Wrap Text
Recast historical financials following Dec 2013 year end in terms of Section13 or 15(d) of the SEC 1934
CAMAC Energy Incorporated
(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 Energy” or “the Company”)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): December 19, 2014
CAMAC Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware 001-34525 30-0349798
(State or other jurisdiction (Commission (I.R.S. Employer Identification No.)
of incorporation) File Number)
1330 Post Oak Blvd., Suite 2250, Houston, Texas 77056
(Address of principal executive offices) (Zip Code)
(713) 797-2940
(Registrant’s telephone number, including area code)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant
under any of the following provisions:
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Item 8.01 Other Events
In February 2014, CAMAC Energy Inc. (the “Company”) completed the acquisition of the remaining economic interests that it did not
already own in the Production Sharing Contract covering Oil Mining Leases 120 and 121 located offshore Nigeria, which includes the
currently producing Oyo Field, and related assets, contracts and rights (the “Allied Assets”) from Allied Energy Plc (“Allied”) (the
“Allied Transaction”). Allied is a subsidiary of CAMAC Energy Holdings Limited (“CEHL”), the Company’s majority shareholder,
and deemed to be under common control (transactions between subsidiaries of the same parent). Accordingly, the historical
consolidated financial statements of the Company have been recast for all periods, and are presented as though the Allied Transaction
had occurred in June 2012, the date Allied acquired the Allied Assets from an independent third party.
The Company is filing this Current Report on Form 8-K to reflect the effect of the consummation of the Allied Transaction on the
historical annual financial and related information included in the Company’s Annual Report on Form 10-K for the fiscal year ended
December 31, 2013 (the “2013 Form 10-K”). The following items from the 2013 Form 10-K have been recast to reflect the effects of
treating the Acquisition as a combination of businesses under common control:
- Part II, Item 6 - Selected Financial Data;
- Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations; and
- Part II, Item 8 - Financial Statements and Supplemental Data.
Other than the items listed above, the Company is not otherwise updating any other portion of the 2013 Form 10-K previously filed.
This Current Report on Form 8-K does not include Items from the 2013 Form 10-K that are not affected by the accounting treatment
of the Allied Transaction. This Current Report on Form 8-K should be read in conjunction with the 2013 Form 10-K (except for Items
listed above) and the Company's other filings with the SEC, including the Company’s Quarterly Report on Form 10-Q/A for the
quarter ended March 31, 2014, as filed with the SEC on July 8, 2014, the Company’s quarterly report on form 10-Q for the quarter
ended June 30, 2014, as filed with the SEC on August 11, 2014, and the Company’s quarterly report on form 10-Q for the quarter
ended September 30, 2014, as filed with the SEC on November 10, 2014.
The recast financial information contained in the Items noted above is presented in Exhibit 99.1 to this Current Report on Form 8-K.
The Company is also presenting such financial information in XBRL format, as attached as Exhibit 101 to this Current Report on
Form 8-K.
The consent of the Company’s current independent public accounting firm for the years ended 2013 and 2012, Grant Thornton LLP,
and the Company’s previous independent public accounting firm for the year ended 2011, RBSM LLP, to the inclusion of their audit
reports in Exhibit 99.1 to this Current Report on Form 8-K, are attached hereto as Exhibit 23.1 and 23.2, respectively.
Item 9.01 Financial Statements and Exhibits
(d) Exhibits
Exhibit Descriptions
23.1 Consent of Grant Thornton LLP.
23.2 Consent of RBSM LLP.
23.3 Consent of DeGolyer and MacNaughton.
99.1 Revisions to 2013 Form 10-K and Consolidated Financial Statements as of and for the years ended December 31, 2013 and
2012 (revised solely to reflect the transactions described in this Current Report on Form 8-K).
99.2 Report of DeGolyer and MacNaughton.
101 Consolidated Financial Statements from the 2013 Form 10-K, formatted in XBRL: (i) Consolidated Balance Sheets; (ii)
Consolidated Statements of Operations; (iii) Consolidated Statements of and Comprehensive Income (Loss); (iv) the
Consolidated Statements of Equity; (v) Consolidated Statements of Cash Flows; and (v) Notes to the Consolidated
Financial Statements furnished herewith (revised to reflect the transactions described in this Current Report on Form 8-K).
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned hereunto duly authorized.
Dated: December 19, 2014 CAMAC Energy Inc.
/s/ Earl W. McNiel
Earl W. McNiel
Senior Vice President and
Chief Financial Officer
INDEX TO EXHIBITS
Exhibit Descriptions
23.1 Consent of Grant Thornton LLP.
23.2 Consent of RBSM LLP.
23.3 Consent of DeGolyer and MacNaughton.
99.1 Revisions to 2013 Form 10-K and Consolidated Financial Statements as of and for the years ended December 31, 2013 and
2012 (revised solely to reflect the transactions described in this Current Report on Form 8-K).
99.2 Report of DeGolyer and MacNaughton.
101 Consolidated Financial Statements from the 2013 Form 10-K, formatted in XBRL: (i) Consolidated Balance Sheets; (ii)
Consolidated Statements of Operations; (iii) Consolidated Statements of and Comprehensive Income (Loss); (iv)
Consolidated Statements of Equity; (v) Consolidated Statements of Cash Flows; and (v) Notes to the Consolidated
Financial Statements furnished herewith (revised to reflect the transactions described in this Current Report on Form 8-K).
INDEX TO EXHIBIT 99.1
Item 6. Selected Financial Data ................................................................................................. 1
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ........................................... 1
Item 8. Financial Statements and Supplemental Data ................................................................................................................... 8
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued our report dated December 19, 2014, with respect to the consolidated financial statements of CAMAC Energy Inc. as
of December 31, 2013 and 2012, and for each of the two years in the period ended December 31, 2013 included in this current report
on Form 8-K. We hereby consent to the incorporation by reference of said report in the Registration Statements of CAMAC Energy
Inc. on Form S-3 (File No. 333-163869 and 333-167013) and on Forms S-8 (File No. 333-175294, 333-160737, 333-152061 and 333-
194503).
/s/ GRANT THORNTON LLP
Houston, Texas
December 19, 2014
Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To: CAMAC Energy Inc.
We consent to the incorporation by reference in the Registration Statements No. 333-163869 and 333-167013 on Form S-3 and
Registration Statements No. 333-152061, 333-160737, 333-175294 and 333-194503 on Form S-8 of CAMAC Energy Inc. of our
report dated March 15, 2012, except for paragraph 4 of Note 2, as to which the date is March 14, 2014 with respect to the December
31, 2011 consolidated financial statements, which appears in this Current Report on Form 8-K.
/s/ RBSM LLP
New York, New York
December 19, 2014
Exhibit 23.3
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
December 19, 2014
Camac Energy Inc.
1330 Post Oak Boulevard
Suite 2550
Houston, Texas 77056
Ladies and Gentlemen:
We hereby consent to the incorporation by reference into the Registration Statements on Form S-3 (File Nos. 333-163869
and 333-167013) and Form S-8 (File Nos. 333-152061, 333-160737, 333-175294 and 333-194503) of CAMAC Energy Inc. (the
“Company”) of (a) the references to DeGolyer and MacNaughton contained in “Item 8. Financial Statements and Supplemental Data”
in “Exhibit 99.1” of the Company’s Current Report on Form 8-K filed December 19, 2014 and (b) our third-party letter report dated
December 5, 2014, containing our opinion on the proved reserves as of January 1, 2014, attributable to the interest owned by
the Company in the Oyo field offshore Nigeria, which such report is included as “Exhibit 99.2” in the Company’s Current Report on
Form 8-K filed December 19, 2014.
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
Exhibit 99.1
ITEM 6. SELECTED FINANCIAL DATA
Years Ended December 31,
(In thousands) 2013 2012 2011 2010 2009
Statement of Income Data
Revenues $ 63,736 $ 74,667 $ 37,922 $ 20,229 $ 67
Net loss attributable to CAMAC Energy Inc. $ (43,525 ) $ (29,529 ) $ (24,913 ) $ (230,468 ) $ (11,489 )
Net loss per common share attributable to CAMAC
Energy Inc.:
Basic $ (0.05 ) $ (0.05 ) $ (0.07 ) $ (0.80 ) $ (0.11 )
Diluted $ (0.05 ) $ (0.05 ) $ (0.07 ) $ (0.80 ) $ (0.11 )
Cash Flow Data
Net cash (used in) provided by operating activities $ (36,625 ) $ 9,434 $ (14,654 ) $ 8,572 $ (6,872 )
As of December 31,
(In thousands) 2013 2012 2011 2010 2009
Balance Sheet Data
Working capital $ (39,704 ) $ (4,610 ) $ (5,380 ) $ 1,650 $ 3,910
Property plant and equipment, net $ 435,787 $ 363,724 $ 196,222 $ 204,979 $ 451
Total assets $ 454,224 $ 377,043 $ 230,870 $ 247,843 $ 7,436
Note payable - related party $ 6,496 $ 872 $ 6,000 $ - $ -
The above presented earnings per share amounts reflect the effect of the Stock Dividend paid in February 2014.
For more information on results of operations and financial condition, see Item 7. – Management’s Discussion and Analysis of
Financial Condition and Results of Operations.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion of the Company’s historical performance and financial condition should be read together with Part II, Item
6, “Selected Financial Data” and the consolidated financial statements and related notes in Part II, Item 8 of this Report and in
conjunction with the 2013 Form 10-K filed March 14, 2014. This discussion contains forward-looking statements based on the views
and beliefs of our management, as well as assumptions and estimates made by our management. These statements by their nature are
subject to risks and uncertainties, and are influenced by various factors. As a consequence, actual results may differ materially from
those in the forward-looking statements. See Item 1A of our 2013 Form 10-K for the discussion of risk factors.
The terms “we,” “us,” “our,” “Company,” and “our Company” refer to CAMAC Energy Inc. and its subsidiaries and affiliates.
The Company’s operating subsidiaries include CAMAC Energy Ltd., CAMAC Petroleum Limited, CAMAC Energy International
Ltd., CAMAC Energy Ghana Limited, CAMAC Energy Kenya Limited, CAMAC Energy Gambia A2 Ltd. and CAMAC Energy
Gambia A5 Ltd. The Company also conducts certain business transactions with its majority shareholder, CAMAC Energy Holdings
Limited (“CEHL”), and its affiliates, which include Allied Energy Plc (“Allied”). See “Note 15 – Related Party Transactions” of the
Notes to Consolidated Financial Statements for details of these transactions.
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 nine licenses across four countries covering an area of approximately 43,000 square
kilometers (approximately 10 million acres). The Company owns producing properties and conducts exploration activities in Nigeria,
conducts explorations activities as an operator onshore and offshore Kenya, and conducts exploration activities as an operator offshore
The Gambia.
In August 2012, the Company divested its wholly owned Hong Kong subsidiary Pacific Asia Petroleum Limited for net cash
consideration of $2.4 million and 9.6 million fully paid ordinary shares, net of selling expenses, of Leyshon Resources Limited, a
natural resources mining company based in Beijing, China. The Leyshon shares had a fair market value of $1.9 million, and have
since been sold. As a result of the transaction, the Company is reporting its China operations, including other inactive operations not
involved in this sale, for all presented periods in discontinued operations.
From September 2013 to November 2013, the first phase of drilling operations was conducted on the Oyo-7 well. Based on logging-
while-drilling (“LWD”) data, the well encountered gross oil pay of 133 feet (net oil pay of 115 feet) and gross gas pay of 103 feet (net
gas pay of 93 feet) in the gas cap from the currently producing Pliocene reservoir, with excellent reservoir quality. As a secondary
objective, the Oyo-7 well confirmed the presence of hydrocarbons in the deeper Miocene formation. This marked the first time a well
had been successfully drilled into the Miocene formation on OML 120. Hydrocarbons were encountered in three intervals totaling
approximately 65 feet, as interpreted from the LWD data.
During 2013, the Company completed shooting airborne gravity and magnetic geophysical surveys on its Kenya onshore Lamu Basin
blocks L1B and L16. The data acquisition covers essentially the entire 12,129 square kilometers in block L1B and the entire 3,613
square kilometers in block L16 and satisfies the gravity and magnetic survey requirements for each block under the relevant PSC. The
Company has signed agreements for both blocks for the acquisition, processing, and interpretation of 2D seismic data.
In February 2014, the Company completed the acquisition of the remaining economic interests that it did not already own in the
Production Sharing Contract (“PSC”) covering Oil Mining Leases 120 and 121 (“OMLs 120 and 121” or “OMLs”) located offshore
Nigeria, which include the currently producing Oyo Field (the “Allied Assets”), from Allied (the “Allied Transaction”). Pursuant to
the terms of the Transfer Agreement, the Company, as partial consideration for the Allied Assets, paid $85.0 million in cash to Allied,
issued 497,454,857 shares of the Company’s common stock to Allied and delivered a $50.0 million Convertible Subordinated Note
(the “Convertible Subordinated Note”) to Allied under which $25.0 million was deemed to be advanced.
RESULTS OF OPERATIONS – CONTINUING OPERATIONS
Oil Revenues
Revenue is recognized when a lifting (sale) occurs. Crude oil revenues for 2013 were $63.7 million, as compared to revenues of $74.7
million and $37.9 million for 2012 and 2011, respectively. In 2013, the Company sold approximately 591,000 net barrels of oil at an
average price of $107.84/Bbl. In 2012, the Company sold approximately 683,000 net barrels of oil at an average price of $109.32/Bbl.
In 2011, the Company sold approximately 337,000 net barrels of oil at an average price of $112.91/Bbl. The decrease in revenues in
2013 compared to 2012 was primarily due to the natural decline in production, leading to lower sales volumes. In addition, a lifting
did not occur during the fourth quarter of 2013 as compared to 2012. The increase in revenues in 2012 compared to 2011 was
primarily due to additional revenues recorded from the acquired Allied Assets.
During 2013, 2012 and 2011, the net daily production from the Oyo Field was approximately 2,000 barrels of oil per day (“BOPD”),
2,400 BOPD and 3,300 BOPD, respectively.
Operating Costs and Expenses
Production costs were $70.4 million for 2013, as compared to $41.6 million in 2012 and $30.9 million for 2011. Production costs
include costs directly related to the production of hydrocarbons. Such costs are capitalized as a component of crude oil inventory and
are reflected in operating costs and expenses when inventory is sold. Production costs were higher in 2013 as compared to 2012,
primarily due to 2013 including twelve months of costs for the acquired Allied Assets, as compared to only six months of costs
recorded in 2012 for the same assets. The 2011 production costs include $30.8 million spent for the Oyo-5 well workover.
Exploration expenses were $5.5 million for 2013, as compared to $3.2 million in 2012 and $0.9 million in 2011. Exploration expenses
consist of personnel costs, drilling costs for unsuccessful wells, costs for acquiring seismic data and other related costs as required. In
2013, the Company incurred $5.5 million of exploration expenses, including $2.1 million spent at the corporate level for exploration
activities, $2.5 million related to Kenya, $0.6 million related to Gambia, and $0.3 million related to Nigeria. In 2012, the Company
incurred $3.2 million of exploration expenses, including $1.5 million spent at the corporate level for exploration activities, $1.0
million related to Kenya, $0.5 million related to Gambia, and $0.2 million related to Nigeria. In 2011, the Company incurred $0.7
million at the corporate level and $0.2 million in Nigeria for exploration activities.
Depreciation, depletion and amortization (“DD&A”) expenses for 2013, including accretion, were $16.9 million, as compared to $51.0
million in 2012 and $13.5 million in 2011. The 2013 DD&A expenses decreased as compared to 2012 primarily due to both lower
sales volumes and lower depletion rates as a result of the 2012 positive reserve revision. The 2012 DD&A expenses increased as
compared to 2011 primarily due to higher sales volumes with regards to the Allied Assets and increased depletion rates. The average
depletion rates for 2013, 2012 and 2011, were $28.60/Bbl, $74.70/Bbl and $40.00/Bbl, respectively.
General and administrative expenses for 2013 were $14.5 million, as compared to $11.0 million and $13.3 million for 2012 and 2011,
respectively. The increase in general and administrative expenses for 2013 as compared to 2012 was primarily due to higher
consulting and legal costs associated with the Allied Transaction. The decrease in general and administrative expenses for 2012 as
compared to 2011 was primarily due to lower administrative expenses associated with staffing reductions. The Company incurred
non-cash based stock compensation expenses of $2.0 million, $0.7 million, and $2.5 million for the years 2013, 2012, and 2011,
respectively.
Other Income (Expense)
Other income was $38,000 in 2013, as compared to other expense of $0.6 million and $0.3 million in 2012 and 2011, respectivel y. In
2013, the Company recognized realized foreign currency gains of $0.3 million, partially offset by $0.2 million in interest expense
associated with the Promissory Note with Allied (the “Promissory Note”). In 2012, the Company recognized realized losses of $0.5
million on sale of securities and incurred $0.1 million in interest expenses associated with the Promissory Note. In 2011, the Company
incurred other expense of $0.3 million, which included $0.1 million in interest expense and $0.2 million in other adjustments.
Income Taxes
Income taxes were nil for the year 2013, 2012, and 2011. The Company did not have any taxable income in the years 2013, 2012 and
2011, and was therefore not subject to Petroleum Profit Taxes.
Losses From Continuing Operations
Losses from continuing operations were $43.5 million in 2013, as compared to losses of $32.7 million and $21.0 million for 2012 and
2011, respectively. In 2013, losses from continuing operations increased by $10.8 million as compared to 2012, primarily as the result
of lower sales volumes. In 2012, losses from continuing operations increased by $11.7 million as compared to 2011 primarily as the
result of higher depletion expense, partially offset by the additional revenues recorded from the acquired Allied Assets.
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 separately identifiable remeasurements based on the criteria outlined in circular 3/2009
and headline earnings was the same as net loss per share from continuing operations as disclosed on the audited consolidated
statements of operations. Therefore, HEPS for the years ended 2013, 2012 and 2011 were $(0.05), $(0.05) and $(0.07), respectively.
RESULTS OF OPERATIONS – DISCONTINUED OPERATIONS
Discontinued operations include the results of operations of the Company’s China business, which was divested in 2012. In 2012, the
Company recognized a gain of $4.2 million, net of selling expenses, associated with the sale. For details of the sale and results of
operations, see “Note 3 – Discontinued Operations” within the Notes To Consolidated Financial Statements of this Report.
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 $39.7 million.
Years Ended December 31,
(In thousands) 2013 2012 2011
Net cash (used in) provided by operating activities $ (36,625) $ 9,434 $ (14,654)
Net cash (used in) provided by investing activities $ (602) $ 1,219 $ (6,860)
Net cash provided by (used in) financing activities $ 33,584 $ (20,456) $ 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 $36.6 million for 2013 as compared to net cash provided by operating activities of $9.4
million for 2012 and net cash used in operating activities of $14.7 million in 2011. The change in net cash flows from operating
activities of $46.1 million in 2013 as compared to 2012 was primarily due to both higher production costs and lower revenues in 2013.
Production costs increased in 2013 as compare to 2012 because 2013 includes twelve months of costs for the acquired Allied Assets,
as compared to only six months of costs recorded in 2012 for the same assets. Revenues decreased in 2013 as compared to 2012
because of the natural decline in production, leading to lower sales volumes. The increase in net cash provided by operating activities
of $24.1 million in 2012 as compared to 2011 was primarily due to additional revenues in 2012 recorded from the acquired Allied
Assets.
Net cash used in investing activities for 2013 was $0.6 million, compared to net cash provided by investing activities of $1.2 million
in 2012, and net cash used in investing activities of $6.9 million in 2011. Net cash used in investing activities of $0.6 million in 2013
consisted primarily of office infrastructure expenditures. In 2012, net cash provided by investing activities consisted primarily of $2.4
million net cash proceeds from the divestiture of the Company’s China operations and $2.4 million of proceeds received from the sale
of long-term investments, partially offset by $3.6 million paid for capital expenditures. In 2011, net cash used in investing activities
consisted primarily of $7.2 million paid for capital expenditures, partially offset by $0.3 million received for the sales of available for
sale securities.
Net cash provided by financing activities was $33.6 million for 2013 as compared to net cash used in financing activities of $20.5
million in 2012 and net cash provided by financing activities of $6.2 million in 2011. Net cash provided by financing activities for
2013, consisted primarily of a $29.2 million positive adjustment to the net assets of Allied in connection with the Allied Transaction
and $4.4 million of net borrowings under the Promissory Note with Allied. Net cash used in financing activities in 2012, consisted
primarily of a $15.3 million negative adjustment to the net assets of Allied and a $5.1 million of net repayments under the Promissory
Note with Allied. Net cash provided by financing activities for 2011 consisted primarily of net borrowings under the Promissory Note
with Allied. See below for details of the Promissory Note with Allied.
The Company has a $25.0 million borrowing facility under a Promissory Note with Allied. In August 2014, the Promissory Note was
amended to extend the maturity date by one year to July 2015 and to allow for the entire $25.0 million facility amount to be utilized
for general corporate purposes. As of December 31, 2013, $6.5 million was outstanding under the Promissory Note. See “Note 9. –
Note Payable – Related Party” for additional information regarding the Promissory Note.
In February 2014, the Company completed the Allied Transaction and the First Closing of the Private Placement with the Public
Investment Corporation (SOC) Limited, a state-owned company incorporated in the Republic of South Africa (“PIC”), in accordance
with the terms of the Transfer Agreement and the Share Purchase Agreement, respectively. In May 2014, the Company completed the
Second Closing of the Private Placement with the PIC. In aggregate, the Company received $270.0 million pursuant to the Closing of
both the First and Second Private Placements with the PIC. The Company paid Allied a total sum of $170.0 million in cash, resulting
in a net $100.0 million retained by the Company.
In September 2014, the Company entered into a Term Loan Facility Agreement (the “Term Loan Facility”) with a Nigerian bank for a
five year senior secured term loan providing initial borrowing capacity of up to $100.0 million. The purpose of the facility established
pursuant to the Loan Agreement is to provide funding for continued expansion and development of OMLs 120 and 121. For more
information on the Term Loan Facility, see “Note 18 – Subsequent Events” within the Notes to the Consolidated Financial Statements.
Although there are no assurances that the Company’s plans will be realized, management believes that the Company will have
sufficient capital resources to meet projected cash flow requirements for the next twelve months from the date of filing this report.
Capital Expenditures
In 2013, the Company invested $0.6 million in property and equipment additions primarily for office infrastructure support co sts. In
2012, the company invested $3.6 million in property and equipment additions, primarily associated with leasehold acquisition costs of
$2.0 million and $1.2 million in The Gambia and Kenya, respectively, and $0.4 million in office infrastructure support costs. In 2011,
the Company invested $7.2 million in property and equipment additions, of which $5.0 million was for the acquisition of an economic
interest in OML 121 offshore Nigeria.
Contractual Obligations
The following table summarizes the Company’s significant estimated future contractual obligations at December 31, 2013:
Payments Due By Period
(In thousands) Total 2014 2015-2016 2017-2018 Thereafter
Minimum obligations - Kenya $ 34,432 $ 10,800 $ 23,632 $ - $ -
Minimum obligations - The Gambia 114,000 4,000 110,000 - -
Operating lease obligations 2,149 360 750 784 255
Total $ 150,581 $ 15,160 $ 134,382 $ 784 $ 255
The minimum obligations for both Kenya and The Gambia require annual rental payments, training and community fees, all of which
have been included in the above table.
In January 2014, a long-term drilling contract was signed for the drillship Energy Searcher. The rig arrived at the Oyo Field offshore
Nigeria in June 2014 and has commenced the Oyo Field development campaign. The agreement covers an initial term of one year,
with an option to extend the contract for an additional one year. The minimum commitment pursuant to the initial term of the
agreement is approximately $86.0 million.
In February 2014, a long-term contract was signed for the floating, production, storage, and offloading vessel (“FPSO”) Armada
Perdana, which is the vessel currently connected to the Company’s producing wells Oyo-5 and Oyo-6 in OML 120. The contract
provides for an initial term of seven years beginning January 1, 2014, with an automatic extension for an additional term of two years
unless terminated by the Company with prior notice. The FPSO can process up to 40,000 barrels of liquid per day, with a storage
capacity of approximately one million barrels. The annual minimum commitment per the terms of the agreement is approximately
$35.0 million in the first year and approximately $48.0 million thereafter.
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 for its costs of acquisition, exploration and development of oil and
gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts
that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are
capitalized when incurred. Drilling costs of exploratory wells are capitalized pending determination that proved reserves have been
found. If the determination is dependent upon the results of planned additional wells and require additional capital expenditures to
develop the reserves, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the
exploratory well as a producing well, and additional wells are underway or firmly planned to complete the evaluation of the well.
Exploratory wells not meeting the criteria for continued capitalization are expensed when such a determination is made. Other
exploration costs are expensed as incurred.
Depreciation, depletion and amortization for productive oil and gas properties are recorded on a unit-of-production basis. For other
depreciable property, depreciation is recorded on a straight line basis over the estimated useful life of the assets which ranges between
three to five years or the lease term. Repairs and maintenance costs are charged to expense as incurred.
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 recognized $20.6 million and $24.8 million, respectively, in asset retirement obligations
related to OMLs 120 and 121.
Inventory
Inventories of crude oil are valued at the lower of cost or market using the first-in, first-out method and include certain costs directly
related to the production process.
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.
In April 2014, the Financial Accounting Standards Board (“FASB”) issued updated guidance that changes the criteria for reporting
discontinued operations including enhanced disclosure requirements. Under the updated guidance, only disposals representing a
strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the
organization´s operations and financial results. The standards update is effective for fiscal years beginning after December 15, 2014.
We will adopt this standards update, as required, beginning with the first quarter of 2015. The adoption of this standards update affects
presentation only and, as such, is not expected to have a material impact on our consolidated financial statements.
In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. The objective of this
guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising
from an entity’s contracts with customers, including qualitative and quantitative disclosures around contracts with customers,
significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. The standards
update is effective for interim and annual periods beginning after December 15, 2016. We will adopt this standards update, as
required, beginning with the first quarter of 2017. The Company is in the process of evaluating the impact, if any, of this guidance on
its consolidated financial statements.
In June 2014, the FASB issued updated guidance around share-based compensation. The guidance was issued to clarify the accounting
treatment for performance-based stock awards. The update states that companies should not record compensation expense related to an
award for which transfer to the employee is contingent on the company’s satisfaction of a performance target until it becomes
probable that the performance target will be met. The update does not contain any new disclosure requirements and is effective for
interim and annual periods beginning after December 15, 2015. We will adopt this standards update, as required, beginning with the
first quarter of 2016. The adoption of this standards update is not expected to have a material impact on our consolidated financial
statements.
In August 2014, the FASB issued updated guidance on determining when and how reporting entities must disclose going concern
uncertainties in its financial statements. The objective of the update is to define management’s responsibility to evaluate, each annual
and interim reporting period, whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as
a going concern within one year after the date the financial statements are issued and to provide related footnote disclosures. The
standards update is effective for annual periods ending after December 15, 2016, and interim period thereafter. We will adopt this
standards update, as required, beginning with the first quarter of 2017. The Company is in the process of evaluating the impact this
guidance will have on its footnote disclosures.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
(1) Consolidated Financial Statements
1
Reports of Independent Registered Public Accounting Firms
F- 1
1
Consolidated Balance Sheets at December 31, 2013 and 2012
F- 2
1
Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011
F- 3
1
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011
F- 4
Consolidated Statements of Equity for the years ended December 31, 2013, 2012 and 2011 1
F- 4
1
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011
F- 5
1
Notes to Consolidated Financial Statements
F- 6
(2) Consolidated Financial Statement Schedules
Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)
Schedules not included have been omitted because they are not applicable or the required information is shown in the 2
consolidated financial statements or notes. S- 9
(3) Exhibits
Grant Thornton
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 stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2013. These
financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of
CAMAC Energy Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for
each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the
United States of America.
/s/ GRANT THORNTON LLP
Houston, Texas
December 19, 2014
Grant Thornton LLP
U.S. member firm of Grant Thornton International Ltd
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.
/s/ RBSM LLP
New York, New York
March 15, 2012, except for paragraph 4 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
Crude oil inventory 16,254 2,350
Prepaids and other current assets 856 1,013
Total current assets 18,385 13,272
Property, plant and equipment:
Oil and gas properties (successful efforts method of accounting), net 435,035 363,268
Other property, plant and equipment, net 752 456
Total property, plant and equipment, net 435,787 363,724
Other assets 52 11
Noncurrent assets of discontinued operations - 36
Total Assets $ 454,224 $ 377,043
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 31,668 $ 15,112
Accrued expenses 7,446 2,770
Asset retirement obligations 12,479 -
Notes payable - related party 6,496 -
Total current liabilities 58,089 17,882
Asset retirement obligations 8,122 24,832
Long-term notes payable - related party - 872
Other long-term liabilities 67 55
Total liabilities 66,278 43,641
Commitments and Contingencies
Equity:
Preferred stock $0.001 par value - 50,000,000 shares
authorized; none issued and outstanding as of December 31,
2013 and 2012, respectively - -
Common stock $0.001 par value - 1,227,894,857 shares
authorized; 879,817,093 and 877,515,805 shares outstanding as
of December 31, 2013 and 2012, respectively 879 877
Paid-in capital 735,959 637,674
Accumulated deficit (348,892) (305,367)
Accumulated other comprehensive income (loss) - 224
Total equity - CAMAC Energy Inc. 387,946 333,408
Noncontrolling interests of discontinued operations - (6)
Total equity 387,946 333,402
Total liabilities and equity $ 454,224 $ 377,043
The accompanying notes are an integral part of these consolidated financial statements.
CAMAC ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for per share amounts)
Years Ended December 31,
2013 2012 2011
Revenues:
Crude oil sales, net of royalties $ 63,736 $ 74,667 $ 37,922
Operating costs and expenses:
Production costs 70,427 41,555 30,882
Exploratory expenses 5,501 3,236 890
Depreciation, depletion and amortization 16,875 51,002 13,477
General and administrative expenses 14,460 10,998 13,336
Total operating costs and expenses 107,263 106,791 58,585
Operating loss (43,527 ) (32,124 ) (20,663 )
Other income (expense), net: 38 (582 ) (328 )
Loss from continuing operations before income taxes (43,489 ) (32,706 ) (20,991 )
Income tax expense - - -
Net loss from continuing operations (43,489 ) (32,706 ) (20,991 )
Discontinued Operations
Net loss from discontinued operations, net of tax (36 ) (991 ) (4,012 )
Gain on divestiture, net - 4,160 -
Net (loss) income from discontinued operations (36 ) 3,169 (4,012 )
Net loss (43,525 ) (29,537 ) (25,003 )
Noncontrolling interests - discontinued operations - 8 90
Net loss attributable to CAMAC Energy Inc. $ (43,525 ) $ (29,529 ) $ (24,913 )
Net (loss) income per common share attributable to CAMAC Energy Inc. - basic:
Continuing operations $ (0.05 ) $ (0.05 ) $ (0.06 )
Discontinued operations $ (0.00 ) $ (0.00 ) $ (0.01 )
Total $ (0.05 ) $ (0.05 ) $ (0.07 )
Net (loss) income per common share attributable to CAMAC Energy Inc. - diluted:
Continuing operations $ (0.05 ) $ (0.05 ) $ (0.06 )
Discontinued operations $ (0.00 ) $ (0.00 ) $ (0.01 )
Total $ (0.05 ) $ (0.05 ) $ (0.07 )
Weighted average common shares outstanding:
Basic 878,710 628,101 376,312
Diluted 878,710 628,101 376,312
The accompanying notes are an integral part of these consolidated financial statements.
CAMAC ENERGY INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
Years Ended December 31,
2013 2012 2011
Net loss $ (43,525 ) $ (29,537 ) $ (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 (loss) income (224 ) 489 (145 )
Comprehensive loss (43,749 ) (29,048 ) (25,148 )
Comprehensive loss attributable to noncontrolling interests - 8 88
Comprehensive loss attributable to CAMAC Energy, Inc. $ (43,749 ) $ (29,040 ) $ (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
Common Stock Paid-in Accumulated Comprehensive Noncontrolling Total
Shares Amount Capital Deficit Income (Loss) Interest Equity
At December 31, 2010 374,014 $ 374 $ 458,303 $ (250,925 ) $ (120 ) $ (643 ) $ 206,989
Stock issued for services 2,045 2 705 - - - 707
Exercise of options 786 1 176 - - - 177
Vesting of restricted stock 1,488 1 (1 ) - - - -
Stock-based employee
compensation - - 2,484 - - - 2,484
Adjustments to noncontrolling
interest - - (733 ) - - 735 2
Net loss - - - (24,913 ) - (90 ) (25,003 )
Other comprehensive income
(loss): - - -
Foreign currency loss - - - - (31 ) - (31 )
Unrealized loss on investments,
net of taxes - - - - (114 ) - (114 )
At December 31, 2011 378,333 378 460,934 (275,838 ) (265 ) 2 185,211
Exercise of options 17 - 3 - - - 3
Vesting of restricted stock 1,251 1 - - - - 1
Contingent consideration stock
issued 460 1 889 - - - 890
Stock-based employee
compensation - - 739 - - - 739
Net loss - - - (29,529 ) - (8 ) (29,537 )
Net assets contributed by parent - - 190,925 - - - 190,925
Shares issued to affiliate 497,455 497 (497 ) - - - -
Allied Transaction adjustments (15,331 ) - - - (15,331 )
Other comprehensive income
(loss): - - -
Foreign currency gain - - 12 - 94 - 106
Unrealized gain on investments,
net of taxes - - - - 395 - 395
At December 31, 2012 877,516 877 637,674 (305,367 ) 224 (6 ) 333,402
Vesting of restricted stock 2,301 2 - - - - 2
Stock-based employee
compensation - - 2,013 - - - 2,013
Realized foreign currency gain - - - - (224 ) - (224 )
Adjustments to noncontrolling
interest - - - - - 6 6
Net loss - - - (43,525 ) - - (43,525 )
Net assets contributed by parent - - 61,205 - - - 61,205
Allied Transaction adjustments - - 35,067 - - - 35,067
At December 31, 2013 879,817 $ 879 $ 735,959 $ (348,892 ) $ - $ - $ 387,946
The accompanying notes are an integral part of these consolidated financial statements.
CAMAC ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
2013 2012 2011
Cash flows from operating activities
Net loss $ (43,525) $ (29,537) $ (25,003)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization 14,640 49,963 13,530
Asset retirement obligation accretion 2,235 1,047 -
Stock-based compensation 2,013 739 2,484
Currency transaction (gain) loss (224) 22 (31)
Dry hole costs - (37) 2,176
Gain on divestiture, net - (4,160) -
Other 16 55 -
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable (3,046) 12,836 (8,528)
Decrease in other current assets 156 649 1,841
(Increase) decrease in inventories (14,004) (1,483) 72
Increase (decrease) in accounts payable and accrued expenses 5,114 (20,660) (1,195)
Net cash (used in) provided by operating activities (36,625) 9,434 (14,654)
Cash flows from investing activities
Capital expenditures (602) (3,576) (7,159)
Proceeds from divestiture, net - 2,364 -
Net sales of available for sale securities - - 256
Decrease in other assets - 465 43
Proceeds from the sale long-term investments - 1,966 -
Net cash (used in) provided by investing activities (602) 1,219 (6,860)
Cash flows from financing activities
Allied Transaction adjustments 29,234 (15,331) -
Proceeds from the exercise of stock options - 3 177
Proceeds (repayments) of note payable - related party, net 4,350 (5,128) 6,000
Net cash provided by (used in) financing activities 33,584 (20,456) 6,177
Effect of exchange rate on cash and cash equivalents - (17) 45
Net decrease in cash and cash equivalents (3,643) (9,820) (15,292)
Cash and cash equivalents at beginning of period 3,806 13,626 28,918
Cash and cash equivalents at end of period $ 163 $ 3,806 $ 13,626
Supplemental disclosure of cash flow information
Cash paid for:
Interest, net $ 99 $ 117 $ 120
Contingent consideration stock $ - $ 890 $ -
Supplemental disclosure of non-cash investing and financing activities:
Nonsubsidiary common stock received as partial proceeds from divestiture, net $ - $ 1,877 $ -
Common stock issued for services $ - $ - $ 707
Related party accounts payable, net, settled with related party notes payable $ 1,274 $ - $ -
Non-cash gain from asset retirement obligation extinguishment $ 5,833 $ - $ -
Net assets contributed by parent $ 61,205 $ 190,925 $ -
The accompanying notes are an integral part of these consolidated financial statements
CAMAC ENERGY INC.
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 nine licenses across four
countries covering an area of approximately 43,000 square kilometers (approximately 10 million acres). The Company owns
producing properties and conducts exploration activities offshore Nigeria, conducts exploration activities offshore Ghana and The
Gambia, and both offshore and onshore Kenya.
CAMAC Energy Inc. is headquartered in Houston, Texas and has offices in Nairobi, Kenya, Banjul, The Gambia and Lagos, Nigeria.
The Company’s operating subsidiaries include CAMAC Energy Ltd (“CEL”), CAMAC Petroleum Limited (“CPL”), CAMAC Energy
International Limited, CAMAC Energy Ghana Limited, CAMAC Energy Kenya Limited, CAMAC Energy Gambia A2 Limited, and
CAMAC Energy Gambia A5 Limited. The terms “we,” “us,” “our,” “Company,” and “our Company” refer to CAMAC Energy Inc.
and its subsidiaries and affiliates.
The Company also conducts certain business transactions with its majority shareholder, CAMAC Energy Holdings Limited
(“CEHL”), and its affiliates, which include Allied Energy Plc (“Allied”). See “Note 15 – Related Party Transactions” for additional
information with regard to these transactions.
The Company’s Executive Chairman of the Board of Directors, and Chief Executive Officer, is a director of each of the above listed
related parties. He indirectly owns 27.7% of CEHL, which is the majority shareholder of the Company. As a result, he may be deemed
to have an indirect material interest in transactions contemplated with any of the above companies and their affiliates.
NOTE 2. — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company and its wholly owned and majority-owned
direct and indirect subsidiaries and have been prepared in accordance with generally accepted accounting principles in the United
States (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). All
significant intercompany transactions and balances have been eliminated in consolidation. The consolidated financial statements
reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial position
and results of operations for the indicated periods. All such adjustments are of a normal recurring nature.
In August 2012, the Company divested its wholly owned Hong Kong subsidiary Pacific Asia Petroleum Limited for cash and shares of
stock. The Company has classified the current and historical results of its China operations, including other inactive operations not
involved in this sale, as discontinued operations, net of tax, in the accompanying consolidated statements of operations. See “Note 3 -
Discontinued Operations”, for more information regarding the sale.
In January 2014 the Company’s Board of Directors declared a stock dividend on all shares of the Company’s outstanding Common
Stock entitling stockholders of record as of the close of business on February 13, 2014, to receive an additional 1.4348 shares of
Common Stock for every share of Common Stock held (the “Stock Dividend”). Payment of the Stock Dividend was conditioned on
(i) approval of the Company’s stockholders at the special meeting of stockholders to be held on February 13, 2014 of certain proposals
related to the Allied Transaction, including a proposal to amend the Company’s certificate of incorporation to increase the number of
authorized shares of Common Stock and (ii) approval of the listing of the Company’s Common Stock on the Johannesburg Stock
Exchange (“JSE”). On February 13, 2014, the Company held a special meeting of its stockholders to consider and vote upon the
proposals mentioned above and other related agenda items. All of the proposals presented at the meeting received the requisite
shareholder approval and the approval of the JSE listing was successfully obtained. On February 21, 2014, the Company paid the
Stock Dividend pursuant to which each share of stock of record as of the close of business on February 13, 2014, carried the right to
receive 1.4348 shares of Common Stock for every one share of Common Stock held.
Due to the large nature of the Stock Dividend (exceeds 25% of the total shares outstanding prior to the distribution), it has been
accounted for as a Stock Split. The effect is a retroactive adjustment to the financial statements and associated footnotes as if the
dividend had occurred at the beginning of the first period presented.
In February 2014, the Company completed the acquisition of the remaining economic interests that it did not already own in the
Production Sharing Contract (“PSC”) covering Oil Mining Leases 120 and 121 (“OMLs 120 and 121”) located offshore Nigeria,
which include the currently producing Oyo Field (the “Allied Assets”), from Allied (the “Allied Transaction”). Allied is a subsidiary
of CEHL, the Company’s majority shareholder, and deemed to be under common control (transactions between subsidiaries of the
same parent). Accordingly, the net assets acquired from Allied were recorded at their respective carrying values as of the acquisition
date. The consolidated financial statements, included herein, are presented as though the Allied Transaction had occurred in June
2012, the date Allied Acquired the Allied Assets from an independent third party. See “Note 4 – Acquisitions” for additional
information relating to the Allied Assets and “Note 18 – Subsequent Events” for additional information relating to the Allied
Transaction.
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 for its costs of acquisition, exploration and development of oil and
gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts
that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are
capitalized when incurred. Drilling costs of exploratory wells are capitalized pending determination that proved reserves have been
found. If the determination is dependent upon the results of planned additional wells and require additional capital expenditures to
develop the reserves, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the
exploratory well as a producing well, and additional wells are underway or firmly planned to complete the evaluation of the well.
Exploratory wells not meeting the criteria for continued capitalization are expensed when such a determination is made. Other
exploration costs are expensed as incurred.
Depreciation, depletion and amortization for productive oil and gas properties are recorded on a unit-of-production basis. For other
depreciable property, depreciation is recorded on a straight line basis over the estimated useful life of the assets which ranges between
three to five years, or the lease term. Repairs and maintenance costs are charged to expense as incurred.
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 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. See “Note 8 –
Asset Retirement Obligations” for further information.
Inventory
Inventories of crude oil are valued at the lower of cost or market using the first-in, first-out method and include certain costs directly
related to the production process.
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 to their net realizable amounts if it is more likely than not that the related tax benefits will not
be fully realized.
The Company routinely evaluates any tax deduction and tax refund positions in a two-step process. The first step is to determine
whether it is more likely than not that a tax position will be sustained. If that test is met, the second step is to determine the amount of
benefit or expense to recognize in the consolidated financial statements. See “Note 10 – Income Taxes” for further information.
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 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 disclosure, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts
reclassified from each component of accumulated other comprehensive income based on its source and the income statement line
items affected by the reclassification. The new guidance is effective prospectively for reporting periods beginning after December 15,
2012. The Company adopted the guidance required as of January 1, 2013. The required disclosures have been included in Note 5,
Accumulated Other Comprehensive Income (Loss) of the Notes to Consolidated Financial Statements
In February 2013, the FASB issued ASU 2013-04, Obligations Resulting From Joint and Several Liability Arrangements for Which
the Total Amount of the Obligation is Fixed at the Reporting Date. The amendments in ASU 2013-04 to Topic 405, Liabilities,
provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability
arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for
obligations addressed with existing U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the
amount the reporting entity agreed to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and
amounts of the obligation, as well as other information about those obligations. The amendment is effective retrospectively for
reporting periods beginning after December 15, 2013. Early adoption is permitted. The adoption of this guidance is not expected to
have a material impact on the Company’s consolidated financial statements.
In 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, or the entity does not intend to use, the deferred tax asset for such purpose, the
unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax
assets. The amendments in ASU 2013-11 are effective prospectively for fiscal years, and interim periods within those years, beginning
after December 15, 2013. Retrospective application is permitted. The Company is currently evaluating the possible impact of ASU
2013-11, but does not anticipate that it will have a material impact on the Company’s consolidated financial statements.
In April 2014, the Financial Accounting Standards Board (“FASB”) issued updated guidance that changes the criteria for reporting
discontinued operations including enhanced disclosure requirements. Under the updated guidance, only disposals representing a
strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the
organization´s operations and financial results. The standards update is effective for fiscal years beginning after December 15, 2014.
We will adopt this standards update, as required, beginning with the first quarter of 2015. The adoption of this standards update affects
presentation only and, as such, is not expected to have a material impact on our consolidated financial statements.
In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. The objective of this
guidance is to establish principles for reporting information about the nature, timing, and uncertainty of revenue and cash flows arising
from an entity’s contracts with customers, including qualitative and quantitative disclosures around contracts with customers,
significant judgments and change in judgments, and assets recognized from the costs to obtain or fulfill a contract. The standards
update is effective for interim and annual periods beginning after December 15, 2016. We will adopt this standards update, as
required, beginning with the first quarter of 2017. The Company is in the process of evaluating the impact, if any, of this guidance on
its consolidated financial statements.
In June 2014, the FASB issued updated guidance around share-based compensation. The guidance was issued to clarify the accounting
treatment for performance-based stock awards. The update states that companies should not record compensation expense related to an
award for which transfer to the employee is contingent on the company’s satisfaction of a performance target until it becomes
probable that the performance target will be met. The update does not contain any new disclosure requirements and is effective for
interim and annual periods beginning after December 15, 2015. We will adopt this standards update, as required, beginning with the
first quarter of 2016. The adoption of this standards update is not expected to have a material impact on our consolidated financial
statements.
In August 2014, the FASB issued updated guidance on determining when and how reporting entities must disclose going concern
uncertainties in its financial statements. The objective of the update is to define management’s responsibility to evaluate, each annual
and interim reporting period, whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as
a going concern within one year after the date the financial statements are issued and to provide related footnote disclosures. The
standards update is effective for annual periods ending after December 15, 2016, and interim period thereafter. We will adopt this
standards update, as required, beginning with the first quarter of 2017. The Company is in the process of evaluating the impact this
guidance will have on its footnote disclosures.
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 (in thousands):
Years Ended December 31,
2013 2012 2011
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 (in thousands):
As of December 31,
2013
Other assets $ 36
Total assets $ 36
NOTE 4. — ACQUISITIONS
The Allied Assets
In June 2012, Allied purchased the Allied Assets from an independent third party. The Allied Assets were subsequently acquired by
the Company in February 2014 as part of the Allied Transaction see “Note 18 – Subsequent Events”. Allied is a wholly owned
subsidiary of CEHL, the Company’s majority shareholder, and deemed to be under common control (transactions between subsidiaries
of the same parent). The transaction has been accounted for as if CEHL had acquired the Allied Assets and contributed them to the
Company. In addition, costs related to the drilling of the Oyo-7 well, incurred by Allied in 2013, are also considered to be contributed
to the Company.
The table below shows the carrying values of the net Allied Assets contributed at their respective periods (in thousands):
As of December 31,
2013 2012
Asset acquired and liabilities assumed:
Property, plant and equipment, net $ 61,205 $ 214,710
Asset retirement obligations - (23,785 )
Net assets acquired $ 61,205 $ 190,925
Because these assets were deemed paid for by CEHL and contributed to the Company, they have been treated as non-cash transactions
in the accompanying Consolidated Statements of Cash Flows.
Award of 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 (the “Kenya PSCs”), covering onshore exploration blocks L1B and L16, and new offshore exploration
blocks L27 and L28. For all blocks, the Company is the operator, with the Government having the right to participate up to 20%,
either directly or through an appointee, in any area subsequent to declaration of a commercial discovery. The Company also has the
right to apply for up to two additional two-year exploration periods, with specified additional minimum work obligations, including
the acquisition of seismic data and the drilling of one exploratory well on each block during each such additional period. The
Company is responsible for all exploration expenditures.
The Kenya PSCs for onshore blocks L1B and L16 each provide for an initial exploration period, now extended through June 2015,
with specified minimum work obligations during that period. Prior to the end of the initial exploration period, the Company is required
to conduct, for each block, a gravity and magnetic survey and acquire, process and interpret 2D seismic data. The gravity and
magnetic survey was completed in April 2013. In December 2013, the Company initiated an Environmental and Social Impact
Assessment (“ESIA”) study which was successfully completed in March 2014. In October 2014, the Company signed agreements for
both blocks for the acquisition, processing and interpretation of 2D seismic data. The project is expected to be completed in the first
half of 2015.
The Kenya PSCs for offshore blocks L27 and L28 each provide for an initial exploration period of three years, through August 2015,
with specified minimum work obligations during that period. Prior to the end of the initial exploration period, the Company is required
to conduct, for each block, a regional geological and geophysical study, acquire 2D seismic data and acquire, process and interpret 3D
seismic data. The Company participated in a multi-client combined gravity / magnetic and 2D seismic survey covering blocks L27 and
L28. The survey was successfully completed in March 2014. The processed data is currently being interpreted internally. Further, in
March 2014 the Company started the regional geophysical study for these two blocks.
In addition to the minimum work obligations, each of the Kenya PSCs requires annual surface rental payments, training fund
payments and contributions to local community development projects.
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
Gambian National Petroleum Company (“GNPCo”) having the right to elect to participate up to a 15% interest, following approval of
a development and production plan. The Company is responsible for all expenditures prior to such approval even if the GNPCo elects
to participate.
The Gambia Licenses provide for an initial exploration period of four years with specified minimum work obligations during that
period. Prior to the end of the initial exploration period, the Company will conduct, on each block, a regional geological study,
acquire, process and interpret seismic data, drill one exploration well and evaluate drilling results, with the first two work obligations
(regional geological study and 3D seismic data acquisition and processing) due prior to the end of the second year. The Company has
the right to apply for up to two additional two-year exploration periods with specified additional minimum work obligations, including
the drilling of one exploration well during each additional period for each block. The company has completed a regional geology and
geophysical study of both the A2 and A5 blocks.
In addition to the minimum work obligations, The Gambia Licenses require annual rental payments, training and community fees.
NOTE 5. — ACCUMULATED OTHER COMPREHENSIVE INCOME
The following summarizes the changes in the balances of each component of accumulated other comprehensive income (loss) (in
thousands):
Foreign
Currency
Gain (Loss)
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 (in thousands):
As of December 31,
2013 2012
Wells and production facilities $ 28,874 $ 34,725
Proved properties 386,196 386,196
Work in progress and other 86,634 -
Oilfield assets 501,704 420,921
Accumulated depletion (74,909) (65,893 )
Oilfield assets, net 426,795 355,028
Unevaluated leaseholds 8,240 8,240
Oil and gas properties, net 435,035 363,268
Other property and equipment 1,590 989
Accumulated depreciation (838 ) (533 )
Other property and equipment, net 752 456
Total property, plant and equipment, net $ 435,787 $ 363,724
NOTE 7. — SUSPENDED EXPLORATORY WELL COSTS
In November 2013, the Company achieved both its primary and secondary drilling objectives for the Oyo-7 well. The primary drilling
objective was to establish production from the existing Pliocene reservoir. The secondary drilling objective was to confirm the
presence of hydrocarbons in the deeper Miocene formation. Hydrocarbons were encountered in three Miocene intervals totaling
approximately 65 feet, as interpreted by the logging-while-drilling (“LWD”) data. Management is making plans to further explore the
Miocene formation in future wells. The Company’s suspended exploratory well costs were $26.5 million at December 31, 2013 for the
costs related to the Miocene exploratory drilling activities. The Company did not have any suspended exploratory well costs at
December 31, 2012.
NOTE 8. —ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations primarily represent the estimated fair value of the amounts that will be incurred to plug,
abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such
obligations include, but are not limited to, estimates of plugging and abandonment costs, estimated future inflation rates and changes
in property lives. The inputs are calculated based on historical data as well as current estimated costs.
The following tables summarize the changes and the balances of current and long-term portions in the Company’s asset retirement
obligations during the periods (in thousands):
As of December 31,
2013 2012
Asset retirement obligations at January 1 $ 24,832 $ -
Property acquisition - 23,785
Revisions in estimated liabilities (6,466 ) -
Accretion 2,235 1,047
Asset retirement obligations at December 31 $ 20,601 $ 24,832
As of December 31,
2013 2012
Asset retirement obligations, current portion $ 12,479 $ -
Asset retirement obligations, long-term portion 8,122 24,832
$ 20,601 $ 24,832
Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying
consolidated statements of operations.
NOTE 9. — 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-5 well in an aggregate sum of up to $25.0 million. Interest accrues on the outstanding principal under the
Promissory Note at a rate of 30 day LIBOR plus 2% per annum. In September 2013, the Company and Allied amended the Promissory
Note and the Guaranty to add the Company as a borrower, to allow for borrowings of up to $10.0 million for general corporate
purposes and to pledge the stock of the subsidiary of CEI that holds the exploration licenses in The Gambia and Kenya as collateral
pursuant to an equitable share mortgage arrangement. As of December 31, 2013, the book value of the exploration licenses in The
Gambia and Kenya was $3.2 million. Pursuant to the initial terms of the Promissory Note, the outstanding principal amount of all
loans was to mature on June 6, 2013. In August 2012, the Promissory Note was amended to extend the maturity date to October 15,
2013, and in March 2013 the Promissory Note was again amended to extend the maturity date to July 15, 2014. In January 2014,
Allied agreed to amend the Promissory Note and extend the maturity date to July 15, 2015 in the event the Company is not successful
in obtaining external financing arrangements by June 30, 2014. In August 2014, the Promissory Note was amended to extend the
maturity date by one year to July 2015, and to allow for the entire $25.0 million facility amount to be utilized for general corporate
purposes. The Company has guaranteed all of CPL’s obligations under the Promissory Note. As of December 31, 2013, $6.5 million
was outstanding under the Promissory Note.
The Company’s Executive Chairman and member of the Board of Directors, and Chief Executive Officer indirectly owns 27.7% of
CEHL, which is the majority shareholder of the Company. As a result, he is deemed to have an indirect material interest in the
transaction contemplated by the Promissory Note. The material facts as to this relationship with Allied were fully disclosed to the
Board of Directors prior to Board approval of the transaction.
NOTE 10. — 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 (in thousands):
Years Ended December 31,
2013 2012 2011
Net loss attributable to CAMAC Energy Inc. before income
tax expense $ (43,525 ) $ (29,529 ) $ (24,913 )
Expected income tax provision at statutory rate of 35% (15,234 ) (10,335 ) (8,720 )
Increase (decrease) due to:
Foreign-incorporated subsidiaries - - 4,102
Net losses not realizable currently for U.S. tax purposes 15,234 10,335 4,618
Total income tax expense $ - $ - $ -
Significant components of our deferred tax assets are as follows (in thousands):
As of December 31,
2013 2012
Basis difference in fixed assets $ (105,007 ) $ (50,121 )
Unused capital allowances 341,540 276,644
Net operating losses 26,650 16,922
Share-based compensation 837 368
264,020 243,813
Valuation allowance (264,020 ) (243,813 )
Net deferred income tax assets $ - $ -
The majority of the Company’s basis difference in fixed assets and unused capital allowances were generated from its Nigerian
operations. The Company’s foreign net operating losses in Nigeria are not subject to expiration, and can be carried forward
indefinitely. The foreign operating losses in The Gambia and Kenya are included in the respective subsidiaries cost oil accounts,
which will be offset against future taxable revenues.
Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. Based on
current facts and circumstances related to its Nigerian operations, Management has determined that it cannot demonstrate that it is
more likely than not that the Nigerian losses and unutilized capital allowances will be utilized to reduce the Company’s petroleum
profit tax liability within the foreseeable future. Furthermore, since the Company does not currently have any revenue generating
activities either in the U.S. or in any of its non-Nigerian subsidiaries, it cannot demonstrate that it is more likely than not that any of
the related deferred tax assets will be utilized in the foreseeable future.
On the basis of this assessment, valuation allowances of $264.0 million and $243.8 million were recorded as of December 31, 2013
and 2012, respectively.
At December 31, 2013 and 2012, the Company was subject to foreign and United States federal taxes only, with no allocations made
to state and local taxes.
The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:
United States: 2007 - 2013
Nigeria: 2010 - 2013
Kenya: 2012 - 2013
Gambia: 2012 - 2013
NOTE 11. — STOCK BASED COMPENSATION
Under the Company’s amended 2009 Equity Incentive Plan (“2009 Plan”), the Company may issue restricted stock awards and stock
options to result in issuance of a maximum aggregate of 100,000,000 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.
Weighted-Average
Shares Remaining
Underlying Weighted-Average Contractual Term
Options Exercise Price (Years)
Stock Options
Outstanding at January 1, 2013 6,124,703 $ 0.37 3.5
Granted 8,003,874 $ 0.28 4.3
Exercised -
Forfeited (353,046 ) $ 0.69
Outstanding as of December 31, 2013 13,775,531 $ 0.31 3.7
Expected to vest 13,775,531 $ 0.31 3.7
Exercisable at December 31, 2013 3,376,648 $ 0.37 2.7
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 12. — 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
(in thousands):
Years ended December 31,
2013 2012 2011
Basic 878,710 628,101 376,312
Diluted 878,710 628,101 376,312
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 (in thousands):
Years ended December 31,
2013 2012 2011
Stock options - 4 238
Warrants issued in stock offerings - - 14
Nonvested restricted stock awards 2,154 796 158
2,154 800 410
NOTE 13. — 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, inventory, accounts payable, accrued expenses, asset retirement obligations, other long-term liabilities and debt at floating
interest rates approximate their fair values at December 31, 2013 and 2012, respectively, principally due to the short-term nature,
maturities or nature of interest rates of the above listed items.
Concentration of Credit Risk
The Company is currently not exposed to any concentration of credit risk.
NOTE 14. — 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 also has commitments related to four production sharing contracts with the Republic of Kenya and two Petroleum
Exploration, Development & Production Licenses with the Republic of The Gambia, in each case entered into by the Company
through a wholly owned subsidiary. To maintain compliance and ownership, the Company is required to fulfill minimum work
obligations and to make certain payments as stated in each of the Kenya PSCs and The Gambia Licenses. At December 31, 2013,
minimum future work obligations were a total of $148.4 million as follows: $14.8 million in 2014 and $133.6 million in the years
2015 and 2016.
In January 2014, a long-term drilling contract was signed for the drillship Energy Searcher. The rig arrived on location in the Oyo
Field on OML 120 in June 2014 and commenced drilling the Oyo-8 well. The drilling agreement is for an initial term of one year, with
an option to extend the contract for an additional one year. The minimum commitment pursuant to the initial term of the agreement is
approximately $86.0 million.
In February 2014, a long-term contract was signed for the floating, production, storage, and offloading vessel (“FPSO”) Armada
Perdana, which is the vessel currently connected to the Company’s producing wells Oyo-5 and Oyo-6. The contract provides for an
initial term of seven years beginning January 1, 2014, with an automatic extension for an additional term of two years unless
terminated by the Company with prior notice. The FPSO can process up to 40,000 barrels of liquid per day, with a storage capacity of
approximately one million barrels. The annual minimum commitment per the terms of the agreement is approximately $35.0 million
in the first year and approximately $48.0 million thereafter.
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 15. — 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 (in thousands):
As of December 31,
2013 2012
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
CEHL, total operating (income) and expenses $ (1,167 ) $ 81 $ 3,243
CEHL, other expense, net 99 122 120
In June 2011, CPL, a wholly owned subsidiary of the Company, executed a Promissory Note in favor of Allied. See “Note 9 - Note
Payable – Related Party,” for additional information relating to the Promissory Note. As of December 31, 2013, $6.5 million was
outstanding under the Promissory Note.
NOTE 16. — SEGMENT INFORMATION
The Company’s current operations are based in Nigeria, Kenya and The Gambia. Management reviews and evaluates the operations of
each geographic segment separately. Segments include exploration for and production of hydrocarbons where commercial reserves
have been found and developed. Revenues and expenditures are recognized at the relevant geographical location. The Company
evaluates each segment based on operating income (loss).
The Company did not previously report separate segment information because management reviewed and evaluated the operations of
the Company as a whole. However pursuant to the Allied Transaction and the significant exploration activities undertaken in several
of our subsidiaries, management began to evaluate the operations of each geographic segment separately.
Segment activity are as follows (in thousands):
Corporate and
Nigeria Kenya The Gambia Other Total
For the Year Ended December 31,
2013
Revenues $ 63,736 $ - $ - $ - $ 63,736
Operating loss $ (23,705) $ (3,404) $ (1,070) $ (15,348) $ (43,527)
2012
Revenues $ 74,667 $ - $ - $ - $ 74,667
Operating loss $ (18,497) $ (1,046) $ (498) $ (12,083) $ (32,124)
2011
Revenues $ 37,922 $ - $ - $ - $ 37,922
Operating loss $ (7,870) $ - $ - $ (12,793) $ (20,663)
Total assets by segment are as follows (in thousands):
Corporate and
Nigeria Kenya The Gambia Other Total
Total Assets
As of December 31, 2013 $ 449,856 $ 1,484 $ 2,025 $ 859 $ 454,224
As of December 31, 2012 $ 371,744 $ 1,364 $ 2,168 $ 1,767 $ 377,043
NOTE 17. — SELECTED UNAUDITED QUARTERLY FINANCIAL DATA (In thousands)
Three Months Ended,
September 30, December 31,
March 31, 2013 June 30, 2013 2013 2013
Total revenues $ 22,006 $ 20,007 $ 21,723 $ -
Operating loss $ (10,484 ) $ (11,924 ) $ (10,401 ) $ (10,718 )
Net loss attributable to CAMAC Energy Inc. $ (10,488 ) $ (11,930 ) $ (10,417 ) $ (10,690 )
Net loss per common share attributable to CAMAC Energy Inc.:
Basic $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.01 )
Diluted $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.01 )
Three Months Ended,
September 30, December 31,
March 31, 2012 June 30, 2012 2012 2012
Total revenues $ 5,672 $ - $ 44,657 $ 24,338
Operating loss $ (879 ) $ (3,496 ) $ (10,861 ) $ (16,888 )
Net loss attributable to CAMAC Energy Inc. $ (1,296 ) $ (3,975 ) $ (6,879 ) $ (17,379 )
Net loss per common share attributable to CAMAC Energy Inc.:
Basic $ (0.00 ) $ (0.01 ) $ (0.01 ) $ (0.02 )
Diluted $ (0.00 ) $ (0.01 ) $ (0.01 ) $ (0.02 )
NOTE 18. — SUBSEQUENT EVENTS
Allied Transaction
In February 2014, the Company completed the Allied Transaction thereby acquiring the Allied Assets. Pursuant to the terms of the
Transfer Agreement, the Company, as partial consideration for the Allied Assets, paid $85.0 million in cash to Allied, issued
497,454,857 shares of the Company’s common stock to Allied and delivered a $50.0 million Convertible Subordinated Note (the
“Convertible Subordinated Note”) to Allied under which $25.0 million was deemed advanced, with interest accruing per the terms of
the Convertible Subordinated Note. Because Allied is a subsidiary of CEHL, the Company’s majority shareholder, it is deemed to be
under common control. Accordingly, the shares issued to Allied pursuant to the transaction were accounted for as if issued on June 30,
2012, the effective date when Allied acquired the Allied Assets.
To fund the cash portion of the Allied Transaction and a portion of the anticipated capital expenditures for development of the Oyo
Field, the Company also entered into a Share Purchase Agreement (the “Share Purchase Agreement”) with the Public Investment
Corporation (SOC) Limited, a state-owned company registered and duly incorporated in the Republic of South Africa (“PIC”), for an
aggregate cash investment of $270.0 million through a private placement of 376,884,422 shares of common stock (the “Private
Placement”). The Share Purchase Agreement provides that the Private Placement will be completed in two installments. The first
installment of $135.0 million (the “First Closing”) in exchange for 188,442,211 shares of the Company’s common stock was
completed at the closing of the Allied Transaction. The second installment (the “Second Closing”) of $135.0 million in exchange for
188,442,211 shares of the Company’s common stock was completed in May 2014.
Following the Second Closing with the PIC, the Company was required to pay to Allied the additional $85.0 million in cash, and the
additional $25.0 million Convertible Subordinated Note was deemed advanced with interest accruing per the terms of the Convertible
Subordinated Note. As of the First Closing and pursuant to the terms of the Transfer Agreement, the Company was obligated for the
full $50.0 million Convertible Subordinated Note and accordingly recorded this on the balance sheet at that time.
The Allied Transaction is being accounted for as a transaction between entities under common control, whereby the net assets
acquired are combined with the Company’s assets at their historical amounts. Since the cash and debt consideration exceeds the
carrying cost of the assets acquired, no value was assigned to the shares issued.
Ghana Petroleum Agreement
In April 2014, the Company signed a Petroleum Agreement relating to the Expanded Shallow Water Tano block in Ghana. The
Company has been named technical operator and will hold an indirect 30% interest in the block. The block contains three discovered
fields, and the work program requires the partners to determine, within nine months, the economic viability of developing the
discovered fields.
Term Loan Facility
In September 2014, the Company, through its wholly owned subsidiary CPL, entered into a credit facility with a Nigerian bank for a
five-year senior secured term loan providing initial borrowing capacity of up to $100.0 million (the “Term Loan Facility”). U.S. dollar
borrowings under the Term Loan Facility bear interest at the rate of LIBOR plus 7.5%, subject to a floor of 9.5%. The obligations
under the Term Loan Facility include a legal charge over OMLs 120 and 121 and an assignment of proceeds from oil sales. The
obligations of CPL have been guaranteed by the Company and rank in priority with all its other obligations. Proceeds from the Term
Loan Facility will be used for the further expansion and development of OMLs 120 and 121 offshore Nigeria, including the Oyo field.
Under the Term Loan Facility, the following events, among others, constitute events of default: CPL failing to pay any amounts due
within thirty days of the due date; bankruptcy, insolvency, liquidation or dissolution of CPL; a material breach of the Loan Agreement
by CPL that remains unremedied within thirty days of written notice by CPL; or a representation or warranty of CPL proves to have
been incorrect or materially inaccurate when made. Upon any event of default, all outstanding principal and interest under any loans
will become immediately due and payable.
The Term Loan Facility contains normal and customary covenants including the delivery of the Company’s annual audited financial
information each year, and a provision of priority of interest, in which the Company is to procure that its obligations under the Term
Loan Facility do and will rank in priority with all its other current and future unsecured and unsubordinated obligations. The
Company is also to provide a production and lifting schedule each month displaying the daily production totals and quantities lifted
respectively from OMLs 120 and 121.
Upon executing the Term Loan Facility, the Company paid a commitment fee of $1.9 million, which was capitalized and will be
amortized over the life of the Term Loan Facility.
he 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.
CAMAC ENERGY INC.
SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)
(In Thousands)
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 rights to proved reserves and the
estimates of proved crude oil reserves attributable to our net interests in oil and gas properties for the year ended December 31, 2013.
Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-
month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-
month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve
estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing properties.
Accordingly, reserve estimates are expected to change as additional performance data becomes available.
Crude Oil
(MBbls)
International
December 31, 2010 5,288
Revisions (2,288 )
Production (337 )
December 31, 2011 2,663
Revisions 2,986
Acquisition 9,043
Production (683 )
December 31, 2012 14,009
Revisions (4,878 )
Production (591 )
December 31, 2013 8,540
Proved developed reserves
December 31, 2011 92
December 31, 2012 660
December 31, 2013 321
Proved undeveloped reserves
December 31, 2011 2,571
December 31, 2012 13,349
December 31, 2013 8,219
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 $ 449,770 $ 420,921
Unproved properties 34,745 8,240
Materials and equipment 25,429 -
Total capitalized costs 509,944 429,161
Accumulated depreciation, depletion and
amortization (74,909) (65,893)
Net capitalized costs $ 435,035 $ 363,268
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)
Property acquisitions
Proved(1) $ 61,205 $ 214,710 $ -
Unproved - 3,240 5,000
Exploration 32,006 3,236 890
Development 34,700 - -
Total costs incurred $ 127,911 $ 221,186 $ 5,890
(1) Costs incurred by parent and contributed to the Company. See “Note 4 – Acquisitions” of the Notes to the Consolidated Financial Statements for
additional information relating to the contributed costs.
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 $ 63,736 $ 74,667 $ 37,922
Production, G&A and other costs (70,399 ) (41,555 ) (30,882 )
Exploratory expenses (267 ) (3,236 ) (890 )
Depreciation, depletion and amortization (16,585 ) (50,847 ) (13,316 )
Results from oil and gas producing activities $ (23,515 ) $ (20,971 ) $ (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 $108.63, $112.77,
and $112.26 per barrel of crude oil, respectively, including differentials. Amounts below for production sold and production costs
exclude royalties.
Years Ended December 31,
2013 2012 2011
International (In thousands)
Future cash inflows from production sold $ 921,396 $ 1,579,836 $ 298,936
Future production costs (475,703 ) (687,156 ) (140,104 )
Future development costs (287,468 ) (302,000 ) (62,308 )
Future income taxes (28,620 ) (56,873 ) (16,212 )
Future net cash flows before discount 129,605 533,807 80,312
Discount at 10% annual rate (28,338 ) (146,387 ) (18,625 )
Standardized measure of discounted future cash flows $ 101,267 $ 387,420 $ 61,687
Change in Standardized Measure of Discounted Future Net Cash Flows
Years Ended December 31,
2013 2012 2011
International (In thousands)
Balance at Beginning of Period $ 387,420 $ 61,687 $ 95,696
Sales of oil and gas, net of production costs 6,691 (33,112 ) (35,617 )
Net changes in prices and production costs (154,217 ) 9,432 136,097
Net change due to revision of quantity estimates (201,728 ) 138,088 (139,203 )
Net change due to purchases of minerals in place - 418,195 -
Changes in estimated future development costs 11,355 (173,961 ) (9,989 )
Accretion of discount 38,742 6,169 10,417
Net change of income taxes 22,076 (29,510 ) 4,286
Change in production rates (timing) and other (9,072 ) (9,568 ) -
Balance at End of Period $ 101,267 $ 387,420 $ 61,687
Exhibit 99.2
DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244
This is a digital representation of a DeGolyer and MacNaughton report.
This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same conditions thereof.
The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report
should be considered the only authoritative source of such information.
DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244
December 5, 2014
Camac Energy Inc.
1330 Post Oak Boulevard
Suite 2250
Houston, Texas 77056
Ladies and Gentlemen:
Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the extent and value of the
proved crude oil reserves, as of January 1, 2014, of a 100-percent working interest which Camac Energy Inc. (Camac) has represented
it owns in the Oyo field offshore Nigeria. This evaluation was completed on December 5, 2014. Camac has represented that this
property accounts for 100 percent, on a net equivalent barrel basis, of Camac’s net proved reserves as of January 1, 2014. The net
proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X
of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines
specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Camac.
Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be
produced from these properties after December 31, 2014. Net reserves are defined as that portion of the gross reserves attributable to
the interests owned by Camac after deducting interests owned by others. The field evaluated herein is located in Oil Mining License
(OML) 120 and is subject to a production sharing contract (PSC). The terms of this contract generally allow for working interest
participants to be reimbursed operating expenses, capital costs, abandonment costs, and other costs from a percentage of gross annual
revenue. The reimbursements and profit proceeds net to the interests evaluated herein, based on its working interest share, are
converted to a volumetric equivalent by dividing by product prices to determine the net “entitlement quantities.” These quantities are
equivalent, in principle, to net reserves. The ratio of the net quantities to gross quantities is termed “entitlement interest.”
Values shown herein are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue
is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net
revenue is calculated by deducting estimated production taxes, operating expenses, and capital costs from the future gross revenue.
Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that
directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates.
Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected
period of realization.
Estimates of oil reserves and future net revenue should be regarded only as estimates that may change as further production
history and additional information become available. Not only are such reserves and revenue estimates based on that information
which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in
interpreting such information.
Data used in this evaluation were obtained from reviews with Camac personnel, Camac files, from records on file with the
appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent
verification, upon such information furnished by Camac with respect to property interests, production from such properties, current
costs of operation and development, current prices for production, agreements relating to current and future operations and sale of
production, and various other information and data that were accepted as represented. A field examination of the properties was not
considered necessary for the purposes of this report.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and
techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the
Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information
(Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by
experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
When applicable, the volumetric method was used to estimate the original oil in place (OOIP). Structure and isopach maps were
constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to
prepare these maps as well as to estimate representative values for porosity and water saturation.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP. These recovery factors were based on
consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and
the production histories. When applicable, other engineering methods were used to estimate recovery factors. In such cases, an
analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation
of reserves.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other
diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships.
In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the
production licenses as appropriate.
In certain cases, elements of the reserves estimates incorporated information based on analogy with similar reservoirs where
more complete data were available.
Definition of Reserves
Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report.
Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X
of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and
operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment.
In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing
economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of
changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The
petroleum reserves are classified as follows:
Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward,
from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the
time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the
reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil
or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons
(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology
establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetration has defined a highest known oil (HKO) elevation and the potential
exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir
only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable
certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but
not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir
as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using
reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was
based; and (B) The project has been approved for development by all necessary parties and entities, including
governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered
by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within
such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be
recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment
is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the
extraction is by means not involving a well.
Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for
recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are
reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable
certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted
indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been
proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a)
Definitions], or by other evidence using reliable technology establishing reasonable certainty.
The extent to which probable and possible reserves ultimately may be recategorized as proved reserves is dependent upon future
drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by
economic and technological factors as well as the time element. No probable or possible reserves have been evaluated for this report.
Primary Economic Assumptions
Oil Price
The price of oil used in this evaluation was based on a 12-month average Brent marker oil price of 108.63 United States
dollars (U.S.$) per barrel, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each
month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual
arrangements. The oil price for the Oyo field was U.S.$107.89 per barrel. The oil price was held constant for the
remaining producing life of the field.
Operating Expenses and Capital Costs
Estimates of future operating expenses were based on current expenses. In certain cases, future expenses, either higher or
lower than current expenses, may have been used because of anticipated changed operating conditions, but no general
escalation that might result from inflation was applied. Future capital expenditures were not escalated for inflation.
Abandonment costs are included and have not been escalated for inflation.
Summary of Oil Reserves and Revenue
The estimates of the net proved reserves, as of January 1, 2014, attributable to the interests owned by Camac in the Oyo field,
are summarized as follows, expressed thousands of barrels (Mbbl):
Estimated by DeGolyer
and MacNaughton
Net Proved Reserves
as of
January 1, 2014
Oil
(Mbbl)
Proved
Developed ................................................................... 321
Undeveloped ............................................................... 8,219
Total Proved ................................................................... 8,540
The estimated future revenue to be derived from the production and sale of the net proved reserves, as of January 1, 2014, of the
properties appraised, expressed in thousands of United States dollars (M U.S.$), is summarized as follows:
Proved
Total
Developed Undeveloped proved
(M U.S.$) (M U.S.$) (M U.S.$)
Future Net Revenue ........................................................ (27,235) 156,840 129,605
Present Worth at 10 Percent ........................................... (23,210) 124,477 101,267
Notes:
1. Future income taxes have not been taken into account in the preparation of these estimates.
2. The future net revenue for proved developed reserves is negative due to abandonment costs.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s
ability to recover its oil reserves, we are not aware of any such governmental actions which would restrict the recovery of the January
1, 2014, estimated proved oil reserves. The reserves estimated in this report can be produced under current regulatory guidelines.
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and
present worth of estimated future net revenue from proved reserves of oil contained in this report has been prepared in accordance
with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the
Accounting Standards Update 932-235-50, Extractive Industries ? Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and
Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4 ?10(a) (1)?(32) of Regulation S?X and Rules
302(b), 1201 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S?K of the Securities and Exchange Commission; provided,
however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth
values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning
of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature,
we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance
therewith or sufficient therefor.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum
consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including
stock ownership, in Camac. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the
request of Camac. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary
and appropriate to prepare this report.
Submitted,
/s/ DeGOLYER and MacNAUGHTON
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
/s/ Lloyd W. Cade, P.E.
Lloyd W. Cade, P.E
Senior Vice President
DeGolyer and MacNaughton
CERTIFICATE of QUALIFICATION
I, Lloyd W. Cade, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas,
Texas, 75244 U.S.A., hereby certify:
1.That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to
Camac dated December 5, 2014, and that I, as Senior Vice President, was responsible for the preparation of this report.
2.That I attended Kansas State University, and that I graduated with a Bachelor of Science degree in Mechnical Engineering in the
year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of
Petroleum Engineers; and that I have in excess of 32 years of experience in oil and gas reservoir studies and reserves evaluations.
SIGNED: December 5, 2014
/s/ Lloyd W. Cade, P.E.
Lloyd W. Cade, P.E
Senior Vice President
DeGolyer and MacNaughton
22 December 2015
Sponsor: Sasfin Capital (a division of Sasfin Bank Limited)
Date: 22/12/2014 07:39:00 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 
