock. The Company has classified the current and historical results of its China operations, including other inactive
operations not involved in this sale, as discontinued operations, net of tax, in the accompanying consolidated statements of
operations. See Note 3, Discontinued Operations, for more information regarding the sale.
As a result of the above transaction, the Company is reporting its China operations, including other inactive operations not
involved in this sale, for all presented periods in discontinued operations.
On January 24, 2014 the Company’s Board of Directors declared the stock dividend on all shares of the Company's
outstanding Common Stock entitling all stockholders of record as of the close of business on February 13, 2014, to recieve an
additional 1.4348 shares of Common Stock for every share of Common Stock held (the "Stock Dividend"). Payment of the
Stock Dividend was conditioned on (i) approval of the Company’s stockholders at the special meeting of stockholders to be
held on February 13, 2014 of certain proposals related to the Allied Transaction, including a proposal to amend the
Company’s certificate of incorporation to increase the number of authorized shares of Common Stock and (ii) approval of the
listing of the Company’s Common Stock on the JSE. On February 13, 2014, the Company held a special meeting of its
stockholders to consider and vote upon the proposals mentioned above and other related agenda items. All of the proposals
presented at the meeting received the requisite shareholder approval and the approval of the JSE listing was successfully
obtained. On February 21, 2014, the Company paid the Stock Dividend pursuant to which each share of stock of record as of
the close of business on February 13, 2014, carried the right to receive 1.4348 shares of Common Stock for every one share
of Common Stock held.
Per Accounting Standard Codification (“ASC”) 505, Equity, the above Stock Dividend is to be accounted for as a Stock Split
due to its large nature (exceeds 25% of the total shares outstanding prior to the distribution). The effect is a retroactive
adjustment to the financial statements and associated footnotes as if the dividend had occurred in the first period presented.
Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts and activities of the Company, subsidiaries in which the Company
has a controlling financial interest, and entities for which the Company is the primary beneficiary. All material intercompany
accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates
based on assumptions. Estimates affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and
the reported amounts of revenues and expenses during the reporting periods. Accordingly, our accounting estimates require
the exercise of judgment. While management believes that the estimates and assumptions used in preparation of consolidated
financial statements are appropriate, actual results could differ from those estimates. Estimates that may have a significant
effect include oil and natural gas reserve quantities, depletion and amortization relating to oil and natural gas properties, and
income taxes. The accounting estimates used in the preparation of the consolidated financial statements may change as new
events occur, more experience is acquired, additional information is obtained and our operating environment changes.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, demand deposits and short-term investments with initial maturities of three
months or less.
Accounts Receivable and Allowance for Doubtful Accounts
Trade accounts receivable are accounted for at cost less allowance for doubtful accounts . We establish provisions for losses
on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable.
Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification
method. As of December 31, 2013 and 2012, no allowance for doubtful accounts was necessary.
Successful Efforts Method of Accounting for Oil and Gas Activities
The Company follows the successful efforts method of accounting of its costs of acquisition, exploration and development of
oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with
exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or
not successful, are capitalized when incurred. Drilling costs of exploratory wells are capitalized pending determination that
proved reserves have been found. If the determination is dependent upon the results of planned additional wells and require
additional capital expenditures to develop the reserves, the drilling costs will be capitalized as long as sufficient reserves
have been found to justify completion of the exploratory well as a producing well, and additional wells are underway or
firmly planned to complete the evaluation of the well. Exploratory wells not meeting the criteria for continued capitalization
are expensed when such a determination is made. Other exploration costs are expensed as incurred.
Depreciation, depletion and amortization for productive oil and gas properties are recorded on a unit-of-production basis. For
other depreciable property, depreciation is recorded on a straight line basis over the estimated useful life of the assets which
ranges between three to five years or the lease term. Repairs and maintenance costs are charged to expense as incurred.
Impairment of Long-Lived Assets
The Company reviews its long-lived assets in property, plant and equipment for impairment in accordance with ASC Topic
360, (Property, Plant and Equipment). Review for impairment of long-lived assets occurs whenever changes in
circumstances indicate that the carrying amount of assets may not be fully recoverable. Possible indicators of impairment
include current period losses combined with a history of losses, significant downward oil and gas reserve revisions, or when
changes in other circumstances indicate the carrying amount of an asset may not be recoverable. An impairment loss is
recognized for assets to be held and used when the estimated undiscounted future cash flows expected to result from the asset
including ultimate disposition are less than its carrying amount. In the case of oil and gas properties, the Company estimates
the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows are
determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic
conditions during the remaining useful life of the asset. The Company’s cash flow projections into the future include
assumptions on variables such as future sales, sales prices, operating costs, economic conditions, market competition and
inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the
marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount
over the fair value of the assets. No impairment charges were recorded for the years ended December 31, 2013, 2012 or
2011, respectively.
Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with ASC Topic 410 (Asset Retirement and
Environmental Obligations), which requires that the fair value of a liability for an asset retirement obligation be recognized
in the period in which it is incurred. ASC 410 requires the Company to record a liability for the present value using a credit-
adjusted risk free interest rate of the estimated site restoration costs with a corresponding increase to the carrying amount of
the related long-lived assets. As of December 31, 2013 and 2012, the Company did not have the obligation to participate in
any of the capital expenditures for OMLs 120 and 121, and therefore did not have any asset retirement obligations.
Revenues
Revenues are recognized when a lifting (sale) occurs. The recognition criteria are satisfied when there exists a signed contract
with defined pricing, delivery and acceptance (as defined in the contract) of the product or service have occurred, there is no
significant uncertainty of collectability, and the amount is not subject to refund. Crude oil revenues are net of royalties.
Income Taxes
The Company provides for income taxes using the asset and liability method of accounting for income taxes in accordance
with ASC Topic 740 (Income Taxes). Under the asset and liability method, deferred tax assets and liabilities are recognized
for temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting
purposes and for operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted
tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered
or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that
includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not
that the related tax benefits will not be fully realized.
The Company 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 to recognize in the consolidated financial statements. See Note 8 – Income Taxes for further
information.
Stock-Based Compensation
The Company recognizes all stock-based payments to employees, including grants of employee stock options, in the
consolidated financial statements based on their grant-date fair values in accordance with ASC Topic 718-10 (Stock
Compensation). The Company values its stock options awarded using the Black-Scholes option pricing model, and the
restricted stock is valued at the grant date closing market price. Such costs are recognized over the period during which an
employee is required to provide service in exchange for the award (which is usually the vesting period). Stock-based
compensation paid to non-employees in vested stock is valued at the fair value at the applicable measurement date and
charged to expense as services are rendered.
Net Earnings (Loss) Per Common Share
The Company computes earnings or loss per share under ASC Topic 260 (Earnings per Share). Net earnings or loss per
common share is computed by dividing net earnings or loss by the weighted average number of shares of common stock and
applicable dilutive common stock equivalents outstanding during the year. Dilutive common stock equivalents consist of
shares issuable upon the exercise of the Company's stock options, unvested restricted stock, and warrants (calculated using
the treasury stock method). Potential dilutive common shares that have an anti-dilutive effect (e.g., those that increase
earnings per share or decrease net loss per share) are excluded from diluted earnings (loss) per share.
Recently Issued Accounting Standards
In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other
Comprehensive Income. The amendments in ASU 2013-02 to Topic 220, Comprehensive Income, update, supersede and
replace the presentation requirements for reclassifications out of accumulated other comprehensive income in ASUs 2011-05
and 2011-12. ASU 2013-02 requires either in a single note or parenthetically on the face of the financial statements, the
effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its
source and the income statement line items affected by the reclassification. The new guidance is effective prospectively for
reporting periods beginning after December 15, 2012. The Company adopted the guidance required as of January 1, 2013.
The required disclosures have been included in Note 5, Accumulated Other Comprehensive Income (Loss) of the Notes to
Consolidated Financial Statements
In February 2013, the FASB issued ASU 2013-04, Obligations Resulting From Joint and Several Liability Arrangements for
Which the Total Amount of the Obligation is Fixed at the Reporting Date. The amendments in ASU 2013-04 to Topic 405,
Liabilities, provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several
liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting
date, except for obligations addressed with existing U.S. GAAP. The guidance requires an entity to measure those obligations
as the sum of the amount the reporting entity agreed to pay on behalf of its co-obligors. The guidance also requires an entity
to disclose the nature and amount of the obligation, as well as other information about those obligations. The amendment is
effective retrospectively for reporting periods beginning after December 15, 2013. Early adoption is permitted. The adoption
of this guidance is not expected to have a material impact on the Company’s consolidated financial statements.
In April 2013 the FASB issued ASU 2013-07, Liquidation Basis of Accounting. The amendments in ASU 2013-07 to Topic
205, Presentation of Financial Statements, clarify when an entity should apply the liquidation basis of accounting and
provide principles for the recognition and measurement of associated assets and liabilities. In accordance with the
amendments, the liquidation basis is used when liquidation is imminent. Liquidation is considered imminent when the
likelihood is remote that the organization will return from liquidation and either: (a) a plan for liquidation is approved by the
person or persons with the authority to make such a plan effective and the likelihood is remote that the execution of the plan
will be blocked by other parties; or (b) a plan for liquidation is being imposed by other forces. The amendments in ASU
2013-07 are effective prospectively for entities that determine liquidation is imminent for reporting periods beginning after
December 15, 2013, with early adoption permitted. The adoption of this guidance is not expected to have a material impact
on the Company’s consolidated financial statements.
In July 2013 the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss
Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The amendments in ASU 2013-11 to Topic 740,
Income Taxes, clarify that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the
financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax
credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In
situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the
reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity
does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the
financial statements as a liability and should not be combined with deferred tax assets. The amendments in ASU 2013-11 are
effective prospectively for fiscal years, and interim periods within those years, beginning after December 15, 2013.
Retrospective application is permitted. The Company is currently evaluating the possible impact of ASU 2013-11, but does
not anticipate that it will have a material impact on the Company’s consolidated financial statements.
NOTE 3 – 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:
Years Ended December 31,
2013 2012 2011
(In thousands)
Costs and expenses:
Exploratory expenses $ - $ 204 $ 2,545
Depreciation, depletion and amortization - 8 53
General and administrative expenses 36 779 1,642
Other income - - (228)
Total costs and expenses 36 991 4,012
Loss before income taxes (36) (991) (4,012)
Income tax expense - - -
Net loss before noncontrolling interests (36) (991) (4,012)
Noncontrolling interests - 8 90
Net loss $ (36) $ (983) $ (3,922)
Assets and liabilities of discontinued operations are as follows:
As of December
31,
2012
(In thousands)
Other assets $ 36
Total assets $ 36
NOTE 4. -- ACQUISITIONS
Award of Kenya Exploration Blocks
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 exploration blocks L1B and L16, and new offshore exploration blocks L27
and L28. For all blocks, the Company is the operator, with the Government having the right to participate up to 20%, either
directly or through an appointee, in any area subsequent to declaration of a commercial discovery. The Company is
responsible for all exploration expenditures.
The Kenya PSCs for blocks L1B and L16 each provide for an initial exploration period of two years with specified minimum
work obligations during that period. Prior to the end of the initial exploration period, the Company will conduct for each
block a gravity and magnetic survey and acquire, process and interpret 2D seismic data. The gravity and magnetic survey on
blocks L1B and L16 was completed in April, 2013. 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 3D seismic data and the
drilling of one exploratory well on each block during each such additional period. In December 2013, the company initiated
an Environmental and Social Impact Assessment (ESIA) study in blocks L1B and L16 in order to obtain the license to carry
out a 2D seismic survey.
The Kenya PSCs for blocks L27 and L28 each provide for an initial exploration period of three years with specified
minimum work obligations during that period. Prior to the end of the initial exploration period, the Company will conduct for
each block a regional geological and geophysical study, acquire 2D seismic data and acquire, process and interpret 3D
seismic data. The Company has the right to apply for up to two additional two-year exploration periods with specified
additional minimum work obligations, including the drilling of one exploratory well on each block, during each such
additional period. CAMAC is participating in a multi-client combined gravity / magnetic and 2D seismic survey which are
currently underway in blocks L27 and L28.
In addition to the minimum work obligations, each of the Kenya PSCs requires annual surface rental payments, training fund
payments and contributions to local community development projects.
Award of The Gambia Licenses
In May 2012, the Company, through a wholly owned subsidiary, signed two Petroleum Exploration, Development &
Production Licenses with The Republic of The Gambia, for exploration blocks A2 and A5. For both blocks, the Company is
the operator, with the GNPC having the right to elect to participate up to a 15% interest, following approval of a development
and production plan. The Company is responsible for all expenditures prior to such approval even if the GNPC elects to
participate.
The Gambia Licenses for both blocks provide for an initial exploration period of four years with specified work obligations
during that period. Prior to the end of the initial exploration period, the Company will conduct, for each block, a regional
geological study, acquire, process and interpret 750 sq. km of 3D seismic data, drill one exploration well to the total depth of
5,000 meters below mean sea level and evaluate drilling results, with the first two work obligations (regional geological
study and 3D seismic data acquisition and processing) due prior to the end of the second year. The Company has the right to
apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including
the drilling of one exploration well during each additional period for each block.
In addition to the minimum work obligations, The Gambia Licenses require annual rental payments, training and community
fees.
NOTE 5. --- ACCUMULATED OTHER COMPREHENSIVE INCOME
The following summarizes the changes in the balances of each component of accumulated other comprehensive
income (loss):
Foreign
Currency
Gain (Loss)
(In thousands)
Balance at December 31, 2012 $ 224
Realized foreign currency gain (224)
Balance at December 31, 2013 $ -
NOTE 6. --- PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment were comprised of the following:
As of December 31,
2013 2012
Oil and gas properties: (In thousands)
Proved oil and gas properties $ 206,212 $ 206,212
Accumulated depreciation, depletion and amortization (30,044) (25,822)
Proved oil and gas properties, net 176,168 180,390
Unproved oil and gas properties 8,240 8,240
Oil and gas properties, net 184,408 188,630
Other property and equipment 1,590 989
Accumulated depreciation (838) (533)
Other property and equipment, net 752 456
Total property, plant and equipment $ 185,160 $ 189,086
NOTE 7. --- NOTE PAYABLE – RELATED PARTY
In June 2011, CPL, a wholly owned subsidiary of the Company, executed a Promissory Note in favor of Allied. Under the
initial terms of the Promissory Note, Allied agreed to make loans to CPL from time to time for purposes of making payments
relating to the workover of the Oyo well #5 in an aggregate sum of up to $25.0 million. Interest accrues on the outstanding
principal under the Promissory Note at a rate of 30 day LIBOR plus 2% per annum. In September 2013, the Company and
Allied amended the Promissory Note and the Guaranty to add the Company as a borrower, to allow for borrowings of up to
$10.0 million for general corporate purposes and to pledge the stock of the subsidiary of CEI that holds the exploration
licenses in The Gambia and Kenya as collateral pursuant to an equitable share mortgage arrangement. As of December 31,
2013, the book value of the exploration licenses in The Gambia and Kenya was $3.2 million. Pursuant to the initial terms of
the Promissory Note, the outstanding principal amount of all loans was to mature on June 6, 2013. In August 2012, the
Promissory Note was amended to extend the maturity date to October 15, 2013, and in March 2013 the Promissory Note was
again amended to extend the maturity date to July 15, 2014. In January 2014, Allied agreed to amend the Promissory Note
and extend the maturity date to July 15, 2015 in the event the Company is not successful in obtaining external financing
arrangements by June 30, 2014. The Company has guaranteed all of CPL’s obligations under the Promissory Note. As of
December 31, 2013, $6.5 million was outstanding under the Promissory Note.
Dr. Kase Lawal, the Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer, is
a director of each of CEHL, CINL, and the Lender. Dr. Lawal also owns 27.7% of CIL, which indirectly owns 100% of
CEHL, and CINL and the Lender are each wholly-owned subsidiaries of CEHL. As a result, Dr. Lawal is deemed to have an
indirect material interest in the transaction contemplated by the Promissory Note. Dr. Lawal fully disclosed the material facts
as to his relationship to the Lender prior to Board approval.
NOTE 8. --- 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:
Years Ended December 31,
2013 2012 2011
(In thousands)
Net loss attributable to CAMAC Energy Inc. before
income tax expense $ (15,948) $ (6,091) $ (24,913)
Expected income tax provision at statutory rate of 35% $ (5,582) $ (2,132) $ (8,720)
Increase (decrease) due to:
Foreign-incorporated subsidiaries (26) (4,463) 4,102
Net losses not realizable currently for U.S. tax purposes 5,608 6,595 4,618
Total income tax expense $ - $ - $ -
Significant components of our deferred tax assets are as follows:
As of December 31,
2013 2012
(In thousands)
Basis difference in fixed assets $ 927 $ 113
Net operating losses 24,951 19,114
Share-based compensation 837 368
26,715 19,595
Valuation allowance (26,715) (19,595)
Net deferred income tax assets $ - $ -
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 Gambia and Kenya are included in the respective subsidiaries cost oil accounts, which will be
offset against future taxable revenues. Management assesses the available positive and negative evidence to estimate if
existing deferred tax assets will be utilized. The Company does not expect to utilize the net operating losses in the short term,
due to continued operating losses in its foreign subsidiaries. On the basis of this evaluation, valuation allowances of $26.7
million and $19.6 million were recorded as of December 31, 2013 and 2012, respectively.
At December 31, 2013, the Company was subject to foreign and United States federal taxes only, with no allocations made to
state and local taxes.
The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:
United States: 2007-2013
Nigeria: 2010-2013
Kenya: 2012-2013
Gambia: 2012-2013
NOTE 9. --- 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 100,000,000 shares of Common Stock. Options awarded
expire between five and 10 years from date of grant, or shorter term as fixed by the Board of Directors. On February 18,
2014, the Company executed the amendment to the 2009 Plan thereby increasing the number of shares that may be granted
thereunder to 100,000,000.
In 2013, the Company granted a total of 8,003,874 stock options with vesting periods from three years to five years.
Stock Options
A summary of stock option activity for the year ended December 31, 2013, is presented below.
Shares Weighted- Weighted-
Underlying Average Average
Options Exercise Price Remaining
Contractual
Term
(Years)
Stock Options
Outstanding at January 1, 2013 6,124,703 $0.37 3.5
Granted 8,003,874 $0.28 4.3
Exercised -
Forfeited (353,046) $0.69
Outstanding as of December 31, 2013 13,775,531 $0.31 3.7
Expected to vest 13,775,531 $0.31 3.7
Exercisable at December 31, 2013 3,376,648 $0.37 2.7
The total intrinsic values of options outstanding and options exercisable were $0.9 million at December 31, 2013. The total
intrinsic values realized by recipients on options exercised were $0 in 2013, $0 in 2012, and $0.2 million in 2011.
The Company recorded compensation expense relative to stock options in 2013, 2012 and 2011 of $1.1 million , $0.2 million
and $1.3 million, respectively.
The fair values of stock options used in recording compensation expense are computed using the Black-Scholes option
pricing model. The table below shows the weighted-average amounts for the assumptions used in the model for options
awarded in each year under equity incentive plans.
2013 2012 2011
Expected price volatility 77.9% 120.5% 103.7%
Risk free interest rate (U.S. treasury bonds) 0.5% 0.5% 0.8%
Expected annual dividend yield - - -
Expected option term (years) 3.5 3.5 3.1
Grant date fair value per share $ 0.23 $ 0.26 $ 0.34
Restricted Stock Awards (“RSA”)
In addition to stock options, our 2009 Plan allows for the grant of restricted stock awards, or RSA. We determine the fair
value of RSAs based on the market price of our common stock on the date of grant. Compensation cost for RSAs is
recognized on a straight-line basis over the vesting or service period and is net of forfeitures.
A summary of restricted stock activity for the year ended December 31, 2013, is presented below.
Weighted-
Average
Grant Date Fair
Shares Value
Restricted Stock
Nonvested at January 1, 2013 2,676,724 $0.32
Granted 4,163,374 $0.26
Vested (2,301,312) $0.32
Forfeited -
Nonvested as of December 31, 2013 4,538,786 $0.27
The Company recorded compensation expense relative to RSA’s in 2013, 2012 and 2011 of $0.9 million, $0.6 million and
$1.2 million, respectively.
The total grant date fair value of RSA shares that vested during 2013 was approximately $0.5 million. As of December 31,
2013, there was approximately $1.2 million of total unrecognized compensation cost related to nonvested RSAs, with $0.9
million, and $0.3 million to be recognized during the years ended December 31, 2014 and 2015, respectively.
NOTE 10. --- EARNINGS OR LOSS PER COMMON SHARE
Basic earnings or loss per common share (“EPS”) is computed by dividing net income or loss available to common
stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number
of common shares outstanding for basic and diluted EPS for years ended December 31, 2013, 2012, and 2011, respectively,
were as follows:
Years ended December 31,
2013 2012 2011
(In thousands)
Basic 381,255 379,373 376,312
Diluted 381,255 379,373 376,312
The number of stock options, warrants issued in stock offerings and nonvested restricted stock excluded from dilutive shares
outstanding in the above periods, as these potentially dilutive securities are anti-dilutive because the Company was in a loss
position, were as follows:
Years ended December 31,
2013 2012 2011
(In thousands)
Stock options - 4 238
Warrants issued in stock offerings - - 14
Nonvested restricted stock awards 2,154 796 158
2,154 800 410
NOTE 11. --- FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK
Fair Value of Financial Instruments
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently
between willing parties. The carrying amounts of the Company’s financial instruments, which include cash and cash
equivalents, trade receivables, deposits, accounts payable, accrued expenses, other long-term liabilities and debt at floating
interest rates approximate their fair values at December 31, 2013 and 2012, respectively, principally due to the short-term
nature, maturities or nature of interest rates of the above listed items.
Concentration of Credit Risk
The Company is currently not exposed to any concentration of credit risk.
NOTE 12. --- COMMITMENTS AND CONTINGENCIES
Commitments
We rent office space and miscellaneous office equipment under non-cancelable operating leases. Office rent expense, net of
sublease income, for the years ended December 31, 2013, 2012, and 2011 was $0.7 million, $0.5 million and $0.5 million,
respectively. At December 31, 2013, minimum future rental commitments for operating leases were a total of $2.2 million as
follows: $0.4 million in 2014, $0.4 million in 2015, $0.4 million in 2016, $0.4 million in 2017 and $0.6 in 2018 and
thereafter.
The Company has substantial commitments related to its Kenya PSCs and The Gambia Licenses. To maintain compliance
and ownership, the Company is and will be required to fulfill minimum work obligations and to make certain payments as
stated in each PSC and License. At December 31, 2013, minimum future work obligations were a total of $148.4 million as
follows: $14.8 million in 2014 and $133.6 million in the years 2015 and 2016.
Contingencies
From time to time we may be involved in various legal proceedings and claims in the ordinary course of our business. As of
December 31, 2013, and through the filing date of this report, we do not believe the ultimate resolution of such actions or
potential actions of which we are currently aware will have a material effect on our consolidated financial position or our net
income or loss.
NOTE 13. --- RELATED PARTY TRANSACTIONS
The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates. The
following tables summarize related party transactions and balances for the respective period:
December 31, December 31,
2013 2012
(In thousands)
CEHL, accounts receivable $ 1,026 $ 6,103
CEHL, other current assets $ 624 $ 624
CEHL, accounts payable $ 292 $ 10,213
CEHL, note payable-related party $ 6,496 $ -
CEHL, accrued expenses $ 804 $ 25
CEHL, long-term note payable-related party $ - $ 872
Year Ended December 31,
2013 2012 2011
(In thousands)
CEHL, total operating costs and expenses $ (1,167) $ 81 $ 3,243
CEHL, other expense, net $ 99 $ 122 $ 120
The Company entered into a technical services agreement with Allied effective September 1, 2012, whereby the Company
agreed to provide services related to the Oyo Field in Nigeria. Pursuant to the terms of the Technical Service Agreement,
Allied agreed to pay the Company $150.0 thousand per month. The amounts earned under the agreement are recorded as a
reduction to lease operating expenses and production costs and general and administrative expenses.
In June 2011, CPL, a wholly owned subsidiary of the Company, executed a Promissory Note in favor of Allied. See Note 7 -
Note Payable – Related Party, for details relating to the Promissory Note. As of December 31, 2013, $6.5 million was
outstanding under the Promissory Note.
NOTE 14. — SELECTED UNAUDITED QUARTERLY FINANCIAL DATA
Three Months Ended
September December
March 31, June 30, 30, 31,
2013 2013 2013 2013
(In thousands, except per share data)
Total revenues $ 2,452 $ 1,941 $ 3,480 $ -
Operating loss $ (3,774) $ (4,425) $ (2,680) $ (5,071)
Net loss attributable to CAMAC Energy Inc. $ (3,778) $ (4,431) $ (2,696) $ (5,043)
Net loss per share
Basic $ (0.01) $ (0.01) $ (0.01) $ (0.01)
Diluted $ (0.01) $ (0.01) $ (0.01) $ (0.01)
Three Months Ended
September December
March 31, June 30, 30, 31,
2012 2012 2012 2012
(In thousands, except per share data)
Total revenues $ 5,672 $ - $ 7,945 $ 3,007
Operating loss $ (879) $ (3,496) $ (1,944) $ (2,367)
Net (loss) income attributable to CAMAC Energy Inc. (1) $ (1,296) $ (3,975) $ 2,038 $ (2,858)
Net (loss) income income per share
Basic $ (0.00) $ (0.01) $ 0.01 $ (0.01)
Diluted $ (0.00) $ (0.01) $ 0.01 $ (0.01)
(1) In 2012, The Company divested its China operations. See Note 3 – Discontinued Operations for details of the sale.
NOTE 15. — SUBSEQUENT EVENTS
In November 2013, the Company entered into a Transfer Agreement (the “Transfer Agreement”) pursuant to which the
Company agreed to acquire from Allied Energy Plc (“Allied”), a wholly owned subsidiary of CEHL (the 57.2% majority
stockholder of the Company), all remaining economic interests in the PSC and related assets, contracts and rights pertaining
to OMLs 120 and 121 including the currently producing Oyo Field (the “Allied Assets”). In consideration for the Allied
Assets, the Company agreed to issue 497,454,857 shares of the Company’s Common Stock, deliver to Allied a $50.0 million
convertible subordinated promissory note (the “Convertible Subordinated Note”) and pay $170.0 million in cash (the “Allied
Transaction”).
To fund the cash portion of the Allied Transaction and a portion of the anticipated capital expenditures for development of
the Oyo Field, the Company also entered into a Share Purchase Agreement (the “Share Purchase Agreement”) with the
Public Investment Corporation (SOC) Limited, a state-owned company registered and duly incorporated in the Republic of
South Africa ("PIC"), for an aggregate cash investment of $270.0 million through a private placement of 376,884,422 shares
of Common Stock (the “Private Placement”), representing an approximate 30% ownership interest in the Company after
completion of the transactions. The Share Purchase Agreement provides that the Private Placement will be completed in two
installments. The first installment of $135.0 million (the “First Closing”) in exchange for 188,442,211 shares of the
Company’s Common Stock was due at the closing of the Allied Transaction. The second installment (the “Second Closing”)
of $135.0 million in exchange for 188,442,211 shares of the Company’s Common Stock is expected in mid 2014. In
connection with the Private Placement, the Company agreed to list its Common Stock on the Johannesburg Stock Exchange
("JSE") in addition to the Company’s listing on the NYSE MKT.
On February 13, 2014, the Company held a special meeting of its stockholders to consider and vote upon the proposal to
approve the Transfer Agreement as mentioned above and other related agenda items. Additionally, the Company had
previously declared the Stock Dividend, which was subject to shareholder approval of the proposals presented at the above
special meeting. All of the proposals presented at the meeting were approved by the requisite majority of the minority
shareholders of the Company. The Stock Dividend was paid on February 21, 2014 to all shareholders of record at the close of
business on February 13, 2014.
On February 21, 2014, the Company completed the Allied Transaction and the First Closing of the Private Placement in
accordance with the terms of the Transfer Agreement and the Share Purchase Agreement, respectively. Pursuant to the terms
of the Transfer Agreement, the Company, as partial consideration for the Allied Assets, paid $85.0 million in cash to Allied,
issued 497,454,857 shares of the Company’s Common Stock to Allied and delivered the Convertible Subordinated Note to
Allied under which $25.0 million was deemed to be advanced. The Company’s Common Stock also began trading on the JSE
on February 24, 2014. Within two business days following the Second Closing of the Private Placement, the Company will
be required to pay to Allied an additional $85.0 million in cash, as may be adjusted pursuant to the Transfer Agreement, and
an additional $25.0 million will be deemed to be advanced to Allied under the Convertible Subordinated Note. The Second
Closing of the Private Placement is expected to take place in the second quarter of 2014.
CAMAC ENERGY INC.
SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)
The unaudited supplemental information on oil and gas exploration and production activities for 2013, 2012 and 2011 has
been presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 932,
Extractive Activities—Oil and Gas. Disclosures by geographic area include Africa and the United States.
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”) has prepared evaluations on 100 percent of our right to proved
reserves and the estimates of proved crude oil reserves attributable to our net interests in oil and gas properties as of
December 31, 2013. Reserve volumes and values were determined under the method prescribed by the SEC, which requires
the application of the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month
price for each month within the 12-month prior period to the end of the reporting period and current costs held constant
throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more
imprecise than those of producing properties. Accordingly, reserve estimates are expected to change as additional
performance data becomes available.
Crude Oil
(MBbls)
International
January 1, 2011 5,288
Revisions (2,288)
Production (337)
December 31, 2011 2,663
Revisions 583
Production (148)
December 31, 2012 3,098
Revisions (544)
Production (73)
December 31, 2013 2,481
Developed reserves
December 31, 2011 92
December 31, 2012 55
December 31, 2013 92
Undeveloped reserves
December 31, 2011 2,571
December 31, 2012 3,043
December 31, 2013 2,389
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.
As of December 31,
2013 2012
International (In thousands)
Proved properties $ 206,212 $ 206,212
Unproved properties 8,240 8,240
Total capitalized costs 214,452 214,452
Accumulated depreciation, depletion and amortization (30,044) (25,822)
Net capitalized costs $ 244,496 $ 240,274
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.
Years Ended December 31,
2013 2012 2011
International (In thousands)
Unproved property acquisition $ - $ 3,240 $ 5,000
Exploration 5,501 3,236 890
Total costs incurred $ 5,501 $ 6,476 $ 5,890
Results of Continuing Operations
Results of continuing operations for producing activities consist of all activities within the oil and gas exploration and
production operations.
Years Ended December 31,
2013 2012 2011
International (In thousands)
Revenues $ 7,873 $ 16,624 $ 37,922
Production, G&A and other costs 694 (326) (30,882)
Exploratory expenses (267) (3,236) (890)
Depreciation, depletion and amortization (4,238) (10,595) (13,316)
Results from oil and gas producing activities $ 4,062 $ 2,467 $ (7,166)
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, 2013) without giving effect to non-property related expenses such as DD&A expense and discounted at
10% per year. The average first-day-of-the-month commodity prices during the 12-month periods ending on December 31,
2013, 2012, and 2011, were $107.89, $112.77, and $112.26 per barrel of crude oil, respectively, including differentials.
Amounts below for production sold and production costs exclude royalties.
Years Ended December 31,
2013 2012 2011
International (In thousands)
Future cash inflows from production sold $ 267,653 $ 349,345 $ 298,936
Future production costs (142,712) (180,612) (140,104)
Future development costs (86,239) (58,800) (62,308)
Future income taxes (9,280) (19,886) (16,212)
Future net cash flows before discount 29,422 90,047 80,312
Discount at 10% annual rate (6,733) (24,335) (18,625)
Standardized measure of discounted future cash flows $ 22,689 $ 65,712 $ 61,687
Change in Standardized Measure of Discounted Future Net Cash Flows
Years Ended December 31,
2013 2012 2011
(In thousands)
BALANCE AT BEGINNING OF PERIOD $ 65,712 $ 61,687 $ 95,696
Sales of oil and gas, net of production costs (8,539) (16,357) (35,617)
Net changes in prices and production costs 26,580 (40,435) 136,097
Revisions of previous quantity estimates (49,163) 47,662 (139,203)
Additions - - -
Changes in estimated future development costs (16,881) 8,433 (9,989)
Development costs incurred during the period - - -
Accretion of discount 6,571 5,717 10,417
Net change of income taxes 10,606 (995) 4,286
Change in production rates (timing) and other (12,196) - -
BALANCE AT END OF PERIOD $ 22,689 $ 65,712 $ 61,687
S-3
17 March 2014
Johannesburg
Sponsor
Sasfin Capital (a division of Sasfin Bank Limitd)
Date: 17/03/2014 09:13:00 Produced by the JSE SENS Department. The SENS service is an information dissemination service administered by the JSE Limited ('JSE').
The JSE does not, whether expressly, tacitly or implicitly, represent, warrant or in any way guarantee the truth, accuracy or completeness of
the information published on SENS. The JSE, their officers, employees and agents accept no liability for (or in respect of) any direct,
indirect, incidental or consequential loss or damage of any kind or nature, howsoever arising, from the use of SENS or the use of, or reliance on,
information disseminated through SENS.
Sharenet Sites 
