ERIN-6.30.2015.10Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



	FORM 10-Q

(Mark One)



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2015



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 01-34525



	ERIN ENERGY CORPORATION



Delaware		30-0349798
(State or Other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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)

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

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

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

At August 3, 2015, there were 211,501,647 shares of common stock, par value $0.001 per share, outstanding.



PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements:	3

	Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014 (unaudited)	3

	Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014 (unaudited)	4

	Consolidated Statements of Equity for the six months ended June 30, 2015 (unaudited)	5

	Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014 (unaudited)	6

	Notes to Unaudited Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	23

Item 4.	Controls and Procedures	24

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	24

Item 1A.	Risk Factors	24

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25
Item 6.	Exhibits	26

Signatures		27

PART I. – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ERIN ENERGY CORPORATION (formerly CAMAC ENERGY INC.)

CONSOLIDATED BALANCE SHEETS

(Unaudited)

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



	June 30, 2015			December 31, 2014
ASSETS
Current Assets:
Cash and cash equivalents	$	1,041		$	25,143
Restricted cash	7,072			1,496
Accounts receivable - partners	76			496
Accounts receivable - related party	624			624
Accounts receivable - other	105			54
Crude oil inventory	25,223			1,089
Prepaids and other current assets	3,523			2,929
Total current assets	37,664			31,831

Property, plant and equipment:
Oil and gas properties (successful efforts method of accounting), net	705,838			595,269
Other property, plant and equipment, net	1,232			1,060
Total property, plant and equipment, net	707,070			596,329

Other non-current assets:
Restricted cash	—			8,909
Debt issuance costs	1,207			1,307
Other non-current assets	67			67
Other assets, net	1,274			10,283

Total assets	$	746,008		$	638,443

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	180,696		$	108,047
Accounts payable and accrued liabilities - related party	26,523			9,391
Accounts payable - partners	101			—
Asset retirement obligations	—			12,703
Current portion of long-term debt	18,445			6,200
Total current liabilities	225,765			136,341

Long-term notes payable - related party	115,164			61,185
Term loan facility	79,928			93,000
Asset retirement obligations	23,838			13,830
Other long-term liabilities	—			82

Total liabilities	444,695			304,438

Commitments and contingencies

Equity:
Preferred stock $0.001 par value - 50,000,000 shares authorized; none issued and outstanding at June 30, 2015 and December 31, 2014	—			—
Common stock $0.001 par value - 416,666,667 shares authorized; 211,501,647 and 210,307,502 shares outstanding as of June 30, 2015 and December 31, 2014	212			210
Additional paid-in capital	787,722			778,095
Accumulated deficit	(487,175		)	(444,954		)
Total equity - Erin Energy Corporation	300,759			333,351
Non-controlling interests	554			654
Total equity	301,313			334,005
Total liabilities and equity	$	746,008		$	638,443

See accompanying notes to unaudited consolidated financial statements.

ERIN ENERGY CORPORATION (formerly CAMAC ENERGY INC.)

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Revenues:
Crude oil sales, net of royalties	$	—		$	14,940		$	—		$	34,834

Operating costs and expenses:
Production costs	(5,616		)	15,459			15,712			38,356
Workover expenses	618			—			618			—
Exploratory expenses	1,502			427			8,017			2,703
Depreciation, depletion and amortization	422			5,985			1,119			10,956
Loss on settlement of asset retirement obligations	3,454			—			3,454			—
General and administrative expenses	5,441			4,340			8,932			8,773
Total operating costs and expenses	5,821			26,211			37,852			60,788

Operating loss	(5,821		)	(11,271		)	(37,852		)	(25,954		)

Other income (expense):
Currency transaction gain	555			32			1,991			32
Interest expense	(4,224		)	(681		)	(6,835		)	(866		)
Other, net	—			(10		)	—			—
Total other income (expense)	(3,669		)	(659		)	(4,844		)	(834		)

Loss before income taxes	(9,490		)	(11,930		)	(42,696		)	(26,788		)
Income tax expense	—			—			—			—
Net loss before non-controlling interest	(9,490		)	(11,930		)	(42,696		)	(26,788		)

Net loss attributable to non-controlling interest	328			—			475			—

Net loss attributable to Erin Energy Corporation	$	(9,162	)	$	(11,930	)	$	(42,221	)	$	(26,788	)

Net loss per common share:
Basic	$	(0.04	)	$	(0.06	)	$	(0.20	)	$	(0.17	)
Diluted	$	(0.04	)	$	(0.06	)	$	(0.20	)	$	(0.17	)
Weighted average common shares outstanding:
Basic	211,108			198,035			210,791			155,428
Diluted	211,108			198,035			210,791			155,428

See accompanying notes to unaudited consolidated financial statements.

ERIN ENERGY CORPORATION (formerly CAMAC ENERGY INC.)

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In thousands)



	Common Stock		Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Equity
Balance at December 31, 2014	$	210	$	778,095	$	(444,954	)	$	654		$	334,005
Common stock issued	2		1,978		—			—			1,980
Stock based compensation	—		3,165		—			—			3,165
Warrants issued with debt	—		4,484		—			—			4,484
Funding from non-controlling interest	—		—		—			375			375
Net loss	—		—		(42,221		)	(475		)	(42,696		)
Balance at June 30, 2015	$	212	$	787,722	$	(487,175	)	$	554		$	301,313

See accompanying notes to unaudited consolidated financial statements.

ERIN ENERGY CORPORATION (formerly CAMAC ENERGY INC.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)



	Six Months Ended June 30,
	2015			2014
Cash flows from operating activities
Net loss, including non-controlling interest	$	(42,696	)	$	(26,788	)

Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization	243			10,066
Accretion of asset retirement obligations	876			890
Amortization of debt discount and debt issuance costs	1,119			—
Loss on settlement of asset retirement obligations	3,454			—
Foreign currency transaction gain	(1,991		)	—
Share-based compensation	3,434			1,394
Payments to settle asset retirement obligations	(16,441		)	—
Change in operating assets and liabilities:
Decrease (increase) in accounts receivable	470			(13,161		)
Decrease (increase) in inventories	(9,861		)	4,144
Increase in prepaids and other current assets	(1,234		)	(10,579		)
Increase in accounts payable and accrued liabilities	34,653			8,648
Net cash used in operating activities	(27,974		)	(25,386		)

Cash flows from investing activities
Capital expenditures	(56,741		)	(22,179		)
Allied transaction	—			(170,000		)
Net cash used in investing activities	(56,741		)	(192,179		)

Cash Flows from Financing Activities
Proceeds from the issuance of common stock	—			270,000
Proceeds from exercise of stock options and warrants	1,855			415
Proceeds from notes payable - related party, net	57,815			650
Allied transaction adjustments	—			(13,921		)
Funding from non-controlling interest	375			—
Net cash provided by financing activities	60,045			257,144

Effect of exchange rate changes on cash and cash equivalents	568			—

Net increase (decrease) in cash and cash equivalents	(24,102		)	39,579
Cash and cash equivalents at beginning of period	25,143			163
Cash and cash equivalents at end of period	$	1,041		$	39,742

Supplemental cash flow information
Cash paid for:
Interest, net	$	4,927		$	8
Non-cash investing and financing activities:
Issuance of common shares for settlement of liabilities	$	125		$	—
Discount on notes payable pursuant to issuance of warrants	$	4,484		$	—
Related party accounts payable, net, settled with related party accounts receivable	$	—		$	14,129
Reduction in accounts payable from settlement of Northern Offshore contingency	$	24,307		$	—

See accompanying notes to unaudited consolidated financial statements.

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Company Description

Erin Energy Corporation (NYSE MKT: ERN; JSE: ERN), formerly CAMAC Energy, Inc., is 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 offshore Nigeria and conducts exploration activities offshore Nigeria, onshore and offshore Kenya, offshore The Gambia, and offshore Ghana.

In April 2015, the Company changed its name to Erin Energy Corporation from CAMAC Energy Inc. The Company is headquartered in Houston, Texas and has offices in Lagos, Nigeria, Nairobi, Kenya, Banjul, The Gambia, Accra, Ghana and Johannesburg, South Africa.

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

The Company also conducts certain business transactions with its majority shareholder, CAMAC Energy Holdings Limited (“CEHL”), and its affiliates, which include Allied Energy Plc. (“Allied”). See Note 8 - Related Party Transactions for further information.

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

2. Basis of Presentation and Recently Issued Accounting Standards

The accompanying unaudited 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 unaudited 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. This Form 10-Q should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on March 16, 2015.

Reverse Stock Split

Effective April 22, 2015, the Company implemented a reverse stock split, whereby each six shares of outstanding common stock pre-split was converted into one share of common stock post-split (the “reverse stock split”). All share and per share amounts for all periods presented herein have been adjusted to reflect the reverse stock split as if it had occurred at the beginning of the first period presented.

Use of Estimates

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

Estimates that may have a significant effect on the Company’s financial position and results from operations include share-based compensation assumptions, oil and natural gas reserve quantities, depletion and amortization relating to oil and natural gas

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

properties, asset retirement obligation assumptions, and income taxes. The accounting estimates used in the preparation of the Company's consolidated financial statements may change as new events occur, more experience is acquired, additional information is obtained and our operating environment changes.

Capitalized Interest

The Company capitalizes interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production, and interest costs have been incurred. The capitalization period continues as long as these events occur. Capitalized interest is added to the cost of the underlying assets and is depleted using the unit-of-production method in the same manner as the underlying assets.

During the six months ended June 30, 2015 and 2014, the Company capitalized $2.2 million and $0.2 million, respectively, in interest cost as additions to property, plant and equipment related to the Oyo field redevelopment campaign.

Net Earnings (Loss) Per Common Share

Basic net earnings or loss per common share is computed by dividing net earnings or loss by the weighted average number of shares of common stock outstanding at the end of the reporting period. Diluted net earnings or loss per share is computed by dividing net earnings or loss by the fully diluted common stock equivalent, which consists of shares outstanding, augmented by potentially dilutive shares issuable upon the exercise of stock options, unvested restricted stock awards, warrants, and conversion of the Convertible Subordinated Note, calculated using the treasury stock method.

The table below sets forth the number of shares issuable pursuant to stock options, unvested restricted stock awards, and shares issuable upon conversion of the Convertible Subordinated Note that were excluded from diluted shares outstanding during the three and six months ended June 30, 2015 and 2014, as these securities are anti-dilutive because the Company was in a loss position for each period.



	Three Months Ended June 30,		Six Months Ended June 30,
(In thousands)	2015	2014	2015	2014
Stock options	1,476	1,189	1,119	1,216
Stock warrants	1,046	—	426	—
Unvested restricted stock awards	1,348	1,076	1,324	977
Convertible note	11,632	11,632	11,632	8,355
	15,502	13,897	14,501	10,548

Upon the occurrence of certain events, the Company is also contingently liable to make additional payments to Allied, under the Transfer Agreement, up to an additional amount totaling $50.0 million in cash, or the equivalent in shares of the Company’s common stock, at Allied’s option. See Note 9 - Commitments and Contingencies for further information.

Fair Value of Financial Instruments

The Company measures assets and liabilities at fair value based on an expected exit price as defined by the authoritative guidance on fair value measurements. Fair value is the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between willing market participants at the measurement date.

The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, restricted cash, accounts receivable, inventory, deposits, accounts payable and accrued liabilities, and debts at floating interest rates, approximate their fair values at June 30, 2015, and December 31, 2014, respectively, principally due to the short-term nature, maturities or nature of interest rates of the above listed items.

Recently Issued Accounting Standards

In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-01, Income Statement - Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

the Concept of Extraordinary Items. ASU No. 2015-01 eliminates from US GAAP the concept of extraordinary items, and is effective for fiscal years beginning after December 15, 2015. The Company will adopt this standards update, as required, beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. ASU No. 2015-02 is effective for interim and annual periods beginning after December 15, 2015, and the Company will adopt this standards update, as required, beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which is guidance for the reporting of debt issuance costs related to a recognized debt liability on an entity's balance sheet. Under the guidance, an entity must report debt issuance costs as a direct deduction from the carrying amount of that debt liability, consistent with the treatment for debt discounts. ASU No. 2015-03 is effective for interim and annual periods beginning after December 15, 2015; early adoption is permitted for financial statements that have not been previously issued. The Company will adopt this standards update beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-05, Intangibles - Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in Cloud Computing Arrangement. ASU 2015-05 is new guidance to help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement. ASU No. 2015-05 is effective for interim and annual periods beginning after December 15, 2015, and the Company will adopt this standards update, as required, beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In May 2015, the FASB issued ASU No. 2015-08, Business Combinations (Topic 805): Pushdown Accounting - Amendments to SEC Paragraphs Pursuant to Staff Accounting Bulletin No. 115. The amendments in ASU 2015-08 amend various SEC paragraphs included in the FASB’s Accounting Standards Codification to reflect the issuance of Staff Accounting Bulletin No. 115 (“SAB 115”). SAB 115 rescinds portions of the interpretive guidance included in the SEC’s Staff Accounting Bulletins series and brings existing guidance into conformity with ASU No. 2014-17, “Business Combinations (Topic 805): Pushdown Accounting,” which provides an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The Company has adopted the amendments in ASU 2015-08, effective May 8, 2015, as the amendments in the update are effective upon issuance. The adoption did not have an impact on the Company's consolidated financial statements.

3. Liquidity Matters

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

Crude oil production is a primary source of operating cash for the Company. The Company commenced production from the Oyo-8 well in early May 2015 and from the Oyo-7 well in mid-June 2015. After a period of retooling and optimization, the current combined production rate from the two wells is approximately 13,100 barrels of oil per day ("BOPD") (approximately 11,500 BOPD net to the Company after royalty). In July 2015, the Company lifted and sold approximately 312,000 Bbls of crude oil (274,000 Bbls net to the Company) at a price of $55.78/Bbls. Net proceeds to the Company were approximately $15.3 million. Further, the Company expects to sell approximately 650,000 Bbls of crude oil in August 2015 (572,000 Bbls net to the Company). If actual production rates decline substantially below anticipated rates, or if oil prices decline significantly from current levels, the Company may need to seek additional sources of capital.

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

2015 Convertible Note was $44.0 million. Subsequent to June 30, 2015, the Company borrowed additional funds totaling $4.0 million under the note. See Note 7 - Debt for additional information.

In May 2015, the Company executed a term sheet for a commodity-based Full Recourse Prepayment Facility (the “Prepayment Facility”) with Glencore Energy UK Ltd. The Prepayment Facility, which is subject to completion of legal documentation and certain conditions precedent, would provide proceeds in two tranches. The initial tranche, a term prepayment facility, would be available to the Company in drawdowns totaling up to $50.0 million towards the Oyo field redevelopment program, and would depend on the Company’s ability to meet certain production targets. The second tranche consists of an inventory revolving facility up to a total of $100.0 million. The Company expects the Prepayment Facility to be finalized during the third quarter of 2015.

In July 2015, the Company received $13.0 million as an advance under a stand-alone spot sales contract with Glencore Energy UK Ltd. (the “July Advance”). Interest accrued on the July Advance at the rate of LIBOR plus 6.5%. Repayment of the July Advance was made from the July crude oil lifting.

In August 2015, the Company received another advance amounting to $26.5 million under a stand-alone spot sales contract with Glencore Energy UK Ltd. (the “August Advance”). Interest accrues on the August Advance at the rate of LIBOR plus 6.5%. Repayment of the August Advance will be made from the August crude oil lifting.

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

4. Property, Plant and Equipment

Property, plant and equipment were comprised of the following:



(In thousands)	June 30, 2015			December 31, 2014
Wells and production facilities	$	319,884		$	33,690
Proved properties	386,196			386,196
Work in progress and other	98,994			261,346
Oilfield assets	805,074			681,232
Accumulated depletion	(109,676		)	(95,403		)
Oilfield assets, net	695,398			585,829
Unevaluated leaseholds	10,440			9,440
Oil and gas properties, net	705,838			595,269

Other property and equipment	2,739			2,324
Accumulated depreciation	(1,507		)	(1,264		)
Other property and equipment, net	1,232			1,060

Total property, plant and equipment, net	$	707,070		$	596,329

All of the Company’s Oilfield assets are located in Nigeria. “Work-in-progress and other” includes ongoing costs for wells that are not yet completed, suspended exploratory well costs, as well as warehouse inventory items purchased as part of the redevelopment plan of the Oyo field.

5. 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 intervals totaling approximately 65 feet, as interpreted by logging-while-drilling (“LWD”) data. Management is making plans to further explore the Miocene formation in future wells. Suspended exploratory well costs were $26.5 million at both June 30, 2015, and December 31, 2014, for the costs related to the Miocene exploratory drilling activities.

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

In August 2014, the Oyo-8 well was drilled to a total vertical depth of approximately 6,059 feet (approximately 1,847 meters) and successfully encountered four new oil and gas reservoirs in the eastern fault block, with total gross hydrocarbon thickness of 112 feet, based on results from the LWD data, reservoir pressure measurement, and reservoir fluid sampling. Management has commenced a detailed evaluation of the results and plans to further explore the Pliocene formation in the eastern fault block and establish the size of the incremental additions. Suspended exploratory well costs were $6.5 million at both June 30, 2015, and December 31, 2014, for the costs related to the Pliocene exploration drilling activities in the eastern fault block.

6. 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 certain oil and gas 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.

On a quarterly basis, the Company reviews the assumptions used to estimate the expected cash flows required to settle the asset retirement obligations, including changes in estimated probabilities, amounts and timing of the settlement of the asset retirement obligations, as well as changes in the legal obligation for each of its properties. Changes in any one or more of these assumptions may cause revisions in the estimated liabilities for the corresponding assets.

The following summarizes changes in the Company’s asset retirement obligations during the six months ended June 30, 2015 (in thousands):



Balance at January 1	$	26,533
Accretion expense	876
Additions	9,416
Loss on settlement of asset retirement obligations	3,454
Cost incurred to settle asset retirement obligations	(16,441		)
Balance at June 30	$	23,838

In April 2015, the Company completed plug and abandonment ("P&A") activities for well Oyo-6 that was previously shut-in. Actual P&A expenditures exceeded estimated P&A liabilities by $3.5 million. Accordingly, the Company recorded a $3.5 million loss on settlement of asset retirement obligations.

The table below shows the current and long-term portions of the Company's asset retirement obligations as of the end of each period:



(In thousands)	June 30, 2015		December 31, 2014
Asset retirement obligations, current portion	—		12,703
Asset retirement obligations, long-term portion	23,838		13,830
	$	23,838	$	26,533

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

7. Debt

Promissory Note – Long-Term (Related Party)

The Company has a $25.0 million borrowing facility under a Promissory Note (the “Promissory Note”) with Allied. Interest accrues on the outstanding principal under the Promissory Note at a rate of the 30-day London Interbank Offered Rate (“LIBOR”) plus 2% per annum, payable quarterly. In March 2015, the Promissory Note was amended to extend the maturity date by one year to July 2016. The entire $25.0 million facility amount can be utilized for general corporate purposes. As of June 30, 2015, the outstanding principal and interest under the Promissory Note was $25.0 million and $0.6 million, respectively.

Convertible Subordinated Note – Long-Term (Related Party)

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

At the election of the holder, the Convertible Subordinated Note is convertible into shares of the Company’s common stock at an initial conversion price of $4.2984 per share, subject to anti-dilution adjustments. The Convertible Subordinated Note is subordinated to the Company’s existing and future senior indebtedness and is subject to acceleration upon an Event of Default (as defined in the Convertible Subordinated Note). The Company may, at its option, prepay the Convertible Subordinated Note in whole or in part, at any time, without premium or penalty, and is subject to mandatory prepayment upon (i) the Company’s issuance of capital stock or incurrence of indebtedness, the proceeds of which the Company does not apply to repayment of senior indebtedness or (ii) any capital markets debt issuance to the extent the net proceeds of such issuance exceed $250.0 million. Allied may assign all or any part of its rights and obligations under the Convertible Subordinated Note to any person upon written notice to the Company. As of June 30, 2015, the outstanding principal and accrued interest under the Convertible Subordinated Note was $50.0 million and $3.7 million, respectively.

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”). 90% of the Term Loan Facility is available in U.S. dollar, while the remaining 10% is available in Nigerian Naira. U.S. dollar borrowings under the Term Loan Facility currently bear interest at the rate of LIBOR plus 10.5%. 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 were used for the further expansion and development of the Oyo field offshore Nigeria.

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. The Company was in compliance with all loan covenants as of June 30, 2015.

Upon executing the Term Loan Facility, the Company paid a $2.1 million commitment fee, which was recorded as debt issuance cost and is being amortized over the life of the Term Loan Facility using the effective interest method. As of June 30, 2015, $1.9 million of the debt issuance cost remain unamortized. For the six months ended June 30, 2015, the Company recognized an unrealized foreign currency gain of $1.6 million on the Naira portion of the loan, reducing the net balance under the Term Loan Facility to $98.4 million. Of this amount, $79.9 million was classified as long-term and $18.5 million as short-term. Accrued interest for the Term Loan Facility was $2.5 million as of June 30, 2015.

2015 Convertible Note (Related Party)

In March 2015, the Company entered into a new borrowing facility with Allied for a Convertible Note (the “2015 Convertible Note”) allowing the Company to borrow up to $50.0 million for general corporate purposes. The 2015 Convertible Note will mature in December 2016. Interest accrues at the rate of LIBOR plus 5%, and is payable quarterly.

The 2015 Convertible Note is convertible into shares of the Company’s common stock upon the occurrence and continuation of an event of default, at the sole option of the holder. The number of shares issuable upon conversion is equal to the sum of the principal amount and the accrued and unpaid interest divided by the conversion price, defined as the volume weighted average of

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

the closing sales prices on the NYSE MKT for a share of common stock for the five complete trading days immediately preceding the conversion date.

As of June 30, 2015, the Company had borrowed $44.0 million under the note and issued to Allied warrants to purchase approximately 2.4 million shares of the Company’s common stock at prices ranging from $2.46 to $7.85 per share. The total fair market value of the warrants amounting to $4.5 million based on the Black-Scholes option pricing model was recorded as a discount from the note, and is being amortized using the effective interest method over the life of the note. As of June 30, 2015, the unamortized balance of the note discount was $3.8 million.

Additional warrants are issuable in connection with future borrowings, with the per share price for those warrants determined based on the market price of the Company’s common stock at the time of such future borrowings. As of June 30, 2015, the Company owed $40.2 million under the 2015 Convertible Note, net of discount. Accrued interest on the 2015 Convertible Note was $0.5 million as of June 30, 2015.

Subsequent to June 30, 2015, the Company borrowed an additional $4.0 million under the 2015 Convertible Note and issued to Allied warrants to purchase approximately 0.2 million shares of the Company's common stock with exercise prices ranging from $3.71 to $3.93 per share.

8. Related Party Transactions

Assets and Liabilities

The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates. The following table sets forth the related party assets and liabilities as of June 30, 2015 and December 31, 2014:



(In thousands)	June 30, 2015		December 31, 2014
Accounts receivable, CEHL	$	624	$	624
Accounts payable and accrued expenses, CEHL	$	26,523	$	9,391
Notes payable - related party, CEHL	$	115,164	$	61,185

As of June 30, 2015 and December 31, 2014, the Company owed $26.5 million and $9.4 million, respectively, to an affiliate primarily for logistical and support services in relation to the Company's oilfield operations in Nigeria, as well as accrued interest on the various notes payable.

As of June 30, 2015, the Company had a long-term note payable balance of $115.2 million owed to an affiliate, consisting of a $50.0 million Convertible Subordinated Note, $25.0 million in borrowings under the Promissory Note, and $40.2 million in borrowings under the 2015 Convertible Note, net of discount. As of December 31, 2014, the Company had a long-term note payable balance of $61.2 million owed to an affiliate, consisting of a $50.0 million Convertible Subordinated Note and $11.2 million in borrowings under the Promissory Note. See Note 7 – Debt for further information relating to the notes payable transactions.

Results from Operations

The table below sets forth a summary of transactions included in the Company's results of operations that were incurred with affiliates during the three and six months ended June 30, 2015 and 2014:



	Three Months Ended June 30,				Six Months Ended June 30,
(In thousands)	2015		2014		2015		2014
Total operating expenses, CEHL	$	2,967	$	3,503	$	4,923	$	4,246
Interest expense, CEHL	$	1,389	$	679	$	2,421	$	856

An affiliate of the Company provides procurement and logistical support services to the Company’s Nigerian operations. In connection therewith, during the three months ended June 30, 2015 and 2014, the Company incurred operating costs amounting to approximately $3.0 million and $3.5 million, respectively, and during the six months ended June 30, 2015 and 2014, the Company incurred operating costs amounting to approximately $4.9 million and $4.2 million, respectively.

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

During the three months ended June 30, 2015 and 2014, the Company incurred interest expense totaling approximately $1.4 million and $0.7 million, respectively, in relation to related party note payables. During the six months ended June 30, 2015 and 2014, the Company and incurred interest expense totaling approximately $2.4 million and $0.9 million, respectively.

9. Commitments and Contingencies

Commitments

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-8 and Oyo-7 in Nigeria. 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. In June 2015, the operator of the FPSO agreed to a price reduction for the operating day rates incurred by the Company for the period from July 2014 to April 2015. This resulted in a $26.0 million reduction in previously accrued production costs. The remaining annual minimum commitment per the terms of the agreement is approximately $48.4 million through 2020.

In December 2014, the Company entered into a short-term drilling contract for the semi-submersible drilling rig Sedco Express to complete the horizontal drilling portion of wells Oyo-7 and Oyo-8. The Company finished completion operations for well Oyo-8 in March 2015, and the drilling rig was released in June 2015 upon successful completion of the Oyo-7 well.

The Company also has commitments related to four production sharing contracts with the Government of the Republic of Kenya (the “Kenya PSCs”), two Petroleum Exploration, Development & Production Licenses with the Republic of The Gambia (the “Gambia Licenses”), and one Petroleum Agreement with the Republic of Ghana. In all cases, the Company entered into these commitments through a subsidiary. To maintain compliance and ownership, the Company is required to fulfill certain minimum work obligations and to make certain payments as stated in each of the Kenya PSCs, the Gambia Licenses, and the Ghana Petroleum Agreement.

Contingencies

Legal Contingencies

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. As of June 30, 2015, and through the filing date of this report, the Company does not believe the ultimate resolution of such actions or potential actions of which the Company is currently aware will have a material effect on its consolidated financial position or results of operations.

On June 28, 2015, the Company, CPL and an affiliate of CEHL, the Company's majority shareholder (collectively, the "Erin Parties") entered into a Settlement Agreement with Northern Offshore International Drilling Company Ltd. ("Northern"), pursuant to which the parties agreed (i) to settle all disputes and release all claims relating to the daywork drilling contract for Northern’s drillship Energy Searcher and (ii) to terminate the arbitration proceedings in London. Under the terms of the Settlement Agreement, neither the Erin Parties nor Northern paid any amounts to the other to settle the disputes, and each party agreed to bear its own legal fees and to share equally the arbitration costs. As a result of the settlement, the Company recorded a reduction in accounts payable and accrued liabilities of approximately $24.3 million.

Contingency under the Allied Transfer Agreement

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

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

approval of a development plan by the Nigerian Department of Petroleum Resources or the date of the first hydrocarbon production in commercial quantities, as applicable.

10. Stock-Based Compensation

Stock Options

During the six months ended June 30, 2015, the Company granted to certain employees options to purchase a total of 133,334 shares of common stock with a three-year vesting period. During the same period, options to purchase 19,510 shares of common stock were forfeited.

During the six months ended June 30, 2015, the Company issued 5,000 shares of common stock as a result of the exercise of stock options.

Stock Warrants

During the six months ended June 30, 2015, in connection with the execution of the 2015 Convertible Note, the Company issued to Allied warrants to purchase approximately 2.4 million shares of the Company’s common stock at exercise prices ranging from$2.46 to $7.85 per share. The warrants are exercisable at any time starting from the date of issuance and have a five-year term.

During the six months ended June 30, 2015, 0.2 million previously issued warrants were forfeited.

During the six months ended June 30, 2015, the Company issued 0.3 million shares of common stock as a result of the exercise of stock warrants for cash proceeds totaling approximately $1.8 million.

Restricted Stock Awards

During the six months ended June 30, 2015, the Company granted officers, directors, and employees a total of approximately 1.1 million shares of restricted common stock with vesting periods varying from immediate vesting to 36 months.

In February 2015, the Company granted performance-based restricted stock awards (PBRSA) to certain officers totaling 0.4 million shares. Each grant will vest if the individuals remain employed three years from the date of grant and the Company achieves specific performance objectives at the end of the designated performance period. Up to 50% additional shares may be awarded if performance objectives are exceeded. None of the PBRSAs will vest if certain minimum performance goals are not met. The performance conditions are based on the Company’s total shareholder return over the performance period compared to an industry peer group of companies. Total estimated compensation expense is $0.4 million over three years.

11. Segment Information

The Company’s current operations are based in Nigeria, Kenya, The Gambia, and Ghana. Management reviews and evaluates the operations of each geographic segment separately. Operations 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).

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Segment activity for the three and six months ended June 30, 2015 and 2014, are as follows:



(In thousands)	Nigeria			Kenya			The Gambia			Ghana			Corporate and Other			Total
Three months ended June 30,
2015
Revenues	$	—		$	—		$	—		$	—		$	—		$	—
Operating income (loss)	$	1,211		$	(555	)	$	(291	)	$	(655	)	$	(5,531	)	$	(5,821	)
2014
Revenues	$	14,940		$	—		$	—		$	—		$	—		$	14,940
Operating income (loss)	$	(6,403	)	$	(83	)	$	(374	)	$	10		$	(4,421	)	$	(11,271	)
Six months ended June 30,
2015
Revenues	$	—		$	—		$	—		$	—		$	—		$	—
Operating loss	$	(21,025	)	$	(6,106	)	$	(662	)	$	(949	)	$	(9,110	)	$	(37,852	)
2014
Revenues	$	34,834		$	—		$	—		$	—		$	—		$	34,834
Operating loss	$	(14,309	)	$	(2,075	)	$	(642	)	$	(6	)	$	(8,922	)	$	(25,954	)

Total assets by segment as of June 30, 2015, and December 31, 2014, are as follows:



(In thousands)	Nigeria		Kenya		The Gambia		Ghana		Corporate and Other		Total
Total Assets
As of June 30, 2015	$	736,498	$	1,422	$	4,291	$	999	$	2,798	$	746,008
As of December 31, 2014	$	609,243	$	8,527	$	2,739	$	1,413	$	16,521	$	638,443

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Our Business

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

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

Our shares are traded on the NYSE MKT and on the Johannesburg Stock Exchange ("JSE") under the symbol “ERN.”

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

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

We conduct certain business transactions with our majority shareholder, CAMAC Energy Holdings Limited (“CEHL”) and its affiliates. See Note 8 - Related Party Transactions to the Notes to Unaudited Consolidated Financial Statements for further information.

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

Nigeria

The Company currently owns 100% of the economic interests in Oil Mining Leases 120 and 121 ("OMLs") offshore Nigeria, which includes the currently producing Oyo field.

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

In March 2015, the Company finished completion operations for well Oyo-8, and successfully hooked it up to the FPSO. Production commenced in May 2015. In April 2015, the Company completed plug and abandonment activities for well Oyo-6, a well that was previously shut-in in 2014. The semi-submersible rig Sedco Express was then mobilized to the Oyo-7 well location to initiate horizontal completion activities for well Oyo-7. The Company commenced production from well Oyo-7 in mid-June 2015. Current combined daily production from both wells is approximately 13,100 BOPD (approximately 11,500 BOPD net to the Company after royalty).

Current plans include the recompletion of previously shut-in well Oyo-5 into a water injection well, and drilling an additional development well to increase production from the Oyo field. Additionally, the Company is making plans to drill one or two exploration wells, depending on capital and rig availability.

Kenya

The Company, through a wholly owned subsidiary, entered into four production sharing contracts with the Government of the Republic of Kenya, covering onshore exploration blocks L1B and L16, and offshore exploration blocks L27 and L28 (the “Kenya PSCs”). Each block requires specific work commitments to be completed by the end of the respective license periods. The Company is the operator of all blocks with the Government having the right to participate up to 20%, either directly or through an appointee, in any area subsequent to declaration of a commercial discovery. The Company is responsible for all exploration expenditures.

The initial exploration period for onshore blocks L1B and L16 ended in June 2015. The Company finished the required 2-D seismic data acquisition in February 2015. The Company has satisfied all material contractual obligations under the initial exploration period for onshore blocks L1B and L16 as of June 30, 2015. In accordance with the provisions of the Kenya PSCs, the Company exercised its right to apply for the First Additional Exploration Period for both blocks, with specified additional minimum work obligations, including the acquisition of seismic data and the drilling of one exploratory well on each block over a two-year period. Following discussions with the Government of the Republic of Kenya, the Company believes that the First Additional Exploration Period for both onshore blocks will be granted.

The initial exploration period for offshore blocks L27 and L28 ended on August 8, 2015. As of the date of this report, the remaining contractual obligation under the initial exploration period is for the Company to acquire, process, and interpret 3-D seismic data over both offshore blocks. The Company plans to pursue completion of the work program, and is also considering the possibility of farming-out a portion of its rights to both offshore blocks to potential partners. Accordingly, the Company has applied for a two-year extension of the Initial Exploration Period for both blocks in order to bring in potential partners and complete the remaining work obligations. Following discussions with the Government of the Republic of Kenya, the Company believes that the extension will be granted to complete the work program. Upon completion of the work program, the Company has the right to apply for up to two additional two-year exploration periods, with specified additional minimum work obligations, including the acquisition of seismic data and the drilling of one exploratory well on each block during each additional period.

The Gambia

The Company, through a wholly owned subsidiary, entered into two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia, for offshore exploration blocks A2 and A5 (the “Gambia Licenses”). Each block requires specific work commitments to be completed by the end of the respective license periods. 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 term of the initial exploration period for both blocks A2 and A5 was extended by two years through December 2018 following an amendment agreement (the "Amendment") entered into with The Republic of the Gambia in May 2015. As of June 30, 2015, the remaining contractual obligations, pursuant to the Amendment, under the Gambia Licenses for both blocks is for the Company to i) acquire, process and interpret 750 square kilometers of 3-D seismic data and ii) drill one exploration well on either block A2 or A5 and evaluate the drilling results. As consideration for the Amendment, the Company agreed to i) pay a $1.0 million extension fee, ii) provide a full well guarantee on either block at such time that the Company enters into a farm-in agreement with a partner, and iii) pay the annual contractual Training and Resources Expenses into a Government of Gambia bank account in The Gambia. The Company intends to pursue completion of the work program, and is also considering the possibility of farming-out a portion of its rights to both blocks to potential partners.

In mid-July 2015, the Company commenced the shooting of a 3-D seismic survey off the coast of The Gambia. The survey is expected to take approximately 50 days to complete and will cover approximately 1,500 square kilometers on the Company's A2 and A5 blocks.

Ghana

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

In January 2015, the Petroleum Agreement became effective, following the signing of a Joint Operating Agreement between the Contracting Parties. The initial exploration period ends in January 2017. The remaining contractual obligations under the initial exploration period are for the Company to i) complete the economic and commercial evaluation of three previously discovered fields within nine months of the effective date of the Petroleum Agreement, ii) reprocess existing 2-D and 3-D seismic data and iii) drill one exploration well.

Work is ongoing to establish the economic viability of the previously discovered fields.

Results of Operations

The following discussion pertains to the Company’s results of operations, financial condition, liquidity and capital resources and should be read together with our unaudited consolidated financial statements and the notes thereto contained in this report, and our audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2014, filed on March 16, 2015 with the SEC.

Three months ended June 30, 2015, compared to three months ended June 30, 2014

Revenues

Revenue is recognized when a lifting (sale) occurs. Crude oil revenues for the three months ended June 30, 2015, were nil, as compared to $14.9 million for the same period in 2014. The two previously producing wells Oyo-5 and Oyo-6 have been shut-in since September 2014 as part of the Oyo field redevelopment campaign. Production resumed in the second quarter of 2015 with the horizontal completion of wells Oyo-7 and Oyo-8. During the three months ended June 30, 2015, the Company sold no oil. For the three months ended June 30, 2014, the Company sold approximately 135,000 net barrels of oil at an average price of $110.40/Bbl.

During the three months ended June 30, 2015 and 2014, the average net daily production from the Oyo field, over the number of days production occurred was approximately 6,700 and 1,600 BOPD, respectively.

Operating Costs and Expenses

Production costs for the three months ended June 30, 2015, were a net credit of $5.6 million, as compared to expenditures of $15.5 million for the same period in 2014. In June 2015, the operator of the FPSO agreed to a price reduction for the operating day rates incurred by the Company for the period from July 2014 to April 2015. This resulted in a $26.0 million reduction in production costs recognized in June 2015, partially offset by higher charges recorded for the FPSO as a result of certain scheduled repairs.

During the three months ended June 30, 2015, the Company spent $0.6 million to repair a control module associated with its well Oyo-4 that is currently operating as a gas injection well. The expenditure was recorded as a workover expense. There were no workover expenses incurred for the three months ended June 30, 2014.

During the three months ended June 30, 2015, the Company incurred $1.5 million of exploration expenses, including $0.5 million spent in Kenya, $0.3 million spent in The Gambia, and $0.7 million spent in Ghana for exploration activities. During the three months ended June 30, 2014, the Company incurred $0.4 million of exploration expenses, which were primarily spent in The Gambia.

Depreciation, depletion and amortization (“DD&A”) expenses, including asset retirement obligation accretion, for the three months ended June 30, 2015, were $0.4 million, as compared to $6.0 million for the same period in 2014. In the three months ended June 30, 2015, oilfield depletion expenses were nil, compared to $5.4 million for the same period in 2014 because there were no oil sales in 2015. The average depletion rate for the three months ended June 30, 2014, was $44.23/Bbl.

In April 2015, the Company completed P&A activities for well Oyo-6 that was previously shut-in. Actual P&A expenditures exceeded estimated P&A liabilities by $3.5 million. Accordingly, the Company recognized a $3.5 million loss on settlement of its asset retirement obligations during the three months ended June 30, 2015. No P&A activity occurred during the same period in 2014.

General and administrative expenses for the three months ended June 30, 2015 were $5.4 million, as compared to $4.3 million in 2014. The increase in 2015 is primarily due to certain severance costs recognized in May 2015.

Other Income (Expense)

Other expense for the three months ended June 30, 2015 was $3.7 million, consisting of $4.2 million in interest expense on borrowings, net of $1.0 million capitalized interest, partially offset by $0.6 million gain on foreign currency transactions. Other expense for the same period in 2014 was $0.7 million, primarily for interest accrued on the related party note payable, net of $0.2 million capitalized interest.

Income Taxes

Income taxes were nil for each of the three months ended June 30, 2015 and 2014. The Company did not have any taxable income from its oil and gas activities in Nigeria in these respective periods.

Six months ended June 30, 2015, compared to six months ended June 30, 2014

Revenues

Revenue is recognized when a lifting (sale) occurs. Crude oil revenues for the six months ended June 30, 2015, were nil, as compared to $34.8 million for the same period in 2014. The two previously producing wells Oyo-5 and Oyo-6 have been shut-in since September 2014 as part of the Oyo field redevelopment campaign. Production resumed in the second quarter of 2015 with the horizontal completion of wells Oyo-7 and Oyo-8. The Company had no oil sales during the six months ended June 30, 2015.

For the six months ended June 30, 2014, the Company sold approximately 397,000 net barrels of oil at an average price of $105.80/Bbl.

During the six months ended June 30, 2015 and 2014, the average net daily production from the Oyo field, over the number of days that production occurred, was approximately 6,700 and 1,600 BOPD, respectively.

Operating Costs and Expenses

Production costs for the six months ended June 30, 2015, were $15.7 million, as compared to $38.4 million for the same period in 2014. In June 2015, the operator of the FPSO agreed to a price reduction for the operating day rates incurred by the Company for the period from July 2014 to April 2015. This resulted in a $26.0 million reduction in production costs recognized in June 2015, partially offset by higher charges for the FPSO in relation to certain scheduled repairs.

During the six months ended June 30, 2015, the Company spent $0.6 million to repair a control module associated with its well Oyo-4 that is currently operating as a gas injection well. The expenditure was recorded as a workover expense. There were no workover expenses incurred for the six months ended June 30, 2014.

During the six months ended June 30, 2015, the Company incurred $8.0 million of exploration expenses, including $5.4 million spent onshore Kenya primarily for the 2-D seismic acquisition and interpretation. In addition, $0.7 million was spent offshore Kenya, $0.7 million in The Gambia, $0.3 million in Nigeria, and $0.9 million in Ghana for exploration activities. During the six months ended June 30, 2014, the Company incurred $2.7 million of exploration expenses, including $0.6 million spent onshore Kenya, $1.5 million spent offshore Kenya, and $0.6 million spent in The Gambia.

DD&A expenses, including asset retirement obligation accretion, for the six months ended June 30, 2015, were $1.1 million, as compared to $11.0 million for the same period in 2014. In the six months ended June 30, 2015, oilfield depletion expenses were nil, compared to $9.8 million for the comparable period in 2014 because there were no oil sales in 2015. The average depletion rate for the six months ended June 30, 2014, was $34.49/Bbl.

In April 2015, the Company completed P&A activities for well Oyo-6 that was previously shut-in. Actual P&A expenditures exceeded estimated P&A liabilities by $3.5 million. Accordingly, the Company recognized a $3.5 million loss on settlement of its asset retirement obligations during the six months ended June 30, 2015. No P&A activity occurred during the same period in 2014.

General and administrative expenses for the six months ended June 30, 2015 were $8.9 million, as compared to $8.8 million in 2014. Higher severance costs recorded in the six months ended June 30, 2015 were partially offset by lower legal and professional services costs incurred in 2015 as compared to 2014 in conjunction with the 2014 Allied Transaction.

Other Income (Expense)

Other expense for the six months ended June 30, 2015, was $4.8 million, consisting of $6.8 million in interest expense on borrowings, net of $2.2 million capitalized interest, partially offset by a $2.0 million gain on foreign currency transactions. Other expense for the same period in 2014 was $0.8 million, primarily for interest accrued on the related party note payable, net of $0.2 million capitalized interest,

Income Taxes

Income taxes were nil for each of the six months ended June 30, 2015 and 2014. The Company did not have any taxable income from its oil and gas activities in Nigeria in these respective periods.

Headline Earnings

In addition to the Company’s primary listing on the New York Stock Exchange, the Company’s common stock is also traded on the JSE. The JSE requires for the Company to file certain documents that it files with the SEC. 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 certain separately identifiable re-measurements, 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 three and six months ended June 30, 2015 and 2014, there were no separate identifiable re-measurements required and headline earnings was the same as net loss per share as disclosed on the unaudited consolidated statements of operations. Therefore, HEPS for the three months ended June 30, 2015 and 2014, were $(0.04) and $(0.06), respectively, and for the six months ended June 30, 2015 and 2014, were $(0.20) and $(0.17), respectively.

Liquidity

Cash Flows from Operating Activities

Cash used in operating activities increased by $2.6 million because of $35.0 million positive changes in working capital, primarily from vendor financing, offset the $15.9 million higher losses from operations, the $16.4 million paid in relation to the P&A activities for well Oyo-6, as well as the $5.2 million lower non-cash adjustments to net income.

Cash Flows from Investing Activities

Cash used in investing activities during the six months ended June 30, 2015, consists of a $56.7 million addition to property, plant and equipment primarily for the ongoing Oyo field redevelopment campaign in the OMLs. The cash used in investing activities for the six months ended June 30, 2014 included $170.0 million paid to Allied as partial consideration for the acquisition of the remaining economic interest in the OMLs and $22.2 million addition to property, plant, and equipment.

Cash Flows from Financing Activities

Net cash provided by financing activities of $60.0 million during the six months ended June 30, 2015, consisted of $1.9 million proceeds from the issuance of common stock arising from warrant and option exercises, $44.0 million borrowings under the 2015 Convertible Note, $13.8 million borrowings under the Promissory Note, and $0.4 million funding received from a related party owning a non-controlling interest in the Company's Ghana subsidiary.

Net cash provided by financing activities for the six months ended June 30, 2014, consisted of $270.0 million investment from the sale of equity, $0.4 million proceeds from the issuance of stock pursuant to employee stock option exercises, and $0.7 million additional borrowings under the Promissory Note, partially offset by a $13.9 million adjustment pursuant to the acquisition of certain assets from Allied.

Capital Resources

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

BOPD net to the Company after royalty). In July 2015, the Company lifted and sold approximately 312,000 Bbls of crude oil (274,000 Bbls net to the Company) at a price of $55.78/Bbls. Net proceeds to the Company were approximately $15.3 million. Further, the Company expects to sell approximately 650,000 Bbls of crude oil in August 2015 (572,000 Bbls net to the Company). If actual production rates decline substantially below anticipated rates, or if oil prices decline significantly from current levels, the Company may need to seek additional sources of capital.

In March 2015, the Company entered into a borrowing facility with Allied for a Convertible Note (the "2015 Convertible Note"), separate from the existing $25.0 million Promissory Note and the $50.0 million Convertible Subordinated Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. As of June 30, 2015, the Company owed $44.0 million under the 2015 Convertible Note. Subsequent to June 30, 2015, the Company borrowed additional funds totaling $4.0 million under the note. See Note 7 - Debt to the Notes to Unaudited Consolidated Financial Statements for additional information.

In July 2015, the Company received $13.0 million as an advance under a stand-alone sales spot contract with Glencore Energy UK Ltd. (the “July Advance”). Interest accrued on the July Advance at the rate of LIBOR plus 6.5%. Repayment of the July Advance was made from the July crude oil lifting.

In August 2015, the Company received $26.5 million as an advance under a stand-alone sales spot contract with Glencore Energy UK Ltd. (the “August Advance”). Interest accrues on the August Advance at the rate of LIBOR plus 6.5%. Repayment of the August Advance will be made from the August crude oil lifting.

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.

Off-Balance Sheet Arrangements

From time-to-time, we may enter into arrangements that can give rise to off-balance sheet obligations. As of June 30, 2015, material off-balance sheet obligations include operating leases for the FPSO and certain employment contracts. Other than the material off-balance sheet arrangements discussed above, no other arrangements are likely to have a current or future material effect on our financial condition, results from operations, liquidity, capital expenditures or capital resources.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “project,” “should,” “will,” “will likely,” or similar expressions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. We caution you not to place undue reliance on any such forward-looking statements, which speak only as of the date made.

Important factors that could affect our financial performance and that could cause actual results for future periods to differ materially from our expectations include, but are not limited to:


•	the supply, demand and market prices of oil and natural gas;


•	our current and future indebtedness;


•	our ability to raise capital to fund our current and future operations;


•	our ability to develop oil and gas reserves;


•	competition from other companies in the energy market;


•	political instability and foreign government regulations over international operations;


•	our lack of diversification of production and reserves;


•	compliance and enforcement of environmental laws and regulations;


•	our ability to achieve profitability;


•	our dependency on third parties to enable us to produce and deliver oil and gas; and


•	other factors disclosed under Item 1. Description of Business, Item 1A. Risk Factors, Item 2. Properties, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2014, and elsewhere in this report.

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

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, please see “Risk Factors” in Item 1A of Part II of this report and in our Annual Report on Form 10-K for the year ended December 31, 2014. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Foreign Currency Exchange Risk

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

The weighted average exchange rate between the U.S. dollar and the Nigerian Naira was 196.45 Naira per each U.S. dollar for the six months ended June 30, 2015. For the six months ended June 30, 2015, a 10% fluctuation in the weighted average exchange rate between the U.S. dollar and the Nigerian Naira would have had an approximate $1.1 million impact on our capital and operating costs in Nigeria.

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

Commodity Price Risk

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

Historically, realized commodity prices received for our crude oil sales have been tied to the Brent oil prices. Prices received have been volatile and unpredictable. As there were no crude oil sales made during the six months ended June 30, 2015, we were not affected by price fluctuations.

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

Interest Rate Risk

We are exposed to changes in interest rates, primarily from possible fluctuations in the London Interbank Borrowing Rate (“LIBOR”). The interest rates on our debt obligations are stated at floating rates tied to the LIBOR. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. For the six months ended June 30, 2015, the weighted average interest rate on our variable rate debt was 15.9%. Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our various debt facilities would result in an increase of our interest expense by $2.2 million over a twelve month period.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management of the Company, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of June 30, 2015. Based on their evaluation, as of the end of the period covered by this Form 10-Q, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There have not been any changes in our internal control over financial reporting during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The disclosures required in this Item 1 are included in Note 9 - Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements included in Part I, Financial Information, Item 1, Financial Statements and incorporated herein by reference.

Item 1A. Risk Factors

There have not been any material changes to the risk factors previously disclosed in Part I, Item 1A of our Annual Report on Form 10-K filed with the SEC on March 16, 2015 for the fiscal year ended December 31, 2014.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

In September 2014, the Company entered into a consulting agreement (the” Agreement”) with a consultant, pursuant to which the consultant has agreed to represent the Company for a term of one-year in investors’ communications and public relations with existing and prospective shareholders, brokers, dealers and other investment professionals with respect to the Company’s current and proposed activities, and to consult with the Company’s management concerning such activities.

As partial consideration under the Agreement, as amended in March 2015, the Company agreed to issue an aggregate of 52,083 shares of the Company’s common stock to the consultant. The Company issued the above shares in reliance on an exemption from registration of the shares provided by Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”), as a transaction by an issuer not involving any public offering.

In March 2015, the Company entered into a borrowing facility with Allied for the 2015 Convertible Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. As of June 30, 2015, the Company has drawn $44.0 million under the note and issued to Allied warrants to purchase approximately 2.4 million shares of the Company’s common stock at prices ranging from $2.46 to $7.85 per share. For further information, see Note 7 - Debt to the Unaudited Consolidated Financial Statements.

Item 6. Exhibits

The following exhibits are filed with this report:



Exhibit Number	Description
3.1	Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 10-SB filed on August 16, 2007).
3.2	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 13, 2010).
3.3	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 19, 2014).
3.4	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 23, 2015).
3.5	Amended and Restated Bylaws of the Company as of April 11, 2011 (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed on May 3, 2011).
10.1	Offer of Employment as Senior Vice President and Chief Financial Officer, dated April 28, 2015, by and between the Company and Christopher J. Hearne (incorporated by reference to Exhibit 10.2 on Form 8-K filed on May 8, 2015).
10.2	Separation Agreement and General Release of Claims, dated May 6, 2015, by and between the Company and Earl W. McNiel (incorporated by reference to Exhibit 10.1 on Form 8-K filed on May 8, 2015).
10.3	Block A2 License Amendment, dated May 25, 2015, by and between the CAMAC Energy Gambia Limited and The Republic of the Gambia (incorporated by reference to Exhibit 10.1 on Form 8-K filed on May 29, 2015).
10.4	Block A5 License Amendment, dated May 25, 2015, by and between the CAMAC Energy Gambia Limited and The Republic of the Gambia (incorporated by reference to Exhibit 10.2 on Form 8-K filed on May 29, 2015).
31.1	Certification of Chief Executive Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101. INS	XBRL Instance Document.
101. SCH	XBRL Schema Document.
101. CAL	XBRL Calculation Linkbase Document.
101. DEF	XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	XBRL Label Linkbase Document.
101. PRE	XBRL Presentation Linkbase Document.

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, thereunto duly authorized.

Erin Energy Corporation

Date: August 10, 2015

/s/ Christopher J. Hearne

Christopher J. Hearne

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)



Date: August 10, 2015		/s/ Dr. Kase Lukman Lawal
		Dr. Kase Lukman Lawal
		Chief Executive Officer (Principal Executive Officer)



Date: August 10, 2015		/s/ Dr. Kase Lukman Lawal
		Dr. Kase Lukman Lawal
		Chief Executive Officer (Principal Executive Officer)

Asset Retirement Obligations - Summary of Change in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Apr. 30, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations beginning balance				$ 26,533
Accretion expense				876	$ 890
Additions				9,416
Loss on settlement of asset retirement obligations	$ 3,500	$ 3,454	$ 0	3,454	$ 0
Cost incurred to settle asset retirement obligations				(16,441)
Asset retirement obligations ending balance		$ 23,838		$ 23,838

Company Description - Related Party (Details)	6 Months Ended
Company Description - Related Party (Details)	Jun. 30, 2015
Chief Executive Officer
Related Party Transaction [Line Items]
Director ownership interest of majority shareholder of the company	27.70%

Commitments and Contingencies - Narrative (Details) $ in Thousands		1 Months Ended		6 Months Ended
	Jun. 28, 2015 USD ($)	Jun. 30, 2015 USD ($)	Feb. 28, 2014 bbl	Jun. 30, 2015 USD ($) contract license	Jun. 30, 2014 USD ($)
Other Commitments [Line Items]
Decrease in accounts payable and accrued liabilities				$ (24,307)	$ 0
Kenya PSCs
Other Commitments [Line Items]
Production sharing contracts \| contract				4
The Gambia
Other Commitments [Line Items]
Development and production licenses \| license				2
Approval by Nigerian Department of Petroleum Resources
Other Commitments [Line Items]
Payment of cash or the equivalent in shares		$ 25,000		$ 25,000
Payment of cash or the equivalent of shares in period				15 days
Number of shares to be issued in period				30 days
Long-term Floating Production Storage and Offloading System Contract
Other Commitments [Line Items]
Initial contract term			7 years
Additional contract term			2 years
Barrels processing capacity \| bbl			40,000
Maximum storage capacity for the FPSO \| bbl			1,000,000
Reduction of accrued production costs		26,000
Minimum commitment, due thereafter		$ 48,400		$ 48,400
Settlement Agreement with Northern
Other Commitments [Line Items]
Decrease in accounts payable and accrued liabilities	$ (24,300)


1.	I have reviewed this Quarterly Report on Form 10-Q of Erin Energy Corporation;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements and other financial information included in this report, fairly present, in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


I,	Dr. Kase Lukman Lawal, certify that:



Date: August 10, 2015		/s/ Christopher J. Hearne
		Christopher J. Hearne Senior Vice President and Chief Financial Officer (Principal Financial Officer)

Related Party Transactions - Summary of Assets and Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Related Party Transactions [Abstract]
Accounts receivable, CEHL	$ 624	$ 624
Accounts payable and accrued expenses, CEHL	26,523	9,391
Long-term notes payable - related party	$ 115,164	$ 61,185

Debt - Term Loan Facility (Details) - USD ($)	1 Months Ended		6 Months Ended
Debt - Term Loan Facility (Details) - USD ($)	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Line of Credit Facility [Line Items]
Foreign currency transaction gain			$ 1,991,000	$ 0
Long-term debt, current			18,445,000		$ 6,200,000
Term Loan Facility
Line of Credit Facility [Line Items]
Debt term		5 years
Maximum borrowing capacity		$ 100,000,000.0
Percent of maximum borrowing capacity available in USD		90.00%
Percent of maximum borrowing capacity available in Naira		10.00%
Line of credit facility, commitment fee amount		$ 2,100,000
Debt issuance, unamortized discount			1,900,000
Foreign currency transaction gain			1,600,000
Long-term debt			98,400,000
Long-term debt, non-current			79,900,000
Long-term debt, current			18,500,000
Interest payable			$ 2,500,000
Term Loan Facility \| London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Basis spread on variable rate	10.50%

Liquidity Matters	6 Months Ended
Liquidity Matters	Jun. 30, 2015
Liquidity Matters [Abstract]
Liquidity Matters	Liquidity Matters The Company’s primary cash requirements are for capital expenditures for the redevelopment of the Oyo field in Nigeria, operating expenditures for the Oyo field, exploration activities in its unevaluated leaseholds, working capital needs, and interest and principal payments under current indebtedness. Crude oil production is a primary source of operating cash for the Company. The Company commenced production from the Oyo-8 well in early May 2015 and from the Oyo-7 well in mid-June 2015. After a period of retooling and optimization, the current combined production rate from the two wells is approximately 13,100 barrels of oil per day ("BOPD") (approximately 11,500 BOPD net to the Company after royalty). In July 2015, the Company lifted and sold approximately 312,000 Bbls of crude oil (274,000 Bbls net to the Company) at a price of $55.78/Bbls. Net proceeds to the Company were approximately $15.3 million. Further, the Company expects to sell approximately 650,000 Bbls of crude oil in August 2015 (572,000 Bbls net to the Company). If actual production rates decline substantially below anticipated rates, or if oil prices decline significantly from current levels, the Company may need to seek additional sources of capital. In March 2015, the Company entered into a borrowing facility with Allied for a Convertible Note (the "2015 Convertible Note"), separate from the existing $25.0 million Promissory Note and the $50.0 million Convertible Subordinated Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. As of June 30, 2015, the outstanding principal under the 2015 Convertible Note was $44.0 million. Subsequent to June 30, 2015, the Company borrowed additional funds totaling $4.0 million under the note. See Note 7 - Debt for additional information. In May 2015, the Company executed a term sheet for a commodity-based Full Recourse Prepayment Facility (the “Prepayment Facility”) with Glencore Energy UK Ltd. The Prepayment Facility, which is subject to completion of legal documentation and certain conditions precedent, would provide proceeds in two tranches. The initial tranche, a term prepayment facility, would be available to the Company in drawdowns totaling up to $50.0 million towards the Oyo field redevelopment program, and would depend on the Company’s ability to meet certain production targets. The second tranche consists of an inventory revolving facility up to a total of $100.0 million. The Company expects the Prepayment Facility to be finalized during the third quarter of 2015. In July 2015, the Company received $13.0 million as an advance under a stand-alone spot sales contract with Glencore Energy UK Ltd. (the “July Advance”). Interest accrued on the July Advance at the rate of LIBOR plus 6.5%. Repayment of the July Advance was made from the July crude oil lifting. In August 2015, the Company received another advance amounting to $26.5 million under a stand-alone spot sales contract with Glencore Energy UK Ltd. (the “August Advance”). Interest accrues on the August Advance at the rate of LIBOR plus 6.5%. Repayment of the August Advance will be made from the August crude oil lifting. The Company’s majority shareholder has formally committed to provide the Company with additional funding, the form of which would be determined at the time of funding, sufficient to maintain the Company’s operations and to allow the Company to meet its current and future obligations as they become due for one year from March 12, 2015, the date of said commitment.

Stock-Based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	6 Months Ended
	Feb. 28, 2015	Jun. 30, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options granted		133,334
Options forfeited		19,510
Common stock exercised on issuance of warrant		2,400,000
Weighted-average remaining contractual term		5 years
Proceeds from the exercise of warrants		$ 1.8
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Warrants exercise price (in dollars per share)		$ 2.46
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Warrants exercise price (in dollars per share)		$ 7.85
Stock Option
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Award vesting period		3 years
Shares of common stock issued during period		5,000
Warrants exercised in period		300,000
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of grants in period		1,100,000
Restricted Stock \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Award vesting period		36 months
Warrant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number forfeited in period		200,000
Senior Officer \| Performance-Based Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Award vesting period	3 years
Number of grants in period	400,000
Maximum percentage of additional shares awarded	50.00%
Estimated compensation expense		$ 0.4
Estimated compensation cost not yet recognized, period of recognition		3 years

Liquidity Matters - Debt (Details)			1 Months Ended
Liquidity Matters - Debt (Details)	Aug. 14, 2015 USD ($)	Mar. 12, 2015	Aug. 07, 2015 USD ($)	Jul. 31, 2015 USD ($)	Jun. 30, 2015 USD ($)	May. 31, 2015 USD ($) tranche	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Line of Credit Facility [Line Items]
Long-term notes payable - related party					$ 115,164,000			$ 61,185,000
Majority Shareholder
Line of Credit Facility [Line Items]
Commitment to additional funding, time period		1 year
Prepayment Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity						$ 50,000,000.0
Line of credit, number of tranches \| tranche						2
Additional borrowing capacity, post-production						$ 100,000,000.0
Line of Credit \| Promissory Note To Allied
Line of Credit Facility [Line Items]
Long-term notes payable - related party					25,000,000			11,200,000
Maximum borrowing capacity					25,000,000.0
Convertible Subordinated Debt
Line of Credit Facility [Line Items]
Long-term notes payable - related party					50,000,000			$ 50,000,000
Convertible Debt \| 2015 Convertible Note
Line of Credit Facility [Line Items]
Long-term notes payable - related party					40,200,000
Maximum borrowing capacity					50,000,000.0		$ 50,000,000.0
Long term debt, gross					$ 44,000,000
Subsequent Event
Line of Credit Facility [Line Items]
Deferred revenue, additions	$ 26,500,000			$ 13,000,000
Subsequent Event \| London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Deferred revenue, basis spread on variable rate	6.50%			6.50%
Subsequent Event \| Convertible Debt \| 2015 Convertible Note
Line of Credit Facility [Line Items]
Proceeds from additional amount borrowed			$ 4,000,000

Liquidity Matters - Production (Details) $ in Thousands	1 Months Ended		3 Months Ended		6 Months Ended
Liquidity Matters - Production (Details) $ in Thousands	Aug. 31, 2015 bbl	Jul. 31, 2015 USD ($) $ / bbl bbl	Jun. 30, 2015 USD ($) well bbl	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($) well bbl	Jun. 30, 2014 USD ($)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Crude oil sales, net of royalties \| $			$ 0	$ 14,940	$ 0	$ 34,834
Crude Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Number of oil wells (in wells) \| well			2		2
Production rates of oil per day (in bbl per day)			13,100		13,100
Production rates of oil per day, net of royalty (in bbl per day)			11,500		11,500
Crude Oil \| Forecast
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Barrels of oil sold (in bbl)	650,000
Barrels of oil sold, net of royalty (in bbl)	572,000
Crude Oil \| Subsequent Event
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Barrels of oil sold (in bbl)		312,000
Barrels of oil sold, net of royalty (in bbl)		274,000
Average sales price (in usd per bbl) \| $ / bbl		55.78
Crude oil sales, net of royalties \| $		$ 15,300

Property, Plant and Equipment - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Wells and production facilities	$ 319,884	$ 33,690
Proved properties	386,196	386,196
Work in progress and other	98,994	261,346
Oilfield assets	805,074	681,232
Accumulated depletion	(109,676)	(95,403)
Oilfield assets, net	695,398	585,829
Unevaluated leaseholds	10,440	9,440
Oil and gas properties, net	705,838	595,269
Other property and equipment	2,739	2,324
Accumulated depreciation	(1,507)	(1,264)
Other property and equipment, net	1,232	1,060
Total property, plant and equipment, net	$ 707,070	$ 596,329

Suspended Exploratory Well Costs - Narrative (Details) $ in Millions	1 Months Ended
	Aug. 31, 2014 reservoir m ft	Nov. 30, 2013 interval ft	Jun. 30, 2015 USD ($)	Dec. 31, 2014 USD ($)
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Number of hydrocarbons miocene formation intervals \| interval		3
Number of feet encountered by hydrocarbons in three intervals, as interpreted by “LWD” data		65
Pliocene formation eastern fault block vertical depth	6,059
Number of pliocene formation eastern fault block new oil and gas reservoirs \| reservoir	4
Hydrocarbons pliocene formation eastern fault block gross thickness	112
Miocene Exploratory Drilling Activities
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Suspended exploratory well cost \| $			$ 26.5	$ 26.5
Pliocene Exploratory Drilling Activity
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Suspended exploratory well cost \| $			$ 6.5	$ 6.5

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current Assets:
Cash and cash equivalents	$ 1,041	$ 25,143
Restricted cash	7,072	1,496
Accounts receivable - partners	76	496
Accounts receivable - related party	624	624
Accounts receivable - other	105	54
Crude oil inventory	25,223	1,089
Prepaids and other current assets	3,523	2,929
Total current assets	37,664	31,831
Property, plant and equipment:
Oil and gas properties (successful efforts method of accounting), net	705,838	595,269
Other property, plant and equipment, net	1,232	1,060
Total property, plant and equipment, net	707,070	596,329
Other non-current assets [Abstract]
Restricted cash	0	8,909
Debt issuance costs	1,207	1,307
Other non-current assets	67	67
Other assets, net	1,274	10,283
Total assets	746,008	638,443
Current Liabilities:
Accounts payable and accrued liabilities	180,696	108,047
Accounts payable and accrued liabilities - related party	26,523	9,391
Accounts payable - partners	101	0
Asset retirement obligations	0	12,703
Current portion of long-term debt	18,445	6,200
Total current liabilities	225,765	136,341
Long-term notes payable - related party	115,164	61,185
Term loan facility	79,928	93,000
Asset retirement obligations, long-term portion	23,838	13,830
Other long-term liabilities	0	82
Total liabilities	$ 444,695	$ 304,438
Commitments and contingencies
Equity:
Preferred stock $0.001 par value - 50,000,000 shares authorized; none issued and outstanding at June 30, 2015 and December 31, 2014	$ 0	$ 0
Common stock $0.001 par value - 416,666,667 shares authorized; 211,501,647 and 210,307,502 shares outstanding as of June 30, 2015 and December 31, 2014	212	210
Additional paid-in capital	787,722	778,095
Accumulated deficit	(487,175)	(444,954)
Total equity - Erin Energy Corporation	300,759	333,351
Non-controlling interests	554	654
Total equity	301,313	334,005
Total liabilities and equity	$ 746,008	$ 638,443

Segment Information - Segment Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Assets	$ 746,008	$ 638,443
Operating Segments \| Nigeria
Segment Reporting Information [Line Items]
Assets	736,498	609,243
Operating Segments \| Kenya
Segment Reporting Information [Line Items]
Assets	1,422	8,527
Operating Segments \| The Gambia
Segment Reporting Information [Line Items]
Assets	4,291	2,739
Operating Segments \| Ghana
Segment Reporting Information [Line Items]
Assets	999	1,413
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Assets	$ 2,798	$ 16,521

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities
Net loss	$ (42,696)	$ (26,788)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization	243	10,066
Accretion of asset retirement obligations	876	890
Amortization of debt discount and debt issuance costs	1,119	0
Loss on settlement of asset retirement obligations	3,454	0
Foreign currency transaction gain	(1,991)	0
Share-based compensation	3,434	1,394
Payments to settle asset retirement obligations	(16,441)	0
Change in operating assets and liabilities:
Decrease (increase) in accounts receivable	470	(13,161)
Decrease (increase) in inventories	(9,861)	4,144
Increase in prepaids and other current assets	(1,234)	(10,579)
Increase in accounts payable and accrued liabilities	34,653	8,648
Net cash used in operating activities	(27,974)	(25,386)
Cash flows from investing activities
Capital expenditures	(56,741)	(22,179)
Allied transaction	0	(170,000)
Net cash used in investing activities	(56,741)	(192,179)
Cash Flows from Financing Activities
Proceeds from the issuance of common stock	0	270,000
Proceeds from exercise of stock options and warrants	1,855	415
Proceeds from notes payable - related party, net	57,815	650
Allied transaction adjustments	0	(13,921)
Funding from non-controlling interest	375	0
Net cash provided by financing activities	60,045	257,144
Effect of exchange rate changes on cash and cash equivalents	568	0
Net increase (decrease) in cash and cash equivalents	(24,102)	39,579
Cash and cash equivalents at beginning of period	25,143	163
Cash and cash equivalents at end of period	1,041	39,742
Cash paid for:
Interest, net	4,927	8
Supplemental disclosure of non-cash investing and financing activities:
Issuance of common shares for settlement of liabilities	125	0
Discount on notes payable pursuant to issuance of warrants	4,484	0
Related party accounts payable, net, settled with related party accounts receivable	0	14,129
Reduction in accounts payable from settlement of Northern Offshore contingency	$ 24,307	$ 0

Debt - Promissory Note (Details) - USD ($)	6 Months Ended
Debt - Promissory Note (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term notes payable - related party	$ 115,164,000	$ 61,185,000
Line of Credit \| Promissory Note To Allied
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 25,000,000.0
Promissory note extended maturity period	1 year
Long-term notes payable - related party	$ 25,000,000	$ 11,200,000
Interest payable	$ 600,000
Line of Credit \| Promissory Note To Allied \| 30-Day London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Basis spread on variable rate	2.00%

Debt - Convertible Subordinated Note (Details) - USD ($)	1 Months Ended
	Feb. 28, 2014	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term notes payable - related party		$ 115,164,000	$ 61,185,000
Convertible Subordinated Debt
Debt Instrument [Line Items]
Convertible subordinate note issued	$ 50,000,000.0
Debt term	5 years
Convertible debt conversion price	$ 4.2984
Minimum proceeds from capital market debt issuance for mandatory prepayment option	$ 250,000,000.0
Long-term notes payable - related party		50,000,000	$ 50,000,000
Interest payable		$ 3,700,000
Convertible Subordinated Debt \| One Month London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	5.00%

Company Description (Details) - Jun. 30, 2015 km² in Thousands, a in Millions	a km² country license
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of exploration and production licenses	9
Number of countries company operates in Africa \| country	4
Area of land held for exploration activities	10

Company Description	6 Months Ended
Company Description	Jun. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Company Description	Company Description Erin Energy Corporation (NYSE MKT: ERN; JSE: ERN), formerly CAMAC Energy, Inc., is 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 offshore Nigeria and conducts exploration activities offshore Nigeria, onshore and offshore Kenya, offshore The Gambia, and offshore Ghana. In April 2015, the Company changed its name to Erin Energy Corporation from CAMAC Energy Inc. The Company is headquartered in Houston, Texas and has offices in Lagos, Nigeria, Nairobi, Kenya, Banjul, The Gambia, Accra, Ghana and Johannesburg, South Africa. The Company’s operating subsidiaries include CAMAC Petroleum Limited (“CPL”), CAMAC Energy Kenya Limited, CAMAC Energy Gambia Ltd., and CAMAC Energy Ghana Limited. The terms “we,” “us,” “our,” “the Company,” and “our Company” refer to Erin Energy Corporation and its subsidiaries. The Company also conducts certain business transactions with its majority shareholder, CAMAC Energy Holdings Limited (“CEHL”), and its affiliates, which include Allied Energy Plc. (“Allied”). See Note 8 - Related Party Transactions for further information. The Company’s Executive Chairman of the Board of Directors, and Chief Executive Officer, is a director of each of the above listed related parties. He indirectly owns 27.7% of CEHL, which is the majority shareholder of the Company. As a result, he may be deemed to have an indirect material interest in transactions contemplated with CEHL and any of its affiliates.

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parentheticals) - $ / shares	Jun. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Preferred stock par value (in Dollars per share)	$ 0.001	$ 0.001
Preferred stock, authorized shares	50,000,000	50,000,000
Preferred stock, issued shares	0	0
Preferred stock, outstanding shares	0	0
Common stock, par value (in Dollars per share)	$ 0.001	$ 0.001
Common stock, authorized shares	416,666,667	416,666,667
Common stock, outstanding shares	211,501,647	210,307,502

Document And Entity Information - shares	6 Months Ended
Document And Entity Information - shares	Jun. 30, 2015	Aug. 03, 2015
Document And Entity Information [Abstract]
Entity Registrant Name	Erin Energy Corp.
Entity Central Index Key	0001402281
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		211,501,647

Basis of Presentation and Recently Issued Accounting Standards (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Basis of Presentation	The accompanying unaudited 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 unaudited 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. This Form 10-Q should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on March 16, 2015.
Use of Estimates	The preparation of the Company's consolidated financial statements in conformity with U.S. GAAP requires management to make estimates based on certain assumptions. Estimates affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenues and expenses attributable to the reporting periods. Accordingly, accounting estimates in conformity with U.S. GAAP require the exercise of judgment. These estimates and assumptions used in the preparation of the Company’s consolidated financial statements are based on information available as of the date of the consolidated financial statements, and while management believes that the estimates and assumptions are appropriate, actual results could differ from management's estimates. Estimates that may have a significant effect on the Company’s financial position and results from operations include share-based compensation assumptions, oil and natural gas reserve quantities, depletion and amortization relating to oil and natural gas properties, asset retirement obligation assumptions, and income taxes. The accounting estimates used in the preparation of the Company's consolidated financial statements may change as new events occur, more experience is acquired, additional information is obtained and our operating environment changes.
Interest Capitalization	The Company capitalizes interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production, and interest costs have been incurred. The capitalization period continues as long as these events occur. Capitalized interest is added to the cost of the underlying assets and is depleted using the unit-of-production method in the same manner as the underlying assets.
Net Earnings (Loss) Per Common Share	Basic net earnings or loss per common share is computed by dividing net earnings or loss by the weighted average number of shares of common stock outstanding at the end of the reporting period. Diluted net earnings or loss per share is computed by dividing net earnings or loss by the fully diluted common stock equivalent, which consists of shares outstanding, augmented by potentially dilutive shares issuable upon the exercise of stock options, unvested restricted stock awards, warrants, and conversion of the Convertible Subordinated Note, calculated using the treasury stock method.
Fair Value of Financial Instruments	The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, restricted cash, accounts receivable, inventory, deposits, accounts payable and accrued liabilities, and debts at floating interest rates, approximate their fair values at June 30, 2015, and December 31, 2014, respectively, principally due to the short-term nature, maturities or nature of interest rates of the above listed items.
Recently Issued Accounting Standards	In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-01, Income Statement - Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. ASU No. 2015-01 eliminates from US GAAP the concept of extraordinary items, and is effective for fiscal years beginning after December 15, 2015. The Company will adopt this standards update, as required, beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements. In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. ASU No. 2015-02 is effective for interim and annual periods beginning after December 15, 2015, and the Company will adopt this standards update, as required, beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which is guidance for the reporting of debt issuance costs related to a recognized debt liability on an entity's balance sheet. Under the guidance, an entity must report debt issuance costs as a direct deduction from the carrying amount of that debt liability, consistent with the treatment for debt discounts. ASU No. 2015-03 is effective for interim and annual periods beginning after December 15, 2015; early adoption is permitted for financial statements that have not been previously issued. The Company will adopt this standards update beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-05, Intangibles - Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in Cloud Computing Arrangement. ASU 2015-05 is new guidance to help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement. ASU No. 2015-05 is effective for interim and annual periods beginning after December 15, 2015, and the Company will adopt this standards update, as required, beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements. In May 2015, the FASB issued ASU No. 2015-08, Business Combinations (Topic 805): Pushdown Accounting - Amendments to SEC Paragraphs Pursuant to Staff Accounting Bulletin No. 115. The amendments in ASU 2015-08 amend various SEC paragraphs included in the FASB’s Accounting Standards Codification to reflect the issuance of Staff Accounting Bulletin No. 115 (“SAB 115”). SAB 115 rescinds portions of the interpretive guidance included in the SEC’s Staff Accounting Bulletins series and brings existing guidance into conformity with ASU No. 2014-17, “Business Combinations (Topic 805): Pushdown Accounting,” which provides an acquired entity with an option to apply pushdown accounting in its separate financial statements upon occurrence of an event in which an acquirer obtains control of the acquired entity. The Company has adopted the amendments in ASU 2015-08, effective May 8, 2015, as the amendments in the update are effective upon issuance. The adoption did not have an impact on the Company's consolidated financial statements.

Suspended Exploratory Well Costs	6 Months Ended
Suspended Exploratory Well Costs	Jun. 30, 2015
Extractive Industries [Abstract]
Suspended Exploratory Well Costs	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 intervals totaling approximately 65 feet, as interpreted by logging-while-drilling (“LWD”) data. Management is making plans to further explore the Miocene formation in future wells. Suspended exploratory well costs were $26.5 million at both June 30, 2015, and December 31, 2014, for the costs related to the Miocene exploratory drilling activities. In August 2014, the Oyo-8 well was drilled to a total vertical depth of approximately 6,059 feet (approximately 1,847 meters) and successfully encountered four new oil and gas reservoirs in the eastern fault block, with total gross hydrocarbon thickness of 112 feet, based on results from the LWD data, reservoir pressure measurement, and reservoir fluid sampling. Management has commenced a detailed evaluation of the results and plans to further explore the Pliocene formation in the eastern fault block and establish the size of the incremental additions. Suspended exploratory well costs were $6.5 million at both June 30, 2015, and December 31, 2014, for the costs related to the Pliocene exploration drilling activities in the eastern fault block.