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CAK > SEC Filings for CAK > Form 10-K on 15-Apr-2013All Recent SEC Filings

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Form 10-K for CAMAC ENERGY INC.


15-Apr-2013

Annual Report


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

Our Business

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

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

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

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

Nigeria - Oyo Field Production Sharing Contract Interest

In December 2009, Nigerian Agip Exploration Limited ("NAE"), a subsidiary of Italy's ENI SpA, and CAMAC Energy Holdings Limited ("CEHL") announced that they had commenced production of the Oyo Field, offshore Nigeria. The Oyo Field has been producing from two subsea wells in a water depth of greater than 300 meters, which are connected to the Armada Perdana Floating Production Storage and Offloading ("FPSO") vessel. The FPSO has a treatment capacity of 40,000 barrels of liquids per day, with gas treatment and re-injection facilities, and is capable of storing up to one million barrels of crude oil. The first lifting
(sale) of crude oil was in February 2010. Some of the associated gas has been re-injected into the Oyo Field reservoir by a third well, to minimize flaring and to maximize oil recovery.

Through December 31, 2012, the Company incurred a total of $59.7 million in costs relative to the workover to reduce gas production rising from well #5 in the Oyo Field, offshore Nigeria, with the objective of increasing crude oil production from this well. By joint agreement with Allied Energy Plc. ("Allied"), a related party, the Company has committed to pay for the workover. To the extent the Company funds these costs, it is entitled to cost recovery of such costs as non-capital costs from Cost Oil, as defined in the terms of the OML 120/121 Production Sharing Contract ("OML 120/121 PSC"), subject to future production levels. For purposes of Cost Oil recovery on each sale of production, non-capital costs are allocated for recovery prior to capital costs. As of December 31, 2012, $40.4 million of these costs have been recovered as revenue and we expect to recover the remainder as revenue in future liftings. In connection with funding for part of these costs prior to receiving cost recovery, the Company entered into a Promissory Note and Guaranty Agreement with a related party, which is discussed below under "Promissory Note and Guaranty Agreement." The remainder is being funded using available cash and the future Oyo Field lifting proceeds.


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

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

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

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

Nigeria - OML 120/121 Transaction

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

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

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

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

Promissory Note and Guaranty Agreement

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

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


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Kenya

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

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

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

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

The Gambia

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

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

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

Plan of Operation

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

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


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

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

Among the general strategies we use are:

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

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

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

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

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

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

With respect to specific geographical areas our strategies include:

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

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

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

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

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

Results of Operations - Continuing Operations

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

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

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

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


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

Africa Operations

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

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

Through December 31, 2012, the Company incurred a total of $59.7 million in costs relative to the workover to reduce gas production rising from well #5 in the Oyo Field, offshore Nigeria, with the objective of increasing crude oil production from this well. By joint agreement with Allied, a related party, the Company has committed to pay for the workover. To the extent the Company funds these costs, it is entitled to cost recovery of such costs as non-capital costs from Cost Oil, as defined in the terms of the OML 120/121 PSC, subject to future production levels. For purposes of Cost Oil recovery on each sale of production, non-capital costs are allocated for recovery prior to capital costs. As of December 31, 2012, $40.4 million of these costs have been recovered as revenue and we expect to recover the remainder as revenue in future liftings. In connection with funding for part of these costs prior to receiving cost recovery, the Company entered into a Promissory Note and Guaranty Agreement with a related party, which is discussed under "Promissory Note and Guaranty Agreement" within Part I, Item 1 of this document. The remainder is being funded using available cash and the future Oyo Field lifting proceeds.

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

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


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

Consolidated Statements of Operations

Comparison of 2012 and 2011

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

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

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

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

General and administrative expenses consist primarily of salaries and related personnel costs of executive management, finance, accounting, legal and human resources, accounting and legal services, consulting projects and insurance. Our general and administrative expenses in 2012 were $10,998,000 as compared to . . .

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