Document And Entity Information - USD ($)	12 Months Ended
Document And Entity Information - USD ($)	Dec. 31, 2017	Mar. 01, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	Erin Energy Corp.
Entity Central Index Key	0001402281
Trading Symbol	ERN
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		215,337,614
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 132,949,914

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 22,134	$ 7,177
Restricted cash	11,694	2,600
Accounts receivable - trade	6,676	0
Accounts receivable - partners	1,779	674
Accounts receivable - related party	2,926	1,956
Accounts receivable - other	67	29
Crude oil inventory	3,604	9,398
Prepaids and other current assets	2,452	872
Total current assets	51,332	22,706
Property, plant and equipment:
Oil and gas properties (successful efforts method of accounting), net	199,402	265,713
Other property, plant and equipment, net	359	716
Total property, plant and equipment, net	199,761	266,429
Other non-current assets
Other non-current assets	35	66
Other assets, net	35	66
Total assets	251,128	289,201
Current liabilities:
Accounts payable and accrued liabilities	277,404	244,963
Accounts payable and accrued liabilities - related party	40,483	29,513
Accounts payable - partners	249	0
Short-term note payable - related party	200	0
Current portion of long-term debt, net	78,183	12,627
Derivative liability	1,799	0
Total current liabilities	398,318	287,103
Long-term notes payable - related party, net	129,830	129,796
Long-term debt, net	61,349	74,446
Asset retirement obligations	24,409	22,476
Total liabilities	613,906	513,821
Commitments and contingencies (Note 10)
Capital deficiency:
Preferred stock $0.001 par value - 50,000,000 shares authorized; none issued and outstanding as of December 31, 2017 and 2016, respectively	0	0
Common stock $0.001 par value - 416,666,667 shares authorized; 215,093,647 and 212,622,218 shares outstanding as of December 31, 2017 and 2016, respectively	215	213
Additional paid-in capital	807,473	792,972
Accumulated deficit	(1,170,184)	(1,018,292)
Treasury stock at cost, 307,843 and 99,932 shares as of December 31, 2017 and 2016, respectively	(945)	(228)
Total deficit - Erin Energy Corporation	(363,441)	(225,335)
Non-controlling interests	663	715
Total capital deficiency	(362,778)	(224,620)
Total liabilities and capital deficiency	$ 251,128	$ 289,201

CONSOLIDATED BALANCE SHEETS (Parentheticals) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred stock par value (in Dollars per share)	$ 0.001	$ 0.001
Preferred stock, authorized shares (in shares)	50,000,000	50,000,000
Preferred stock, issued shares (in shares)	0	0
Preferred stock, outstanding shares (in shares)	0	0
Common stock, par value (in Dollars per share)	$ 0.001	$ 0.001
Common stock, authorized shares (in shares)	416,666,667	416,666,667
Common stock, outstanding shares (in shares)	215,093,647	212,622,218
Treasury stock, shares (in shares)	307,843	99,932

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Crude oil sales, net of royalties	$ 101,173	$ 77,815	$ 68,429
Operating costs and expenses:
Production costs	80,912	94,607	90,079
Crude oil inventory (increase) decrease	2,093	(1,469)	(2,502)
Workover expense (recovery)	(713)	7,860	972
Exploratory expenses	4,577	39,269	16,437
Depreciation, depletion and amortization	55,342	58,051	97,179
Asset retirement obligation accretion	1,933	1,867	1,931
Impairment of oil and gas properties	78,711	645	261,208
Loss on settlement of asset retirement obligations	0	205	3,653
General and administrative expenses	11,053	13,772	15,905
Total operating costs and expenses	233,908	214,807	484,862
Loss on disposal of other property and equipment	148	0	0
Gain on sale of oil and gas properties	(2,348)	0	0
Operating loss	(130,535)	(136,992)	(416,433)
Other income (expense):
Currency transaction gain	5,241	15,674	2,520
Interest expense	(27,656)	(21,924)	(17,986)
Gain on fair value of derivative liability	36	0	0
Total other expense, net	(22,379)	(6,250)	(15,466)
Loss before income taxes	(152,914)	(143,242)	(431,899)
Income tax expense	0	0	0
Net loss before non-controlling interest	(152,914)	(143,242)	(431,899)
Net loss attributable to non-controlling interest	1,022	841	962
Net loss attributable to Erin Energy Corporation	$ (151,892)	$ (142,401)	$ (430,937)
Net loss attributable to Erin Energy Corporation per common share:
Basic (in Dollars per share)	$ (0.71)	$ (0.67)	$ (2.04)
Diluted (in Dollars per share)	$ (0.71)	$ (0.67)	$ (2.04)
Weighted-average common shares outstanding:
Basic (shares)	213,713	212,318	211,616
Diluted (shares)	213,713	212,318	211,616

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net loss, before non-controlling interest	$ (152,914)	$ (143,242)	$ (431,899)
Comprehensive loss	(152,914)	(143,242)	(431,899)
Comprehensive loss attributable to non-controlling interests	1,022	841	962
Comprehensive loss attributable to Erin Energy Corporation	$ (151,892)	$ (142,401)	$ (430,937)

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (CAPITAL DEFICIENCY) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock	Non-controlling Interest
Beginning balance (in shares) at Dec. 31, 2014		210,308,000
Beginning balance at Dec. 31, 2014	$ 334,005	$ 210	$ 778,095	$ (444,954)	$ 0	$ 654
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common stock issued (in shares)		1,308,000
Common stock issued	1,980	$ 2	1,978
Stock-based compensation	4,631		4,631
Warrants issued with debt	4,911		4,911
Non-controlling interest	1,105					1,105
Net loss	(431,899)			(430,937)		(962)
Ending balance at Dec. 31, 2015	(85,267)	$ 212	789,615	(875,891)	0	797
Ending balance (in shares) at Dec. 31, 2015		211,616,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common stock issued (in shares)		1,106,000
Common stock issued	364	$ 1	363
Stock-based compensation	2,941		2,941
Warrants issued with debt	53		53
Transfer to treasury upon vesting of restricted stock, for income taxes	(228)
Non-controlling interest	759
Net loss	(143,242)			(142,401)		(841)
Ending balance at Dec. 31, 2016	$ (224,620)	$ 213	792,972	(1,018,292)	(228)	715
Ending balance (in shares) at Dec. 31, 2016	212,622,218	212,722,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Noncontrolling interest in joint ventures	$ 800
Common stock issued (in shares)		2,679,000
Common stock issued	3,621	$ 2	3,619
Stock-based compensation	1,932		1,932
Warrants issued with debt	8,950		8,950
Transfer to treasury upon vesting of restricted stock, for income taxes	(717)
Non-controlling interest	970
Net loss	(152,914)			(151,892)		(1,022)
Ending balance at Dec. 31, 2017	$ (362,778)	$ 215	$ 807,473	$ (1,170,184)	$ (945)	$ 663
Ending balance (in shares) at Dec. 31, 2017	215,093,647	215,401,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Noncontrolling interest in joint ventures	$ 1,000

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities
Net loss, before non-controlling interest	$ (152,914)	$ (143,242)	$ (431,899)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation, depletion and amortization	55,342	58,051	97,179
Impairment of oil and gas properties	78,711	645	261,208
Write-off of suspended exploratory well costs	0	33,031	0
Asset retirement obligation accretion	1,933	1,867	1,931
Amortization of debt issuance costs	4,496	3,615	2,766
Loss on settlement of asset retirement obligations	0	0	3,653
Unrealized currency transaction gain	(2,536)	(15,674)	(2,520)
Loss on disposal of other property and equipment	148	0	0
Gain on sale of oil and gas properties	(2,348)	0	0
Gain on fair value of derivative liability	(36)	0	0
Share-based compensation	1,932	2,941	5,027
Payments to settle asset retirement obligations	0	0	(16,640)
Settlement of accounts payable and accrued expenses	(10,189)	0	0
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(3,492)	630	(804)
(Increase) decrease in crude oil inventory	2,093	(1,469)	(2,502)
(Increase) decrease in prepaids and other current assets	(1,456)	(187)	746
Increase in accounts payable and accrued liabilities	54,373	66,147	84,000
Net cash provided by operating activities	26,057	6,355	2,145
Cash flows from investing activities
Capital expenditures	(61,015)	(19,293)	(84,039)
Net cash used in investing activities	(61,015)	(19,293)	(84,039)
Cash flows from financing activities
Proceeds from the exercise of stock options and warrants	0	364	1,855
Payments for treasury stock arising from withholding taxes upon restricted stock vesting and exercise of stock options	(717)	(228)	0
Proceeds from MCB Finance Facility	65,736	0	0
Repayments of MCB Finance Facility	(141)	0	0
Proceeds from JSC 2017 Note	11,687	0	0
Repayments of term loan facility	(9,101)	(5,968)	(337)
Proceeds from note payable - related party, net	0	6,829	61,815
Proceeds from short-term note payable	0	504	0
Proceeds from short-term notes payable - related party	200	0	0
Repayment of short-term note payable	0	(449)	0
Debt issuance costs	(8,655)	(1,040)	0
Funds released from restricted cash, net	0	6,061	0
Funds restricted for debt service	(9,094)	0	0
Funding from non-controlling interest	0	0	553
Net cash provided by financing activities	49,915	6,073	63,886
Effect of exchange rate on cash and cash equivalents	0	5,679	1,228
Net increase (decrease) in cash and cash equivalents	14,957	(1,186)	(16,780)
Cash and cash equivalents at beginning of year	7,177	8,363	25,143
Cash and cash equivalents at end of year	22,134	7,177	8,363
Cash paid for:
Interest, net of amounts capitalized	11,022	10,407	11,114
Supplemental disclosure of non-cash investing and financing activities:
Issuance of common shares for settlement of liabilities	3,527	0	125
Discount on notes payable pursuant to issuance of warrants	10,785	53	4,911
Reduction in oil and gas properties arising from settlement of accounts payable and accrued liabilities	11,478	10,048	0
Reduction in accounts payable from settlement of Northern Offshore contingency	0	0	24,307
Receivable from non-controlling interest	0	0	552
Shares issued for services	93	0	0
Change in asset retirement obligation estimate	$ 0	$ 0	$ (4,284)

Company Description	12 Months Ended
Company Description	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Company Description	COMPANY DESCRIPTION Erin Energy Corporation (NYSE American: ERN, JSE: ERN) is an independent exploration and production company engaged in the acquisition and development of energy resources in Africa. The Company’s asset portfolio consists of five licenses across three countries covering an area of approximately 6,000 square kilometers (approximately 1.5 million acres). The Company owns producing properties and conducts exploration activities offshore Nigeria, and conducts exploration activities offshore Ghana and The Gambia. The Company is headquartered in Houston, Texas and has offices in Lagos, Nigeria, Nairobi, Kenya, and Accra, Ghana. The Company’s operating subsidiaries include Erin Petroleum Nigeria Limited (“EPNL”), Erin Energy Kenya Limited, Erin Energy Gambia Ltd., and Erin 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 related parties. See Note 9. — Related Party Transactions for further information. On February 16, 2017, Babatunde (Segun) Omidele informed the Company that he will be resigning from service as a member of the Board of Directors and as the Chief Executive Officer of the Company. The Board accepted his resignation effective as of February 22, 2017. The Board appointed Jean-Michel Malek, the Company’s Senior Vice President, General Counsel and Secretary, to serve as Interim Chief Executive Officer effective February 22, 2017 while the Board conducted a search for a permanent replacement for Mr. Omidele. Effective on May 18, 2017, the Board appointed Sakiru Adefemi (Femi) Ayoade as the Company’s Chief Executive Officer to replace the then Interim Chief Executive Officer, Jean-Michel Malek. Changes in Control during 2017 The Company was advised by Oltasho Nigeria Limited (“Oltasho”) and Latmol Investment Limited (“Latmol”) that on (a) April 3, 2017, an aggregate of 116,108,833 shares of the Company’s common stock previously held by Allied were transferred to Oltasho; and (b) April 13, 2017, an aggregate of 1,515,927 shares of the Company’s common stock previously held by CAMAC Int’l (Nigeria) Ltd. (“CAMAC International”), were transferred to Latmol. Prior to April 2017, the shares of common stock previously held by Allied and CAMAC International were beneficially owned by Dr. Kase Lawal, the Company’s former Chairman and former Chief Executive Officer, due to his ownership of equity interests in such entities and voting and dispositive control over the securities held by such entities. The shares transferred to Oltasho and Latmol represented approximately 54.6% of the Company’s outstanding voting shares (53.9% owned by Allied and 0.7% owned by CAMAC International) as of the dates of transfer and as such, represented a change in control of the Company. The Company has been advised that the shares held by Oltasho are beneficially owned by Alhaji Murhi Busari, its Chairman, and the shares held by Latmol are beneficially owned by Alhaji Murhi Busari, its Chairman. On July 5, 2017, Oltasho and Latmol entered into a Voting Agreement with Dr. Lawal (the “Voting Agreement”) resulting in another change in control of the Company. Pursuant to the Voting Agreement, Oltasho and Latmol provided complete authority to Dr. Lawal to vote the 117,624,760 shares foreclosed upon (and any other securities of the Company obtained by Oltasho and/or Latmol in the future) at any and all meetings of stockholders of the Company and via any written consents. Those 117,624,760 shares represent approximately 54.6% of the Company’s common stock as of the parties’ entry into the Voting Agreement. The Voting Agreement has a term of approximately 10 years, through July 31, 2027, but can be terminated at any time with the mutual consent of the parties. In connection with their entry into the Voting Agreement, Oltasho and Latmol each provided Dr. Lawal an irrevocable voting proxy to vote the shares covered by the Voting Agreement. Additionally, during the term of such agreement, Oltasho and Latmol agreed not to transfer the shares covered by the Voting Agreement except pursuant to certain limited exceptions. According to the Voting Agreement, Oltasho and Latmol have no desire to control the Company and believe that voting control of the Company was best determined by Dr. Lawal, a United States resident, who has extensive knowledge of United States laws and the assets and operations of the Company, as Dr. Lawal was, until he retired in 2015, the Chairman and Chief Executive Officer of the Company. Due to the Voting Agreement, Dr. Lawal will continue to hold voting control over the Company. These change in control events had no accounting impact on the Company.

Basis of Presentation and Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies

BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned direct and indirect subsidiaries, and have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). All significant intercompany transactions and balances have been eliminated in consolidation. The consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the consolidated financial position and results of operations for the indicated periods. All such adjustments are of a normal recurring nature.

Significant Accounting Policies

Principles of Consolidation

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

Use of Estimates

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

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

Cash and Cash Equivalents

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

Restricted Cash

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

Restricted cash as of December 31, 2017 totaling $11.7 million consists of $2.6 million held in a debt service reserve account to secure certain interest and principal repayments pursuant to the Term Loan Facility in Nigeria and $9.1 million held in a debt service account as required under the MCB Finance Facility (see Note 8 - Debt - Long-Term Debt) for further information and definitions of the Term Loan Facility and MCB Finance Facility). Restricted cash as of December 31, 2016 consists of $2.6 million held in a debt service reserve account to secure certain interest and principal repayments pursuant to the Term Loan Facility in Nigeria.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are accounted for at cost less allowance for doubtful accounts. The Company establishes provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2017 and 2016, no allowance for doubtful accounts was necessary.

As of December 31, 2017 and 2016, the Company had a trade receivable balance of $6.7 million and nil, respectively.

Partner accounts receivable consist of balances owed from joint venture (“JV”) partners. As of December 31, 2017 and 2016, the Company was owed $1.8 million and $0.7 million, respectively, from its Ghana JV partners for their share of the expenditures incurred in the Shallow Water Tano block, pursuant to the Ghana JV Joint Operating Agreement.

Crude Oil Inventory

Inventories of crude oil are valued at the lower of cost or net realized value using the first-in, first-out method and include certain costs directly related to the production process and depletion, depreciation and amortization attributable to the underlying oil and gas properties. The Company had crude oil inventory of $3.6 million and $9.4 million as of December 31, 2017 and 2016, respectively.

Successful Efforts Method of Accounting for Oil and Gas Activities

The Company follows the successful efforts method of accounting for its costs of acquisition, exploration and development of oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Drilling costs of exploratory wells are capitalized pending determination that proved reserves have been found. If the determination is dependent upon the results of planned additional wells and require additional capital expenditures to develop the reserves, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well as a producing well, and additional wells are underway or firmly planned to complete the evaluation of the well. Exploratory wells not meeting the criteria for continued capitalization are expensed when such a determination is made. Other exploration costs are expensed as incurred.

A portion of the Company’s oil and gas properties include oilfield materials and supplies inventory to be used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or net realized value, which approximates fair value, and they are regularly assessed for obsolescence. Oilfield materials and supplies inventory balances were $36.7 million and $34.7 million at December 31, 2017 and 2016, respectively.

Depreciation, depletion and amortization costs for productive oil and gas properties are recorded on a unit-of-production basis. For other depreciable property, depreciation is recorded on a straight-line basis over the estimated useful life of the assets, which range between three to five years, or the lease term if shorter. Repairs and maintenance charges, including workover costs, are charged to expense as incurred.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets in property, plant and equipment for impairment each reporting period, or whenever changes in circumstances indicate that the carrying amount of assets may not be fully recoverable. Possible indicators of impairment include lower expected future oil and gas prices, actual or expected future development or operating costs significantly higher than previously anticipated, significant downward oil and gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable.

An impairment loss is recognized for proved properties when the estimated undiscounted future cash flows expected to result from the asset are less than its carrying amount. The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset. The Company’s cash flow projections into the future include assumptions on variables, such as future sales, sales prices, operating costs, economic conditions, market competition and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount over the fair value of the assets.

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

Asset Retirement Obligations

The Company accounts for asset retirement obligations in accordance with applicable accounting guidelines, which require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. Specifically, the Company records a liability for the present value, using a credit-adjusted risk free interest rate, of the estimated site restoration costs with a corresponding increase to the carrying amount of the related long-lived asset.

Revenues

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

Income Taxes

The Company accounts for income taxes using the asset and liability method of accounting for income taxes in accordance with applicable accounting rules. Under the asset and liability method, deferred tax assets and liabilities are recognized for temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting purposes and for operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets to their net realizable amounts if it is more likely than not that the related tax benefits will not be fully realized.

The Company routinely evaluates any tax deduction and tax refund position in a two-step process. The first step is to determine whether it is more likely than not that a tax position will be sustained. If that test is met, the second step is to determine the amount of benefit or expense to recognize in the consolidated financial statements. See Note 12. — Income Taxes for further information.

Debt Issuance Costs

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

As of December 31, 2017 and 2016, unamortized debt issuance costs were $17.3 million and $2.3 million, of which $6.5 million and $1.6 million was classified as long-term, respectively. The current portion of the debt issuance costs, which was $10.8 million and $0.8 million as of December 31, 2017 and 2016, respectively, is presented as a reduction to the current portion of long-term debt.

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 years ended December 31, 2017 and 2016, the Company capitalized $2.7 million and nil, in interest cost as additions to property, plant and equipment related to the Oyo field redevelopment campaign and costs related to the drilling of an exploratory well in the Miocene formation.

Stock-Based Compensation

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

Treasury Stock

Treasury stock is reported at cost and is included in the accompanying consolidated balance sheets. Pursuant to the Company’s withholding tax policy with respect to vested restricted stock awards, the Company may withhold, on a cashless basis, a number of shares needed to settle statutory withholding tax requirements. During the years ended December 31, 2017 and 2016, 207,911 shares and 99,932 shares were withheld for taxes at a total cost of $0.7 million and $0.2 million, respectively.

The following table sets forth information with respect to the withholding and related repurchases of the Company's common stock during the year ended December 31, 2017.



	Total Number of Shares Purchased (1)	Average Price Paid Per Share
January 1 - January 31, 2017	12,650	$	3.55
February 1 - February 28, 2017	158,264	$	3.82
May 1 - May 31, 2017	33,635	$	1.75
December 1 - December 31, 2017	3,362	$	2.65
Total	207,911	$	3.45



(1)	All shares repurchased were surrendered by employees to settle tax withholding obligations upon the vesting of restricted stock awards and the exercise of stock options. The price paid was the closing price on the dates in which the shares of common stock vested or when the stock options were exercised.



	Total Number of Shares Purchased (1)	Average Price Paid Per Share
January 1 - January 31, 2016	3,643	$	4.02
February 1 - February 29, 2016	62,152	$	2.16
March 1 - March 31, 2016	17,318	$	2.31
May 1 - May 31, 2016	1,072	$	2.48
September 1 - September 30, 2016	6,162	$	2.29
November 1 - November 30, 2016	6,175	$	2.35
December 1 - December 31, 2016	3,410	$	2.10
Total	99,932	$	2.28



(1)	All shares repurchased were surrendered by employees to settle tax withholding obligations upon the vesting of restricted stock awards.

Reporting and Functional Currency

The Company has adopted the U.S. dollar as the functional currency for all of its foreign subsidiaries. Gains and losses on foreign currency transactions and remeasurements are included in results of operations.

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 dilutive common stock equivalent, which consists of shares outstanding, augmented by potentially dilutive shares issuable upon the exercise of the Company’s stock options, stock warrants, non-vested restricted stock awards, and the conversions of the 2011 Promissory Note, 2014 Convertible Subordinated Note and the 2016 Promissory Note (collectively, the "Convertible Notes"), described and defined below under Note 8. - Debt - Long-Term Debt - Related Party), calculated using the treasury stock method.

The table below sets forth the number of stock options, warrants, non-vested restricted stock, and shares issuable upon conversion of Convertibles Notes that were excluded from dilutive shares outstanding during the years ended December 31, 2017, 2016 and 2015, as these securities are anti-dilutive because the Company was in a loss position each year.



	Years Ended December 31,
(In thousands)	2017	2016	2015
Stock options	141	230	1,101
Stock warrants	39	3	541
Unvested restricted stock awards	1,660	1,942	1,275
Convertible Notes	—	—	12,379
	1,840	2,175	15,296

Upon the occurrence of certain events, the Company is also contingently liable to make additional payments to Allied, under the November 2013 Transfer Agreement by the Company and its affiliates, and Allied (the “Transfer Agreement”), up to an additional amount totaling $50.0 million in cash, or the equivalent in shares of the Company’s common stock, at Allied’s option. See Note 10. — Commitments and Contingencies for further information.

Non-Controlling Interests

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

As of December 31, 2017 and 2016, the non-controlling interest recorded in equity was $1.0 million and $0.8 million, respectively, attributable to the joint ownership of an affiliate in our Erin Energy Ghana Limited subsidiary.

Fair Value Measurements

Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. The established framework for measuring fair value establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

There are three levels of valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:


Level 1 -	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an on-going basis.


Level 2 -	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the term, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.


Level 3 -	Inputs that are unobservable and significant to the fair value measurement (including the Company’s own assumptions in determining fair value).

The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

Fair Value on a Recurring Basis

As discussed under Note 8 - Debt, the Company recognized a derivative liability relating to the portion of the amount drawn from the MCB Financing Facility as of December 31, 2017 in which issuance of stock warrants is expected on the day the Company receives funds under the MCB Finance Facility. The Company utilized a combination of a lattice-binomial option-pricing model and the Black-Scholes valuation model to determine the estimated fair value of this derivative liability.

The following table sets forth the Company’s oil and gas properties and derivative liability that is accounted for at fair value using Level 3 assumptions on a recurring basis as of December 31, 2017 and December 31, 2016:



	Level 3
	As of December 31,
(in thousands)	2017
Liabilities:
Warrant Derivative liability	$	1,799

The fair value of the derivative liability is estimated using a combination of a lattice-binomial option-pricing model and the Black-Scholes valuation model with the following assumptions as of December 31, 2017:



	December 31, 2017
Estimated market value of common stock on measurement date	$	2.86
Estimated exercise price	2.86
Risk-free interest rate (1)	2.10		%
Expected warrant term (years)	2.75
Expected volatilities (2)	10.0% - 35.6%
Expected annual dividend yield	—



(1)	The risk-free rate for periods within the contractual life of the warrants is based on the U.S. Treasury yield curve in effect at the time of grant.
(2)	Expected volatilities are based on historical volatility of the Oil & Gas Exploration & Production Select Industries Index, among other factors.

The following table sets forth a reconciliation of changes in the fair value of the Company's financial liability that is accounted for at fair value using Level 3 inputs, and is classified as level 3 in the fair value hierarchy:



	Year ended
(in thousands)	December 31, 2017
Beginning balance	$	—
Loss (gain) on fair value of derivative liability	(36		)
Additions	2,046
Revisions	(211		)
Transfers	—
Ending balance	$	1,799

Change in unrealized loss (gain) included in earnings relating to derivatives still held as of December 31, 2017	$	(36	)

Fair Value on a Non-Recurring Basis

The Company used discounted cash flow techniques to determine the estimated fair value of its oil and gas properties as part of the Company's analysis for impairment. Accordingly, the Company estimated the present value of expected future net cash flows from the Oyo field, discounted using risk-adjusted cost of capital. Significant Level 3 assumptions used in the calculation include the Company's estimate of future crude oil prices, production costs, development costs, and anticipated production of proved reserves, as well as appropriate risk-adjusted probable and possible reserves.

During the year ended December 31, 2017, the Company recorded a non-cash impairment charge of $78.1 million to reduce the carrying value of its oil and gas properties to their estimated fair values. Other than the write-off of the carrying value of its offshore leases in Kenya (as discussed under Note 4 - Property, Plant and Equipment), there was no impairment to the Company's oil and gas properties for the year ended December 31, 2016.

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 December 31, 2017 and 2016, respectively, principally due to the short-term nature, maturities or nature of interest rates of the above listed items.

Risks and Uncertainties

The Company’s producing properties are located offshore Nigeria.

Substantially all of the Company’s crude oil available for sale is sold under spot sales contracts and is delivered Free on Board ("FOB") at the point of transfer from the FPSO, as is customary in the industry.

During the years ended December 31, 2017 and 2016, the Company sold its crude oil under spot sales contracts with one customer. The Company believes that the potential loss of this customer would not prevent it from selling its crude oil, as it will find other buyers for its crude oil.

Reclassification

Certain reclassifications have been made to the 2016 and 2015 consolidated financial statements to conform to the 2017 presentation. These reclassifications were not material to the accompanying consolidated financial statements.

Recently Issued Accounting Standards

In May of 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, Revenue form Contracts with Customers (Topic 606). ASU 2014-09 core principal is that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company has evaluated the impact of this guidance and concluded that this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In February 2016, the Financial Accounting Standards Board FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 is aimed at making leasing activities more transparent and comparable, and requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including leases currently accounted for as operating leases. ASU 2016-02 is effective for the Company in the fiscal year beginning after December 15, 2018, and interim periods within those fiscal years with early adoption permitted. The Company is still evaluating the impact of this standard. However, due to the nature of its operations, the adoption of this standards update could have a material impact on its consolidated financial statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). This ASU clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. The adoption of this standard in the first quarter of 2018 did not have a material impact on the Company’s consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment. ASU 2017-04 eliminates step 2 of the goodwill impairment test. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In February 2017, the FASB issued ASU 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This ASU clarifies the scope and application of ASC 610-20 on the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The Company is required to adopt this guidance at the same time that it adopts the guidance in ASU 2014-09. The adoption of this standard in the first quarter of 2018 did not have a material impact on the Company’s consolidated financial statements.

In March 2017, the FASB issued ASU 2017-08, Receivables-Nonrefundable Fees and Other Costs (Subtopic 310-20), Premium Amortization on Purchased Callable Debt Securities. This ASU shortens the amortization period for certain callable debt securities held at a premium to the earliest call date. However, the amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity. ASU 2017-08 is effective for the Company in the fiscal year beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting, which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. This pronouncement is effective for annual reporting periods beginning after December 15, 2017. Early adoption is permitted. The adoption of this standards update did not have a material impact on the Company’s consolidated financial statements.

In May 2017, the FASB issued ASU No. 2017-10, Service Concession Arrangements (Topic 853): Determining the Customer of the Operation Services. ASU No. 2017-10 provides clarity on determining the customer in a service concession arrangement. ASU No. 2017-10 is effective for interim and annual periods beginning after December 15, 2017, and the Company will adopt this standards update, as required, beginning with the first quarter of 2018. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features. ASU No. 2017-11 amendments simplify the accounting for certain financial instruments with down round features. The amendments require companies to disregard the down round feature when assessing whether the instrument is indexed to its own stock, for purposes of determining liability or equity classification. Companies that provide earnings per share (EPS) data will adjust their basic EPS calculation for the effect of the feature when triggered (i.e., when the exercise price of the related equity-linked financial instrument is adjusted downward because of the down round feature) and will also recognize the effect of the trigger within equity. ASU No. 2017-11 is effective for interim and annual periods beginning after December 15, 2018, and the Company will adopt this standards update, as required, beginning with the first quarter of 2019. The adoption of this standard update is not expected to have a material impact on the Company’s consolidated financial statements.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Improvements to Accounting for Hedging Activities. ASU No. 2017-12 amends and better aligns an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. To meet that objective, the amendments expand and refine hedge accounting for both non-financial and financial risk components and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. ASU No. 2017-12 is effective for interim and annual periods beginning after December 15, 2018, and the Company will adopt this standards update, as required, beginning with the first quarter of 2019. The adoption of this standard update is not expected to have a material impact on the Company’s consolidated financial statements.

In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments in ASU 2018-01 provide an optional transition practical expedient for the adoption of ASU 2016-02 that would not require an organization to reconsider their accounting for existing land easements that are not currently accounted for under the old leases standards. This pronouncement is effective for annual reporting periods beginning after December 15, 2018. The adoption of this standard update is not expected to have a material impact on the Company’s consolidated financial statements.

Liquidity Matters and Going Concern	12 Months Ended
Liquidity Matters and Going Concern	Dec. 31, 2017
Liquidity Matters [Abstract]
Liquidity Matters and Going Concern	LIQUIDITY AND GOING CONCERN The Company has incurred losses from operations in each of the years ended December 31, 2017, 2016 and 2015. As of December 31, 2017, the Company's total current liabilities of $398.3 million exceeded its total current assets of $51.3 million, resulting in a working capital deficit of $347.0 million. As a result of the low commodity prices, the Company has not been able to generate sufficient cash from operations to satisfy certain obligations as they became due. Well Oyo-7 is currently shut-in as a result of an emergency shut-in of the Oyo field production that occurred in early July 2016. This has resulted in a loss of approximately 1,400 BOPD. The Company is currently working on relocating an existing gaslift line to well Oyo-7 to enable continuous gaslift operation to assist in restoring lost production volumes. For cost effectiveness, the relocation of the gaslift line to well Oyo-7 is now planned to be combined with the Oyo-9 subsea equipment installation scheduled for the second half of 2018, subject to fund availability. During an approximately two (2) week period starting from late June 2017 to early July 2017, the owners of the floating, production, storage, and offloading vessel (“FPSO”) Armada Perdana suspended its operations due to an impasse in contract negotiations that led to a temporary shut-in of the Oyo-8 well during this period. The FPSO operation was fully restored and the production from the Oyo-8 well was re-established on July 6, 2017. Contract negotiations have resumed. The Company is currently pursuing a number of actions, including (i) obtaining additional funds through public or private financing sources, (ii) restructuring existing debts from lenders, (iii) obtaining forbearance of debt from trade creditors, (iv) reducing ongoing operating costs, (v) minimizing projected capital costs for the remaining 2017 exploration and development campaign, (vi) farming-out a portion of its rights to certain of its oil and gas properties and (vii) exploring potential business combination transactions. There can be no assurances that sufficient liquidity can be raised from one or more of these actions or that these actions can be consummated within the period needed to meet certain obligations. The Company's consolidated financial statements have been prepared under the assumption that it will continue as a going concern, which assumes the continuity of operations, the realization of assets and the satisfaction of liabilities as they come due in the normal course of business. Although the Company believes that it will be able to generate sufficient liquidity from the measures described above, its current circumstances raise substantial doubt about its ability to continue to operate as a going concern. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment were comprised of the following:



	As of December 31,
(In thousands)	2017			2016
Wells and production facilities	$	308,351		$	318,739
Proved properties	386,196			386,196
Work in progress and exploration inventory	113,303			34,712
Oilfield assets	807,850			739,647
Accumulated depletion and impairment	(614,648		)	(483,754		)
Oilfield assets, net	193,202			255,893
Unevaluated leaseholds	6,200			9,820
Oil and gas properties, net	199,402			265,713
Other property and equipment	2,877			3,040
Accumulated depreciation	(2,518		)	(2,324		)
Other property and equipment, net	359			716
Total property, plant and equipment, net	$	199,761		$	266,429

All of the Company’s oilfield assets are located offshore Nigeria in the Oil Mining Leases 120 and 121 (the "OMLs"). “Work-in-progress and exploration inventory” includes warehouse inventory items purchased as part of the redevelopment plan of the Oyo field. During the year ended December 31, 2016, the Company wrote off $33.0 million of suspended exploratory well costs to exploration expense. There was no such write off for the year ended December 31, 2017.

The Company’s unevaluated leasehold costs include costs to acquire the rights to the exploration acreage in its various oil and gas properties. At December 31, 2017 and 2016 unevaluated leasehold costs were $6.2 million and $9.8 million, respectively.

The Gambia Sale Agreement

In March 2017, the Company entered into a sale agreement with FAR Ltd. ("FAR"), an Australian Securities Exchange listed oil and gas company (the "Sale Agreement"), whereby FAR agreed to acquire an 80% interest and operatorship of the Company’s offshore A2 and A5 blocks in The Gambia. The Company will retain a 20% working interest in both blocks.

Under the terms of the Sale Agreement, which was approved by the Government of the Republic of The Gambia in June 2017, upon closing of the transaction, FAR paid the Company the purchase price of $5.2 million and will carry $8.0 million of the Company’s share of costs in a planned exploration well to be drilled in late 2018. In addition, if the Company’s share of the exploration well is less than $8.0 million, the balance is to be paid in cash to the Company. Any amount in excess of the $8.0 million representing the Company’s share of the exploration well will be borne by the Company.

Impairment of Oil and Gas Properties

The Company used discounted cash flow techniques to determine the estimated fair value of its oil and gas properties as part of the Company's analysis for impairment. Accordingly, the Company estimated the present value of expected future net cash flows from the Oyo field, discounted using risk-adjusted cost of capital. Significant Level 3 assumptions used in the calculation include the Company's estimate of future crude oil prices, production costs, development costs, and anticipated production of proved reserves, as well as appropriate risk-adjusted probable and possible reserves.

In December 2016, the Company recorded a non-cash impairment charge of $0.6 million, mainly to write-off the carrying value of its offshore leases in Kenya because the Company no longer intends to renew or extend its leases on these offshore blocks.

In June 2017, the Company concluded that the carrying value of its oilfield assets would not be recoverable under the then current market conditions. Accordingly, the Company recorded a non-cash impairment charge of $78.1 million to reduce the carrying value of its oil and gas properties to their estimated fair values. In addition, in June 2017, the Company recorded a non-cash impairment charge of $0.6 million to write-off the carrying value of its onshore leases in Kenya.

Suspended Exploratory Well Costs	12 Months Ended
Suspended Exploratory Well Costs	Dec. 31, 2017
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 well Oyo-7. The primary drilling objective was to establish production from the existing Pliocene reservoir. The secondary drilling objective was to confirm the presence of hydrocarbons in the deeper Miocene formation. Hydrocarbons were encountered in three Miocene intervals totaling approximately 65 feet, as interpreted by the logging-while-drilling (“LWD”) data. As of December 31, 2016, the Company’s suspended exploratory well costs were $26.5 million for the costs related to the Miocene exploratory drilling activities. Plans were underway to secure a rig to drill at least one exploration well in the nearby G-Prospect. However, due to the then current economics, the primary objective of the G-Prospect was no longer to target the same Miocene formation as the ones found in the Oyo-7 exploratory drilling. As such, during the year ended December 31, 2016, the Company wrote off the $26.5 million suspended exploratory well costs to exploration expense. In August 2014, the Company drilled well Oyo-8 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 completed a detailed evaluation of the results and initially capitalized suspended exploratory well costs amounting to $6.5 million at December 31, 2016 for the costs related to the Pliocene exploration drilling activities in the eastern fault block. During the year ended December 31, 2016, the Company wrote off the $6.5 million to exploration expense as the then current drilling plans no longer specifically targeted such area due to the then current economics.

Accounts Payable and Accrued Liabilities

12 Months Ended

Dec. 31, 2017

Payables and Accruals [Abstract]

Accounts Payable and Accrued Liabilities

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The table below sets forth a summary of the Company’s accounts payable and accrued liabilities at December 31, 2017 and 2016:



	As of December 31,
(In thousands)	2017		2016
Accounts payable - vendors	$	190,167	$	173,306
Amounts due to government entities	83,515		66,573
Accrued interest	3,051		3,074
Accrued payroll and benefits	671		1,204
Other liabilities	—		806
	$	277,404	$	244,963

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations primarily represent the estimated fair value of the amounts that will be incurred to plug, abandon and remediate its producing properties at the end of their productive lives. Significant inputs used in determining such obligations include, but are not limited to, estimates of plugging and abandonment costs, estimated future inflation rates and changes in property lives. The inputs used in the fair value determination were based on Level 3 inputs, which were essentially management's assumptions.

The following table summarizes changes in the Company’s asset retirement obligations during the years ended December 31, 2017 and 2016:



	As of December 31,
(In thousands)	2017		2016
Asset retirement obligations at January 1	$	22,476	$	20,609
Accretion expense	1,933		1,867
Additions	—		—
Revisions in estimated liabilities	—		—
Loss on settlement of asset retirement obligations	—		—
Payments to settle asset retirement obligations	—		—
Asset retirement obligations at December 31	$	24,409	$	22,476

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

The table below shows the current and long-term portions of the Company's asset retirement obligations as of the end of December 31, 2017 and 2016:



	As of December 31,
(In thousands)	2017		2016
Asset retirement obligations, current portion	$	—	$	—
Asset retirement obligations, long-term portion	24,409		22,476
	$	24,409	$	22,476

Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt

DEBT

Short-Term Debt:

Short-Term Borrowing - Glencore Advance

In February 2017, the Company received $13.6 million as an advance (the “February Advance”) under a stand-alone spot oil sales contract with Glencore Energy UK Ltd. ("Glencore"). Interest accrued on the February Advance at the rate of LIBOR plus 6.5%. Repayment of the February Advance was made from the February 2017 crude oil lifting.

In September 2017, the Company received $23.5 million as an advance (the “September Advance”) under an exclusive off-take

contract with Glencore (the “Off-take Contract”). Interest accrued on the September Advance at the rate of LIBOR plus 6.5%.

Repayment of the September Advance was made from the September 2017 crude oil lifting.

Short-Term Debt - Related Party

On September 19, 2017, the Company, through its wholly-owned subsidiary EPNL, borrowed $0.2 million under a short-term

loan agreement (the "2017 Short-Term Note") entered into with CAMAC Nigeria Limited, an affiliated company, at a flat interest rate of 5% and maturity date of June 30, 2018.

Long-Term Debt:

Term Loan Facility

In September 2014, the Company, through its wholly owned subsidiary EPNL, entered into the Term Loan Facility (as amended or modified, the “Term Loan Facility”) with Zenith for a five-year senior secured term loan providing initial borrowing capacity of up to $100.0 million. Of the total commitment provided, 90% of the Term Loan Facility is available in U.S. dollars, 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 11.1%. The obligations under the Term Loan Facility include a legal charge over the OMLs and an assignment of proceeds from oil sales. The obligations of EPNL 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 in Nigeria.

In June 2016, the Term Loan Facility was modified contingent upon the signing of a loan agreement, which was signed in August 2016. The modification put in place a twelve month moratorium on principal payments and extended the term of the Term Loan Facility until February 2021. Additionally, it reduced the funding requirement of the debt service reserve account (“DSRA”) to an amount equal to one quarter of interest until the price of oil exceeds $55 per barrel, at which time an amount equal to two quarters of interest will then be required.

Upon executing the Term Loan Facility, the Company paid fees totaling $2.6 million. Upon modification of the Term Loan Facility, additional fees of $1.4 million were incurred. These fees were recorded as debt issuance cost and are being amortized over the life of the Term Loan Facility using the effective interest method. As of December 31, 2017, $1.6 million of the debt issuance costs remained unamortized.

Under the Term Loan Facility, the following events, among others, constitute events of default: EPNL failing to pay any amounts due within thirty days of the due date; bankruptcy, insolvency, liquidation or dissolution of EPNL; a material breach of the Term Loan Facility by EPNL that remains unremedied within thirty days of written notice by EPNL; or a representation or warranty of EPNL 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. Further, Zenith has the right to review the terms and conditions of the Term Loan Facility.

During the year ended December 31, 2017, the Company made payments of $0.6 million and $8.4 million for the principal repayment of the Naira portion of the loan and for the U.S. dollar principal, respectively.

As of December 31, 2017, the Company has an unrealized foreign currency gain of $5.0 million on the Naira portion of the loan, reducing the balance under the Term Loan Facility to $78.0 million, net of debt discount. Of this amount, $59.2 million was classified as long-term and $18.8 million as short-term. Accrued interest for the Term Loan Facility was $2.0 million as of December 31, 2017.

MCB Finance Facility and Related Agreements

On February 6, 2017, the Company and its subsidiary, EPNL, entered into a Pre-export Finance Facility Agreement (the “MCB Finance Facility”) with The Mauritius Commercial Bank Limited, as mandated lead arranger, agent, security agent, original lender and issuing bank (“MCB”). The MCB Finance Facility provides for a total commitment of $100.0 million and is supported by a guarantee from The Standard Bank of South Africa Limited (“SBSA”), as named guarantor, which guarantee is facilitated by the South African Public Investment Corporation (SOC) Limited ("PIC"), the Company’s second largest shareholder. The PIC guarantee is made with recourse to the Company pursuant to the Company’s entry into the Financing Support Agreement with PIC (the "Financing Support Agreement").

In connection with the MCB Finance Facility, and as a condition precedent to the initial drawdown thereunder, EPNL entered into the Off-take Contract with Glencore dated January 18, 2017 for EPNL’s entire volumes of oil produced from the OMLs located offshore Nigeria. Pursuant to the MCB Finance Facility, EPNL is required to comply with the terms of the Off-take Contract, ensure payments and deliveries of oil and notify MCB of any failures under such contract and ensure that it receives a fair market price for delivered oil.

The MCB Finance Facility is supported by the SBSA guarantee as facilitated by PIC, the assignment of the Off-take Contract and the assignment by way of security of certain accounts, including a debt service reserve account, as set forth in the MCB Finance Facility. EPNL was required to deposit $10.0 million (see Note 2 - Basis of Presentation and Recently Issued Accounting Standards - Restricted Cash) at the closing of the MCB Finance Facility into the debt service reserve account with MCB and maintain that balance for so long as borrowings are outstanding under the MCB Finance Facility. The aforementioned guarantee and security agreements were entered into by the parties thereto before the initial drawdown on the MCB Finance Facility.

EPNL could make drawdowns under the MCB Finance Facility by way of loans and/or letters of credit until June 30, 2017 after which the remaining balance of MCB's commitment as of that date could be drawn and deposited into a capital expenditure reserve account for payment of invoices expected to be payable within six months after June 30, 2017. Borrowings under the MCB Finance Facility bear interest at the three-month LIBOR plus 6%. Additionally, the Company is required to pay an unused commitment fee of 2% per annum. After a grace period that ended on June 30, 2017, the MCB Finance Facility will be repaid over a period starting from June 30, 2017 and ending on December 31, 2019.

The MCB Finance Facility includes customary fees, including a commitment fee, structuring fee, underwriting fee, management fee, fees payable in respect of utilization of the MCB Finance Facility by way of letter of credit and other fees, and subjects EPNL to certain covenants under the terms of the MCB Finance Facility, and is subject to customary events of default.

The Company did not draw down the remaining Available Facility on June 30, 2017 as expected and is currently in discussions with MCB to amend the agreement. The Company is seeking to extend the availability period, including the grace period, as well as a revised repayment schedule.

The Company did not make the principal payment due and a portion of interest due on December 31, 2017. Also, on June 27, 2017, a vendor filed a suit against a wholly-owned subsidiary of the Company seeking an amount in excess of $10.0 million (see Note 10 - Commitments and Contingencies for further information). These constitute events of default under the MCB Finance Facility.

The Company made its initial drawdown under the MCB Finance Facility in March 2017 (the "March 2017 drawdown"). As part of the March 2017 drawdown, the Company incurred debt issuance costs amounting to $8.7 million. As of December 31, 2017, $7.3 million of the debt issuance costs remained unamortized, which is shown as a discount to long-term debt on the consolidated balance sheet. As of December 31, 2017, the amount drawn under the MCB Finance Facility was $65.6 million. Accrued interest and unused commitment fees under the MCB Finance Facility was approximately $1.0 million as of December 31, 2017.

During the year ended December 31, 2017, the Company paid $0.1 million towards the principal repayment of the MCB Finance Facility.

Under the MCB Finance Facility, the Company is required to maintain specified financial ratios. Maintenance of these financial ratios (the "cover ratios"), including a debt service cover ratio and a life cover ratio, commenced during the quarter after the initial drawdown. As of December 31, 2017, the Company is not in compliance with the cover ratios.

Also on February 6, 2017, the Company and PIC also entered into the Financing Support Agreement. Pursuant to the Financing Support Agreement, PIC agreed to apply for, request and authorize SBSA, or any other reputable commercial bank acceptable to MCB, to issue a bank guarantee in favor of MCB in the amount of $100.0 million. The issuance of a guarantee in favor of MCB by SBSA or another reputable commercial bank was a condition precedent to the closing of the MCB Finance Facility.

In consideration for this undertaking, the Company agreed to pay PIC an upfront fee equal to 250 basis points on the guarantee amount and issue to PIC warrants to purchase a number of shares of the Company’s common stock in an amount equal to the guarantee amount multiplied by 20%, divided by the closing market price of the Company’s common stock on the day that EPNL received the funds available under the MCB Finance Facility (the "warrants issuance date), with an exercise price equal to such closing market price. The Company recognized a derivative liability for the warrants that are expected to be issued for the portion of the amount drawn under the MCB Finance Facility at December 31, 2017. See Note 2 - Basis of Presentation and Recently Issued Accounting Standards - Fair Value Measurements for further information. The Company also has agreed to indemnify PIC from and against certain claims and losses. The amount of any and all indemnifiable losses suffered by PIC agreed or otherwise required to be paid by the Company will be paid in cash or, at the option of PIC, may be paid in newly issued shares of the Company’s common stock. In March 2017, the Company paid $2.5 million to PIC in fees under the Financing Support Agreement which is recorded as debt issuance costs as discussed above and is being amortized to interest expense over the life of the MCB Financing Facility.

On February 8, 2017, and in connection with the MCB Finance Facility, the Company, EPNL, MCB and Zenith, the Company’s existing secured lender, also entered into an Override Deed (the “Override Deed”). The Override Deed establishes, inter alia, pro-rata rights of MCB and Zenith in respect of the proceeds from the Off-take Contract, governs the mechanics of any enforcement action by the creditors and sets out pro-rata sharing of enforcement proceeds between MCB and Zenith. The Override Deed also grants the necessary consents to EPNL’s entry into the MCB Finance Facility and related documents.

On January 17, 2018, the Company and its subsidiary, EPNL, filed a complaint against PIC alleging that PIC is wrongfully attempting to control the approval and payment of funds from MCB under the MCB Finance Facility. See Note 10 - Legal Contingencies and Proceedings for further information.

2017 James Street Capital Note

On October 27, 2017 the Company, through its wholly-owned subsidiary, EPNL, entered into a loan agreement, (the "2017 Loan Agreement"), with James Street Capital Partners Limited, ("JSC") as the lender, allowing the Company to borrow up to $20.0 million to be used for capital expenditures in relation to the drilling of an exploration well in the Miocene formation of the OMLs. JSC is a company registered in Nigeria and has no relation to the entity which is the holder of the 2016 Promissory Note.

Interest accrues on the outstanding principal of the 2017 Loan Agreement at three-month LIBOR plus 5% per annum, payable quarterly in cash or issuance of the Company's restricted common stock. The Company is required to repay one third of the principal amount outstanding under the loan agreement, on each of December 31, 2018, 2019 and 2020. Amounts outstanding under the 2017 Loan Agreement may be paid at any time without penalty.

In consideration for this undertaking, the Company issued a stock purchase warrant to JSC to purchase up to 7,272,727shares of the Company's common stock at $2.75 per share. The warrants include a repurchase right such that upon repayment in full of the amounts borrowed under the 2017 Loan Agreement the Company may repurchase the warrants at their fair market value (as defined in the warrant agreement). The warrants expire on December 31, 2019 and include cashless exercise rights in the event the shares of common stock issuable upon exercise thereof are not registered under the Securities Act of 1933, as amended. The total fair value of the warrants was approximately $9.0 million using the Black-Scholes option model and was recorded as debt issuance cost, and is being amortized over the life of the note.

As of December 31, 2017, the outstanding principal under the JSC Loan Agreement was $11.7 million of which $3.9 million is short term. As of December 31, 2017, accrued interest was $0.09 million.

Long-Term Debt Maturities

Scheduled principal repayments on the outstanding balance on the Term Loan Facility, the MCB Finance Facility, and the 2017 Loan Agreement are as follows (in thousands):



Scheduled payments by year	Principal
2018	$	88,996
2019	25,173
2020	30,493
2021	12,198
2022 and thereafter	—
Total principal payments	$	156,860
Less: Unamortized debt issuance costs	17,328
Total Term Loan Facility, net	$	139,532

Long-Term Debt - Related Party:

As of December 31, 2017, the Company’s long-term related party debt was $129.8 million, consisting of $24.9 million owed under the 2011 Promissory Note, $50.0 million owed under the 2014 Convertible Subordinated Note, $48.5 million, net of discount, under the 2015 Convertible Note, and $6.4 million owed under the 2016 Promissory Note.

Allied, a related party, was originally the holder of each of the 2011 Promissory Note, the 2014 Convertible Subordinated Note, and the 2015 Convertible Note (collectively the “Related Party Notes”). During 2017, Oltasho became the holder of each of the Related Party Notes. Please also see Note 1 - Company Description for changes in control in the Company which occurred during 2017.

Each of the Related Party Notes contains certain default and cross-default provisions, including failure to pay interest and principal amounts when due, and default under other indebtedness. As of December 31, 2017, the Company was not in compliance with the default provisions of the Related Party Notes with respect to the payment of quarterly interest. Further, the risk of cross-default exists for each of the Related Party Notes if the holder of the Term Loan Facility exercises its right to terminate the Term Loan Facility and accelerate its maturity. In July 2017, Oltasho agreed to waive through their respective maturity dates its rights under all default provisions of each of the Related Party Notes.

2011 Promissory Note

EPNL, the Company's wholly owned subsidiary, has a $25.0 million borrowing facility under a promissory note (the "2011 Promissory Note"). Interest accrues on the outstanding principal under the 2011 Promissory Note at a rate of the 30-day LIBOR plus 2% per annum, payable quarterly. In March 2017, the 2011 Promissory Note was amended to extend the maturity date to April 2018. As consideration for the extension, the 2011 Promissory Note became convertible, at the sole option of the holder, into shares of the Company’s common stock at a conversion price of $3.415 per share. In July 2017, the 2011 Promissory Note was amended to extend the maturity date to December 2019. The entire $25.0 million facility amount can be utilized for general corporate purposes. The stock of the Company’s subsidiary that holds the exploration licenses in The Gambia and Kenya were pledged as collateral to secure the 2011 Promissory Note, pursuant to an Equitable Share Mortgage arrangement. As of December 31, 2017, the outstanding principal and accrued interest under the 2011 Promissory Note were $24.9 million and $2.5 million, respectively.

As referred to above, this Note was transferred to Oltasho during 2017.

2014 Convertible Subordinated Note

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

At the election of the holder, the 2014 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 2014 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 2014 Convertible Subordinated Note). The following events, among others, constitute an Event of Default under the 2014 Convertible Subordinated Note: the Company failing to pay interest within thirty days of the due date; the Company failing to pay principal when due; bankruptcy, insolvency, liquidation or dissolution of the Company; a material breach of the 2014 Convertible Subordinated Note by the Company that remains unremedied within ten days of such material breach; or a representation or warranty of the Company 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. As of December 31, 2017, outstanding principal and interest was $50.0 million and $11.4 million, respectively.

The Company may, at its option, prepay the 2014 Convertible Subordinated Note in whole or in part, at any time, without premium or penalty. Further, the 2014 Convertible Subordinated Note 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. The holder may assign all or any part of its rights and obligations under the 2014 Convertible Subordinated Note to any person upon written notice to the Company.

As referred to above, this Note was transferred to Oltasho during 2017.

2015 Convertible Note

In March 2015, the Company entered into a borrowing facility with Allied in the form of a Convertible Promissory Note (the "2015 Convertible Note"), allowing the Company to borrow up to $50.0 million for general corporate purposes. In March 2017, the maturity date of the 2015 Convertible Note was extended to April 2018. 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 the closing sales prices on the NYSE American for a share of common stock for the five complete trading days immediately preceding the conversion date.

As of December 31, 2017, the outstanding balance of the 2015 Convertible Note and accrued interest was $48.5 million and $8.2 million, respectively.

As referred to above, this Note was transferred to Oltasho during 2017.

2016 Promissory Note

As of December 31, 2017, the outstanding balance under the Promissory Note entered into in 2016 with an entity related to the Company's then majority shareholder (the "2016 Promissory Note") was $6.4 million. Accrued interest on the 2016 Promissory Note was approximately $1.0 million as of December 31, 2017. In March 2017, the maturity date of the 2016 Promissory Note was extended to April 2018. As consideration for the extension, the 2016 Promissory Note became convertible, at the sole option of the holder, into shares of the Company’s common stock at a conversion price of $3.415 per share. In July 2017, the maturity date of the 2016 Promissory Note was extended to April 2023.

Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions

RELATED PARTY TRANSACTIONS

Assets and Liabilities

The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates. Effective April 3, 2017, Oltasho became a majority shareholder of the Company and the holder of the Related Party Notes. CEHL and its affiliates, which include Allied, are entities controlled by Dr. Lawal. These entities are deemed to be related parties for financial reporting purposes. The table below sets forth the related party assets and liabilities as of December 31, 2017 and 2016:



	As of December 31,
(In thousands)	2017		2016
Accounts receivable	$	2,926	$	1,956
Accounts payable and accrued liabilities	$	40,483	$	29,513
Short-term note payable - related party	$	200	$	—
Long-term notes payable - related party	$	129,830	$	129,796

As of December 31, 2017 and 2016, the related party receivable balances of $2.9 million and $2.0 million, respectively, were for advance payments made for certain transactions on behalf of affiliates.

As of December 31, 2017 and 2016, the Company owed $40.5 million and $29.5 million, respectively, to affiliates primarily for logistical and support services in relation to the Company's oilfield operations in Nigeria, as well as accrued interest on the various related party notes payable. As of December 31, 2017 and 2016, accrued and unpaid interest on the various related party notes payable were $23.3 million and $15.2 million, respectively.

As of December 31, 2017, the Company had a related party short term note payable balance of $0.2 million under a short term loan agreement entered into with an affiliate.

As of December 31, 2017, the Company had a combined note payable balance of $129.8 million owed to affiliates, consisting of $24.9 million in borrowings under the 2011 Promissory Note, $50.0 million in borrowings under the 2014 Convertible Subordinated Note, $48.5 million in borrowings under the 2015 Convertible Note, net of discount and $6.4 million under the 2016 Promissory Note. As of December 31, 2016, the Company had a long-term note payable balance of $129.8 million owed to an affiliate, consisting of $24.9 million in borrowings under the 2011 Promissory Note, $50.0 million in borrowings under the 2014 Convertible Subordinated Note, and $48.5 million in borrowings under the 2015 Convertible Note, net of discount. See Note 8. - Debt for further information relating to the notes payable transactions.

Results from Operations

The table below sets forth the transactions incurred with affiliates during the years ended December 31, 2017, 2016 and 2015:



	Year Ended December 31,
(In thousands)	2017		2016		2015
Total operating expenses	$	11,058	$	14,621	$	15,106
Interest expense	$	8,157	$	6,843	$	5,490

Certain affiliates of the Company provide procurement and logistical support services to the Company’s operations. In connection therewith, during the years ended December 31, 2017, 2016 and 2015, the Company incurred operating costs amounting to approximately $11.1 million, $14.6 million and $15.1 million, respectively.

During the years ended December 31, 2017, 2016 and 2015, the Company incurred interest expense, excluding debt discount amortization, totaling approximately $8.2 million, $6.8 million and $5.5 million, respectively, attributed to its related party notes payable.

Non-controlling Interests

In April 2014, the Company, through its 50% ownership of its Erin Energy Ghana Limited subsidiary, signed a Petroleum Agreement with the Republic of Ghana relating to the Expanded Shallow Water Tano block offshore Ghana. An affiliate of the Company owns the remaining 50% non-controlling interest in the Erin Energy Ghana Limited subsidiary.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Commitments

The following table summarizes the Company’s significant future commitments on non-cancellable operating leases and estimated obligations arising from its minimum work obligations for the five years after December 31, 2017 and thereafter:



	Payments Due By Period
(In thousands)	Total		2018		2019		2020		2021		2022		Thereafter
Operating lease obligations:
FPSO - Nigeria	$	145,087	$	48,363	$	48,362	$	48,362	$	—	$	—	$	—
Office leases	972		485		383		65		39		—		—
Minimum work obligations:
The Gambia	145		145		—		—		—		—		—
Total	$	146,204	$	48,993	$	48,745	$	48,427	$	39	$	—	$	—

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 productive wells, Oyo-7 and Oyo-8, offshore 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 per year through 2020.

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. The table above sets forth the Company's future contractual obligations with regards to the minimum work obligations in each country. In December 2016, the Company recorded a charge of $0.6 million to write-off the carrying value of certain of its offshore leases in Kenya because the Company no longer intends to renew or extend its leases on these offshore blocks. In June 2017, the Company recorded a non-cash impairment charge of $0.6 million to write-off the carrying value of its onshore leases in Kenya.

The Company rents office space and miscellaneous office equipment under non-cancelable operating leases. Office rent expense, net of sublease income, for the years ended December 31, 2017, 2016 and 2015, was $0.8 million, $1.1 million and $0.9 million, respectively. At December 31, 2017, minimum future rental commitments for office leases were a total of approximately $1.0 million.

In March 2017, the Company entered into a drilling services contract with Pacific Drilling using the Pacific Bora drilling rig. The Company used this rig to drill well Oyo-9 on the Oyo field in the deepwater offshore Nigeria. Under the contract, the Company has the option to drill up to two additional wells. The Pacific Bora is a highly efficient sixth generation double-hulled drillship currently in Nigeria and was mobilized to the Oyo field and on site August 1, 2017. The rig can be used for both drilling and well completion. In October 2017, the Company successfully completed the drilling phase of the Oyo-9 well. However, due to chronic delays in the release of the remaining funds and improper interference by the guarantor of the MCB Finance Facility, the Company temporarily suspended the completion and hookup of the Oyo-9 well. The option to extend the contract was exercised and was used to drill the Company's potential high-impact exploration well ("Oyo-NW"), in the Miocene formation of the OMLs. The contract provides for a base operating rate of $150,000 per day.

Contingencies

Legal Contingencies and Proceedings

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. As of December 31, 2017, 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 January 22, 2016, a request for arbitration was filed with the London Court of International Arbitration by Transocean Offshore Gulf of Guinea VII Limited and Indigo Drilling Limited, as Claimants, against the Company and its Nigerian subsidiary, EPNL, as Respondents (the “Arbitration”). The Arbitration was in relation to a drilling contract entered into by the Claimants and EPNL, and a parent company guarantee provided by the Company in relation thereto. On July 19, 2017, the London Court of International Arbitration issued a “First Partial Final Award by Consent” (the “Consent Award”) in a proceeding between the Claimants and Respondents to resolve claims by the Claimants arising out of a contract for oilfield services done in relation to the Company's ordinary course of business. Pursuant to the Consent Award, the Respondents are liable to pay Claimants approximately $20.2 million and 11.8 million Nigerian Naira (NGN), equal to approximately $33,000 U.S. dollars. On August 25, 2017 Transocean Offshore Gulf of Guinea VII Limited and Indigo Drilling Limited filed a “Petition for Confirmation of Arbitral Award” in the United States District Court for the Southern District of Texas seeking confirmation and enforcement of the Consent Award. On March 12, 2018 the United States District Court for the Southern District of Texas issued an order granting Transocean Offshore Gulf of Guinea VII Limited’s and Indigo Drilling Limited’s motion to enforce the Consent Award and for entry of final judgment. Specifically, the Consent Award was confirmed as the judgment of the United States District Court for the Southern District of Texas. The parties are in the process of negotiating a settlement agreement concerning the Company’s payment of the Consent Award.

On February 5, 2016, a class action and derivative complaint was filed in the Delaware Chancery Court purportedly on behalf of the Company and on behalf of a putative class of persons who were stockholders as of the date the Company (1) acquired the remaining economic interests in the production sharing contract ("the PSC ") and related assets, contracts and rights pertaining to the OMLs located offshore Nigeria, including the producing Oyo field (the "Allied Assets") pursuant to the Transfer Agreement and (2) issued shares to the PIC in a private placement (collectively the “February 2014 Transactions”). The complaint alleges the February 2014 Transactions were unfair to the Company and purports to assert derivative claims against (1) the seven individuals who served on our Board at the time of the February 2014 Transactions and (2) the Company's then majority shareholder, CEHL. The complaint also purports to assert a direct breach of fiduciary duty claim on behalf of the putative class against the seven individuals who served on the Company's Board at the time of the February 2014 Transactions on the grounds that they purportedly caused the Company to disseminate a false and misleading proxy statement in connection with the 2014 Transactions, and a direct claim for aiding and abetting against Dr. Kase Lawal, the former Executive Chairman of the Board of Directors and Chief Executive Officer of the Company. The plaintiff is seeking, on behalf of the Company and the putative class, an undisclosed amount of compensatory damages. The Company is named solely as a nominal defendant against whom the plaintiff seeks no recovery. On March 3, 2016, all of the defendants, including the Company, filed motions to dismiss the complaint (the "Motion to Dismiss"), which motions were heard on January 18, 2017. The plaintiffs filed a motion to supplement their petition to include a claim relating to what Allied paid or did not pay Nigerian Agip Exploration Limited for the asset. On May 23, 2017, the court granted plaintiffs’ motion to supplement petition. On June 23, 2017, the defendants filed short motions to dismiss the supplemental allegations. The plaintiffs filed their response on July 12, 2017 and the defendants filed a reply on July 21, 2017. The Motion to Dismiss was granted by the Court of Chaucery in a Memorandum Opinion on November 7, 2017. The plaintiff filed a timely notice of appeal to the Memorandum Opinion in the Supreme Court of the State of Delaware. Plaintiffs filed an opening brief with that court. The Company then filed a response brief followed by plaintiff's reply brief. A hearing of oral arguments, if any, is expected to occur in April, 2018.

On June 27, 2017, BGP Kenya Limited ("BGP") filed suit against the Company’s operating subsidiary, Erin Energy Kenya Limited ("EEKL") in the High Court of Kenya. BGP is seeking approximately $12.2 million in damages, which includes interest of approximately $2.7 million for allegedly unpaid amounts in connection with BGP’s performance of seismic services in Kenya done in relation to the Company's ordinary course of business. EEKL is contesting the proceedings.

On July 13, 2017, Multiplan Nigeria Limited ("Multiplan") entered into a settlement agreement and release (the “Multiplan Settlement Agreement”) with EPNL for $3.0 million, to resolve claims by Multiplan for work done in relation to the Company's ordinary course of business. As a result thereof, the Company decreased its accounts payable and accrued liabilities by $0.2 million with a corresponding decrease to its oil and gas properties as of December 31, 2017. As of December 31, 2017, all remaining amounts claimed by Multiplan were discharged by EPNL.

On July 14, 2017, Aker Solutions Inc. ("Aker") entered into a settlement agreement and release (the “Aker Settlement Agreement”) with EPNL for $2.5 million, to resolve claims by Aker for work done in relation to the Company's ordinary course of business. As a result thereof, the Company decreased its accounts payable and accrued liabilities by $10.2 million with a corresponding decrease to its oil and gas properties as of December 31, 2017. As of December 31, 2017 all remaining amounts claimed by Aker were discharged by EPNL.

In September 2017, the Company entered into a Mutual Release Agreement and Stock Purchase Agreement, (collectively, the "September 2017 Settlement Agreement") with a vendor, to resolve claims by the vendor for work done in relation to the Company's ordinary course of business. As part of the September 2017 Settlement Agreement, the Company issued 1,282,355 shares of restricted common stock to the vendor at a fair value of $3.5 million.

On January 26, 2018, the Company and its subsidiary, EPNL, filed a complaint against Public Investment Corporation SOC Ltd., ("PIC"), with the Supreme Court of New York, County of New York, Commercial Division. The complaint alleges that PIC is wrongfully attempting to control the approval and payment of funds from MCB under the MCB Finance Facility, (see Note 8 - Debt for further information), which resulted in the suspension of completion of the Oyo-9 well. .

Unrecognized Loss Contingency

As of December 31, 2017, the Company has not accrued penalty and interest related to certain outstanding transactional tax obligations in Nigeria, including withholding taxes, value-added taxes, Nigerian Oil and Gas Industry Content Development Act (NCD) tax, Cabotage taxes, and Niger Delta Development Corporation taxes (NDDC). As of the date of this report, the Company believes that, based on its experience with local practices in Nigeria, no notice of penalty and interest has been assessed by any Nigerian taxing authority, however the likelihood of being assessed penalty and interest is reasonably possible, with an estimated liability up to $27.4 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 ("DPR") 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 is to be determined by calculating the average closing price of the Company’s common stock over a period of thirty days, counted back from the first business day immediately prior to the approval of a development plan by DPR or the date of the first hydrocarbon production in commercial quantities, as applicable.

Allied's interests were transferred to Oltasho in April of 2017.

Contingency under the 2015 Convertible Note

As part of the condition to the extension of the maturity date of the 2015 Convertible Note entered into in March 2016, the Company is required to (i) pay the holder of the note an amount equal to ten percent (10%) of any successful debt fundraising event completed during the remaining term of the 2015 Convertible Note; and (ii) pay the holder of the note an amount equal to twenty percent (20%) of any successful equity fundraising event completed during the remaining term of the 2015 Convertible Note. The execution of the MCB Financing Facility in February 2017 triggered item (i) above of which a payment is due to the holder of the note under these provisions.

Stock Based Compensation

12 Months Ended

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock Based Compensation

STOCK BASED COMPENSATION

Under the Company’s amended 2009 Equity Incentive Plan (“2009 Plan”), the Company may issue restricted stock awards and stock options to result in issuance of a maximum aggregate of 16.7 million shares of common stock. Options awarded expire between five and ten years from the date of the grant, or a shorter term as fixed by the Board of Directors.

Stock Options

The table below sets forth a summary of stock option activity for the year ended December 31, 2017.



	Shares Underlying Options (In Thousands)		Weighted-Average Exercise Price	Weighted-Average Remaining Contractual Term (Years)
Stock Options
Outstanding at December 31, 2016	1,147		$2.54	2.0
Granted	745		$2.26	0.9
Exercised	(511	)	$1.81	—
Forfeited	(639	)	$2.69	—
Expired	(145	)	$3.55	—
Outstanding at December 31, 2017	597		$2.40	1.5
Expected to vest	145		$1.88	4.4
Exercisable at December 31, 2017	452		$2.57	0.6

During the year ended December 31, 2017, the Company issued 183,160 shares of common stock as a result of the exercise of stock options, all of which were issued as a result of the cashless exercise of options to purchase 510,555 shares of common stock. Also, during the year ended December 31, 2017, options to purchase 144,842 shares of common stock expired, and options to purchase 638,891 shares were forfeited.

The total intrinsic value of options outstanding and options exercisable were $0.4 million and $0.2 million, respectively, at December 31, 2017. The total intrinsic values realized by recipients on options exercised were $0.5 million, $0.7 million, and $0.01 million in 2017, 2016 and 2015, respectively.

The Company recorded compensation expense relative to stock options in 2017, 2016 and 2015 of approximately $0.1 million, $0.4 million and $1.3 million, respectively. As of December 31, 2017, there were approximately $0.1 million of total unrecognized compensation cost related to stock options, with $0.04 million, $0.04 million and $0.02 million to be recognized during the years ended December 31, 2018, 2019 and 2020, respectively.

The fair values of stock options used in recording compensation expense are computed using the Black-Scholes option pricing model. The table below shows the weighted-average amounts and the assumptions used in the model for options awarded in each year under equity incentive plans.



	2017		2016			2015
Expected price volatility	83.9% - 87.3%		—		%	77.1% - 83.1%
Risk free interest rate (U.S. treasury bonds)	1.4% - 1.5%		—		%	1.0% - 1.2%
Expected annual dividend yield	—		—			—
Expected option term (years)	3.0		—			3.0
Weighted-average grant date fair value per share	$	1.23	$	—		$	2.73

Stock Warrants

The table below sets forth a summary of stock warrant activity for the year ended December 31, 2017.



	Shares Underlying Warrants (In Thousands)	Weighted-Average Exercise Price	Weighted-Average Remaining Contractual Term (Years)
Stock warrants
Outstanding at December 31, 2016	2,983	$3.59	3.2
Granted	7,273	$2.75	2.0
Exercised	—	$—	—
Forfeited	—	$—	—
Expired	—	$—	—
Outstanding at December 31, 2017	10,256	$2.99	2.1
Expected to vest	—	$—	—
Exercisable at December 31, 2017	10,256	$2.99	2.1

The total intrinsic value of warrants outstanding and exercisable was $0.5 million at December 31, 2017.

On October 27, 2017, the Company, through its wholly-owned subsidiary, EPNL, entered into a loan agreement with James Street Capital Partners Limited, as the lender. In consideration for the loan, the Company issued a stock purchase warrant to JSC to purchase up to 7,272,727 shares of the Company's common stock at $2.75 per share. The warrants include a repurchase right such that upon repayment in full of the amount borrowed the Company may repurchase the warrants at their fair market value. The warrants expire December 31, 2019. See Note 8 – Debt - Long Term Debt - 2017 James Street Capital Note.

During the year ended December 31, 2016, and in connection with the execution of the 2015 Convertible Note, the Company issued to Allied warrants to purchase 48,291 shares of the Company’s common stock at exercise prices ranging from $2.00 to $2.13 per share. The warrants are exercisable at any time starting from the date of issuance and have a five-year term. See Note 8 – Debt - Long Term Debt - Related Party - 2015 Convertible Note.

During the year ended December 31, 2014, as compensation for services received, the Company issued warrants to a service provider to purchase 0.3 million shares of common stock at an exercise price of $3.36 per share. The warrants are exercisable at any time starting from the date of issuance and have a five year term. During the years ended December 31, 2017, 2016 and 2015, the Company recognized stock-based compensation expense of nil, nil and $0.4 million, respectively, related to these warrants, based on the Black-Scholes option pricing model.

The table below shows the weighted-average amounts and the assumptions used in the model for warrants issued during each year.



	2017			2016			2015
Expected price volatility	82.2		%	84.7% - 84.8%			76.8% - 83.2%
Risk free interest rate (U.S. treasury bonds)	1.6		%	0.8		%	0.8% - 1.1%
Expected annual dividend yield	—			—			—
Expected option term (years)	2.0			3.0			3.0
Weighted-average grant date fair value per share	$	1.23		$	1.12		$	1.86

Restricted Stock Awards (“RSA”)

In addition to stock options, the Company’s 2009 Plan allows for the grant of restricted stock awards (“RSAs”). The Company determines the fair value of RSAs based on the market price of its common stock on the date of grant. Compensation cost for RSAs is recognized on a straight-line basis over the vesting or service period and is net of forfeitures.

The table below sets forth a summary of RSA activity for the year ended December 31, 2017.



	Shares (In Thousands)		Weighted-Average Grant Date Fair Value
Restricted Stock
Non-vested at December 31, 2016	2,072		$2.25
Granted	1,122		$3.00
Vested	(1,174	)	$2.40
Forfeited	(861	)	$2.96
Non-vested as of December 31, 2017	1,159		$2.30

During the year ended December 31, 2017, the Company granted its officers, directors, and employees a total of approximately 1.1 million shares of restricted common stock, including 0.2 million shares of performance-based restricted stock awards ("PBRSAs") to certain officers with vesting periods varying from immediate vesting to 36 months. During the year ended December 31, 2017, 860,607 shares of restricted common stock were forfeited.

With regards to the PBRSA, 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, net of forfeitures, is $0.09 million over three years.

The Company recorded compensation expense relative to RSAs, including PBRSAs, in 2017, 2016 and 2015 of $1.9 million, $2.5 million and $3.3 million, respectively.

The total grant date fair value of RSA shares that vested during 2017 and 2016 was approximately $2.3 million and $2.1 million, respectively. As of December 31, 2017, there were approximately $0.7 million of total unrecognized compensation cost related to non-vested RSAs, with $0.6 million and $0.1 million to be recognized during the years ended December 31, 2018 and 2019, respectively.

Issuance of Common Shares

During September 2017, the Company issued 33,333 shares of restricted common stock to a consultant for services rendered with a fair value of $0.1 million.

Also during September 2017, the Company issued 1,282,355 shares of restricted common stock to a vendor under the September 2017 Settlement Agreement with a fair value of $3.5 million (See Note 10 - Commitments and Contingencies).

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

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



	Years Ended December 31,
(In thousands)	2017			2016			2015
Net loss attributable to Erin Energy Corporation before income tax expense	$	(151,892	)	$	(142,401	)	$	(430,937	)
Expected income tax benefit at statutory rate of 35%	(53,162		)	(49,840		)	(150,828		)
Increase (decrease) due to:
Tax Reform Act - rate change	18,762			—			—
Foreign rate differential	(19,530		)	(17,202		)	(59,467		)
Change in valuation allowance	79,768			71,148			256,910
Investment tax credit - Nigeria	(23,728		)	1,991			(35,580		)
Non-deductible expenses and other	(2,110		)	(6,097		)	(11,035		)
Total income tax benefit	$	—		$	—		$	—

Significant components of our deferred tax assets are as follows:



	As of December 31,
(In thousands)	2017			2016
Basis difference in fixed assets	$	19,126		$	(3,249	)
Unused capital allowances	644,099			572,051
Net operating losses	96,701			109,230
Other	10,295			12,421
	770,221			690,453
Valuation allowance	(770,221		)	(690,453		)
Net deferred income tax assets	$	—		$	—

The majority of the Company’s basis difference in fixed assets and unused capital allowances were generated from its Nigerian operations. The Company’s foreign net operating losses in Nigeria are not subject to expiration, and can be carried forward indefinitely. The foreign operating losses in The Gambia, Kenya and Ghana are included in the respective subsidiaries cost oil accounts, which will be offset against future taxable revenues. The U.S. Federal NOL will begin to expire in 2027. The ability to utilize NOLs and other tax attributes could be subject to a limitation if the Company were to undergo an ownership change as defined in Section 382 of the Tax Code.

Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. Based on current facts and circumstances related to its Nigerian operations, management has determined that it cannot demonstrate that it is more likely than not that the Nigerian losses and unutilized capital allowances will be utilized to reduce the Company’s petroleum profit tax liability within the foreseeable future.

Furthermore, because the Company does not currently have any revenue generating activities either in the U.S. or in any of its non-Nigerian subsidiaries, it cannot demonstrate that it is more likely than not that any of the related deferred tax assets will be utilized in the foreseeable future.

On the basis of this assessment, valuation allowances of $770.2 million and $690.5 million were recorded as of December 31, 2017 and 2016, respectively.

At December 31, 2017 and 2016, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.

The Company recognizes the financial statement benefit of a tax position only after determining that they are more likely than not to sustain the position following an audit. The Company believes that its income tax positions and deductions will be sustained on audit and therefore no reserves for uncertain tax positions have been established. Accordingly, no interest or penalties have been accrued as of December 31, 2017 and 2016. The Company’s policy is to include interest and penalties related to unrecognized tax benefits as a component of income tax expense.

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



United States:	2007	-	2017
Nigeria:	2010	-	2017
Kenya:	2012	-	2017
The Gambia:	2012	-	2017

U.S. Tax Reform

On December 22, 2017, the United States government enacted the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act. The Tax Reform Act includes significant changes to the U.S. income tax system including but not limited to: a federal corporate rate reduction from 35% to 21%; limitations on the deductibility of interest expense and executive compensation; repeal of the Alternative Minimum Tax (“AMT”); full expensing provisions related to business assets; creation of new minimum taxes such as the base erosion anti-abuse tax (“BEAT”) and Global Intangible Low Taxed Income (“GILTI”) tax; and the transition of U.S. international taxation from a worldwide tax system to a modified territorial tax system, which will result in a one time U.S. tax liability on those earnings which have not previously been repatriated to the U.S. (the “Transition Tax”). The provisional impacts of this legislation are outlined below:

· Beginning January 1, 2018, the U.S. corporate income tax rate will be 21%. The Company is required to recognize the impacts of this rate change on its deferred tax assets and liabilities in the period enacted. The provisional effect of the rate change is a decrease to the deferred tax asset of $18.8 million. However, as the Company has a full valuation allowance on its net deferred tax asset, the deferred tax recognized due to the change in rate will be offset with a change in the valuation allowance. Therefore, there was no overall impact to the Financial Statements in 2017 due to this change in rate.

· The Transition Tax on unrepatriated foreign earnings is a tax on previously untaxed accumulated and current earnings and profits ("E&P") of the Company's foreign subsidiaries. To determine the amount of the Transition Tax, the Company must determine, among other factors, the amount of post-1986 E&P of its foreign subsidiaries, as well as the amount of non-U.S. income taxes paid on such earnings. Based on the Company’s reasonable estimate of the Transition Tax, there is no provisional Transition Tax expense. The Company has not completed its accounting for the income tax effects of the transition tax and is continuing to evaluate this provision of the Tax Act.

· The Tax Act creates a new requirement that GILTI income earned by foreign subsidiaries must be included currently in the gross income of the U.S. shareholder. Due to the complexity of the new GILTI tax rules, the Company is continuing to evaluate this provision of the Tax Act. Under U.S. GAAP, the Company is permitted to make an accounting policy election to either treat taxes due on future inclusions in U.S. taxable income related to GILTI as a current period expense when incurred or to factor such amounts into the Company's measurement of its deferred taxes. The Company has not yet completed its analysis of the GILTI tax rules and is not yet able to reasonably estimate the effect of this provision of the Tax Act or make an accounting policy election for the accounting treatment whether to record deferred taxes attributable to the GILTI tax. The Company has not recorded any amounts related to potential GILTI tax in the Company’s financial statements.

Other provisions in the legislation, such as interest deductibility and changes to executive compensation plans are not expected to have material implications to the Company’s financial statements. The income tax effects recorded in the Company’s financial statements as a result of the Tax Reform Act are provisional in accordance with the Securities and Exchange Commission’s Staff Accounting Bulletin number 118 (“SAB 118”) as the Company has not yet completed its evaluation of the impact of the new law. SAB 118 allows for a measurement period of up to one year after the enactment date of the Tax Reform Act to finalize the recording of the related tax impacts. The Company does not believe potential adjustments in future periods would materially impact the Company’s financial condition or results of operations.

Segment Information

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

The Company’s current operations are based in Nigeria, Kenya, The Gambia, and Ghana. Management reviews and evaluates the operations of each geographic segment separately. Segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues and expenditures are recognized at the relevant geographical location. The Company evaluates each segment based on operating income (loss).

The table below sets forth segment activity for the years ended December 31, 2017, 2016, and 2015.



(In thousands)	Nigeria			Kenya			The Gambia			Ghana			Corporate and Other			Total
For the Years Ended December 31,
2017
Revenues	$	101,173		$	—		$	—		$	—		$	—		$	101,173
Operating income (loss)	$	(118,570	)	$	(1,504	)	$	1,308		$	(2,051	)	$	(9,718	)	$	(130,535	)
2016
Revenues	$	77,815		$	—		$	—		$	—		$	—		$	77,815
Operating loss	$	(119,346	)	$	(2,569	)	$	(1,570	)	$	(1,677	)	$	(11,830	)	$	(136,992	)
2015
Revenues	$	68,429		$	—		$	—		$	—		$	—		$	68,429
Operating loss	$	(387,448	)	$	(8,038	)	$	(5,209	)	$	(1,931	)	$	(13,807	)	$	(416,433	)

The table below sets forth the total assets by segment as of December 31, 2017 and 2016.



(In thousands)	Nigeria		Kenya		The Gambia		Ghana		Corporate and Other		Total
Total Assets
December 31, 2017	$	243,030	$	40	$	1,782	$	5,367	$	909	$	251,128
December 31, 2016	$	281,050	$	698	$	3,034	$	3,648	$	771	$	289,201

Selected Unaudited Quarterly Financial Data

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Selected Unaudited Quarterly Financial Data

SELECTED UNAUDITED QUARTERLY FINANCIAL DATA (In thousands, except for per share amounts)



	Three Months Ended,
	March 31, 2017			June 30, 2017			September 30, 2017			December 31, 2017
Total revenues	$	31,278		$	14,588		$	33,643		$	21,664
Operating loss	$	(25,092	)	$	(89,133	)	$	(10,030	)	$	(6,280	)
Net loss attributable to Erin Energy Corporation	$	(26,506	)	$	(98,565	)	$	(14,070	)	$	(12,751	)
Net loss per common share attributable to Erin Energy Corporation
Basic	$	(0.12	)	$	(0.46	)	$	(0.07	)	$	(0.06	)
Diluted	$	(0.12	)	$	(0.46	)	$	(0.07	)	$	(0.06	)
	Three Months Ended,
	March 31, 2016			June 30, 2016			September 30, 2016			December 31, 2016
Total revenues	$	4,929		$	23,151		$	28,619		$	21,116
Operating loss	$	(28,293	)	$	(27,199	)	$	(21,817	)	$	(59,683	)
Net loss attributable to Erin Energy Corporation	$	(32,411	)	$	(22,572	)	$	(23,471	)	$	(63,947	)
Net loss per common share attributable to Erin Energy Corporation
Basic	$	(0.15	)	$	(0.11	)	$	(0.11	)	$	(0.30	)
Diluted	$	(0.15	)	$	(0.11	)	$	(0.11	)	$	(0.30	)

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Subsequent to December 31, 2017, the Company granted to employees approximately 0.1 million shares of restricted stock, and granted performance-based restricted stock awards (PBRSA) to certain officers totaling 0.2 million shares. On February 22, 2018, the Company entered into a Promissory Note ("the 2018 Promissory Note'") with CAMAC International Corporation in the amount of $600,000. Interest accrues on the outstanding principal of the 2018 Promissory Note at the rate of LIBOR plus 5% and matures on September 30, 2018. In February of 2018, FAR, the Company's joint venture partner in the Gambia, reported that a subsidiary of Petroliam Nasional Berhad ("PETRONAS"), has signed a Farm-out Agreement ("FOA") with them. The FOA, expected to be completed March 31, 2018, assigns a 40% interest in the A2 and A5 offshore blocks in The Gambia to PETRONAS with FAR retaining operatorship and a 40% interest in each block. Erin Energy has a 20% interest in blocks A2 and A5 following its farm-out to FAR in 2017. On February 26, 2018, the Company executed the Convertible Subordinated Note Amendment and Debt Conversion Agreement (the "Conversion Agreement") effective December 29, 2017, whereby the conversion price of the 2014 Convertible Subordinated Note was amended to $2.75, and the holder of the 2014 Convertible Subordinated Note agreed to convert the outstanding principal and interest balance of the note Company in exchange for 22,327,327 shares of common stock. The shares are expected to be issued during the first quarter of 2018.

Basis of Presentation and Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned direct and indirect subsidiaries, and have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). All significant intercompany transactions and balances have been eliminated in consolidation. The consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the consolidated financial position and results of operations for the indicated periods. All such adjustments are of a normal recurring nature.

Principles of Consolidation

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

Use of Estimates

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

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

Cash and Cash Equivalents

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

Restricted Cash

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

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are accounted for at cost less allowance for doubtful accounts. The Company establishes provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2017 and 2016, no allowance for doubtful accounts was necessary.

Crude Oil Inventory

Inventories of crude oil are valued at the lower of cost or net realized value using the first-in, first-out method and include certain costs directly related to the production process and depletion, depreciation and amortization attributable to the underlying oil and gas properties.

Successful Efforts Method of Accounting for Oil and Gas Activities

The Company follows the successful efforts method of accounting for its costs of acquisition, exploration and development of oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Drilling costs of exploratory wells are capitalized pending determination that proved reserves have been found. If the determination is dependent upon the results of planned additional wells and require additional capital expenditures to develop the reserves, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well as a producing well, and additional wells are underway or firmly planned to complete the evaluation of the well. Exploratory wells not meeting the criteria for continued capitalization are expensed when such a determination is made. Other exploration costs are expensed as incurred.

A portion of the Company’s oil and gas properties include oilfield materials and supplies inventory to be used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or net realized value, which approximates fair value, and they are regularly assessed for obsolescence. Oilfield materials and supplies inventory balances were $36.7 million and $34.7 million at December 31, 2017 and 2016, respectively.

Depreciation, depletion and amortization costs for productive oil and gas properties are recorded on a unit-of-production basis. For other depreciable property, depreciation is recorded on a straight-line basis over the estimated useful life of the assets, which range between three to five years, or the lease term if shorter. Repairs and maintenance charges, including workover costs, are charged to expense as incurred.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets in property, plant and equipment for impairment each reporting period, or whenever changes in circumstances indicate that the carrying amount of assets may not be fully recoverable. Possible indicators of impairment include lower expected future oil and gas prices, actual or expected future development or operating costs significantly higher than previously anticipated, significant downward oil and gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable.

An impairment loss is recognized for proved properties when the estimated undiscounted future cash flows expected to result from the asset are less than its carrying amount. The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset. The Company’s cash flow projections into the future include assumptions on variables, such as future sales, sales prices, operating costs, economic conditions, market competition and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount over the fair value of the assets.

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

Asset Retirement Obligations

The Company accounts for asset retirement obligations in accordance with applicable accounting guidelines, which require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. Specifically, the Company records a liability for the present value, using a credit-adjusted risk free interest rate, of the estimated site restoration costs with a corresponding increase to the carrying amount of the related long-lived asset.

Revenues

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

Income Taxes

The Company accounts for income taxes using the asset and liability method of accounting for income taxes in accordance with applicable accounting rules. Under the asset and liability method, deferred tax assets and liabilities are recognized for temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting purposes and for operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets to their net realizable amounts if it is more likely than not that the related tax benefits will not be fully realized.

The Company routinely evaluates any tax deduction and tax refund position in a two-step process. The first step is to determine whether it is more likely than not that a tax position will be sustained. If that test is met, the second step is to determine the amount of benefit or expense to recognize in the consolidated financial statements. See Note 12. — Income Taxes for further information.

Debt Issuance Costs

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

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.

Share-Based Compensation

Stock-Based Compensation

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

Treasury Stock

Treasury stock is reported at cost and is included in the accompanying consolidated balance sheets. Pursuant to the Company’s withholding tax policy with respect to vested restricted stock awards, the Company may withhold, on a cashless basis, a number of shares needed to settle statutory withholding tax requirements.

Reporting and Functional Currency

The Company has adopted the U.S. dollar as the functional currency for all of its foreign subsidiaries. Gains and losses on foreign currency transactions and remeasurements are included in results of operations.

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 dilutive common stock equivalent, which consists of shares outstanding, augmented by potentially dilutive shares issuable upon the exercise of the Company’s stock options, stock warrants, non-vested restricted stock awards, and the conversions of the 2011 Promissory Note, 2014 Convertible Subordinated Note and the 2016 Promissory Note (collectively, the "Convertible Notes"), described and defined below under Note 8. - Debt - Long-Term Debt - Related Party), calculated using the treasury stock method.

Non-Controlling Interest

Non-Controlling Interests

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

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 December 31, 2017 and 2016, respectively, principally due to the short-term nature, maturities or nature of interest rates of the above listed items.

Fair Value Measurements

Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. The established framework for measuring fair value establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

There are three levels of valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:


Level 1 -	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an on-going basis.


Level 2 -	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the term, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.


Level 3 -	Inputs that are unobservable and significant to the fair value measurement (including the Company’s own assumptions in determining fair value).