ERIN ENERGY CORP., 10-K filed on 3/16/2017
Annual Report
Document And Entity Information (USD $)
12 Months Ended
Dec. 31, 2016
Mar. 7, 2017
Jun. 30, 2016
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, 2016 
 
 
Document Fiscal Year Focus
2016 
 
 
Document Fiscal Period Focus
FY 
 
 
Amendment Flag
false 
 
 
Entity Common Stock, Shares Outstanding
 
213,223,392 
 
Entity Well-known Seasoned Issuer
No 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Public Float
 
 
$ 218,029,463 
CONSOLIDATED BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Current assets:
 
 
Cash and cash equivalents
$ 7,177 
$ 8,363 
Restricted cash
2,600 
8,661 
Accounts receivable - trade
0 
1,029 
Accounts receivable - partners
674 
287 
Accounts receivable - related party
1,956 
1,186 
Accounts receivable - other
29 
28 
Crude oil inventory
9,398 
4,800 
Prepaids and other current assets
872 
684 
Total current assets
22,706 
25,027 
Property, plant and equipment:
 
 
Oil and gas properties (successful efforts method of accounting), net
265,713 
368,891 
Other property, plant and equipment, net
716 
1,174 
Total property, plant and equipment, net
266,429 
370,065 
Other non-current assets
 
 
Other non-current assets
66 
67 
Other assets, net
66 
67 
Total assets
289,201 
395,159 
Current liabilities:
 
 
Accounts payable and accrued liabilities
244,963 
213,120 
Accounts payable and accrued liabilities - related party
29,513 
30,133 
Current portion of long-term debt, net
12,627 
96,558 
Total current liabilities
287,100 
339,811 
Long-term notes payable - related party
74,446 
0 
Term loan facility
129,800 
120,006 
Asset retirement obligations
22,476 
20,609 
Total liabilities
513,821 
480,426 
Commitments and contingencies (Note 11)
   
   
Capital deficiency:
 
 
Preferred stock $0.001 par value - 50,000,000 shares authorized; none issued and outstanding as of December 31, 2016 and 2015, respectively
0 
0 
Common stock $0.001 par value - 416,666,667 shares authorized; 212,622,218 and 211,615,773 shares outstanding as of December 31, 2016 and 2015, respectively
200 
212 
Additional paid-in capital
792,972 
789,615 
Accumulated deficit
(1,018,292)
(875,891)
Treasury stock at cost, 99,932 and -0- shares as of December 31, 2016 and 2015, respectively
(228)
0 
Total capital deficiency - Erin Energy Corporation
(225,335)
(86,064)
Non-controlling interests
715 
797 
Total capital deficiency
(224,620)
(85,267)
Total liabilities and capital deficiency
$ 289,201 
$ 395,159 
CONSOLIDATED BALANCE SHEETS (Parentheticals) (USD $)
Dec. 31, 2016
Dec. 31, 2015
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)
212,622,218 
211,615,773 
Treasury stock, shares (in shares)
99,932 
0 
CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Revenues:
 
 
 
Crude oil sales, net of royalties
$ 77,815 
$ 68,429 
$ 53,844 
Operating costs and expenses:
 
 
 
Production costs
94,607 
90,079 
80,296 
Crude oil inventory (increase) decrease
(1,469)
(2,502)
14,512 
Workover expenses
7,860 
972 
0 
Exploratory expenses
39,269 
16,437 
14,283 
Depreciation, depletion and amortization
58,051 
97,179 
21,590 
Asset retirement obligation accretion
1,867 
1,931 
2,166 
Impairment of oil and gas properties
645 
261,208 
0 
Loss on settlement of asset retirement obligations
205 
3,700 
0 
General and administrative expenses
13,772 
15,905 
14,322 
Total operating costs and expenses
214,807 
484,862 
147,169 
Operating loss
(136,992)
(416,433)
(93,325)
Other income (expense):
 
 
 
Currency transaction gain
15,674 
2,520 
1,758 
Interest expense
(21,924)
(17,986)
(4,383)
Other, net
0 
0 
(358)
Total other expense
(6,250)
(15,466)
(2,983)
Loss before income taxes
(143,242)
(431,899)
(96,308)
Income tax expense
0 
0 
0 
Net loss before non-controlling interest
(143,242)
(431,899)
(96,308)
Net loss attributable to non-controlling interest
841 
962 
246 
Net loss attributable to Erin Energy Corporation
$ (142,401)
$ (430,937)
$ (96,062)
Net loss attributable to Erin Energy Corporation per common share:
 
 
 
Basic (Dollars per share)
$ (0.67)
$ (2.04)
$ (0.49)
Diluted (Dollars per share)
$ (0.67)
$ (2.04)
$ (0.49)
Weighted-average common shares outstanding:
 
 
 
Basic (shares)
212,318 
211,616 
194,745 
Diluted (shares)
212,318 
211,616 
194,745 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
 
 
 
Net loss, before non-controlling interest
$ (143,242)
$ (431,899)
$ (96,308)
Other comprehensive income (loss):
 
 
 
Foreign currency translation
0 
0 
0 
Total other comprehensive (loss) income
0 
0 
0 
Comprehensive loss
(143,242)
(431,899)
(96,308)
Comprehensive loss attributable to non-controlling interests
841 
962 
246 
Comprehensive loss attributable to Erin Energy Corporation
$ (142,401)
$ (430,937)
$ (96,062)
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (CAPITAL DEFICIENCY) (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common Stock
Additional Paid-in Capital
Accumulated Deficit
Treasury Stock
Non-controlling Interest
Beginning balance at Dec. 31, 2013
$ 387,946 
$ 146 
$ 736,692 
$ (348,892)
$ 0 
$ 0 
Beginning balance (in shares) at Dec. 31, 2013
 
146,637,000 
 
 
 
 
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
 
Common stock issued (in shares)
 
63,671,000 
 
 
 
 
Common stock issued
270,415 
64 
270,351 
 
 
 
Stock-based compensation
3,492 
 
3,492 
 
 
 
Allied acquisition
(220,000)
 
(220,000)
 
 
 
Allied Transaction adjustments
(12,440)
 
(12,440)
 
 
 
Non-controlling interest
900 
 
 
 
 
900 
Net loss
(96,308)
 
 
(96,062)
 
(246)
Ending balance at Dec. 31, 2014
334,005 
210 
778,095 
(444,954)
0 
654 
Ending balance (in shares) at Dec. 31, 2014
 
210,308,000 
 
 
 
 
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 
 
 
 
Non-controlling interest
1,105 
 
 
 
 
1,105 
Net loss
(431,899)
 
 
(430,937)
 
(962)
Warrants issued with debt
4,911 
 
4,911 
 
 
 
Ending balance at Dec. 31, 2015
(85,267)
212 
789,615 
(875,891)
0 
797 
Ending balance (in shares) at Dec. 31, 2015
211,615,773 
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 
 
 
 
Non-controlling interest
759 
 
 
 
 
759 
Net loss
(143,242)
 
 
(142,401)
 
(841)
Warrants issued with debt
53 
 
53 
 
 
 
Transfer to treasury upon vesting of restricted stock
(228)
 
 
 
(228)
 
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 
 
 
 
 
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Cash flows from operating activities
 
 
 
Net loss, before non-controlling interest
$ (143,242)
$ (431,899)
$ (96,308)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
 
 
 
Depreciation, depletion and amortization
58,051 
97,179 
21,590 
Impairment of oil and gas properties
645 
261,208 
0 
Write-off of suspended exploratory well costs
33,031 
0 
0 
Asset retirement obligation accretion
1,867 
1,931 
2,166 
Amortization of debt issuance costs
3,615 
2,766 
147 
Loss on settlement of asset retirement obligations
0 
3,653 
0 
Related party liability offset
0 
0 
(32,880)
Unrealized currency transaction gain
(15,674)
(2,520)
(1,572)
Share-based compensation
2,941 
5,027 
3,095 
Payments to settle asset retirement obligations
0 
(16,640)
0 
Other
0 
0 
(17)
Changes in operating assets and liabilities:
 
 
 
(Increase) decrease in accounts receivable
630 
(804)
562 
(Increase) decrease in crude oil inventory
(1,469)
(2,502)
14,512 
(Increase) decrease in prepaids and other current assets
(187)
746 
(1,672)
Increase in other non-current assets
0 
0 
(15)
Increase in accounts payable and accrued liabilities
66,147 
84,000 
56,845 
Net cash provided by (used in) operating activities
6,355 
2,145 
(33,547)
Cash flows from investing activities
 
 
 
Capital expenditures
(19,293)
(84,039)
(128,510)
Allied transaction
0 
0 
(170,000)
Net cash used in investing activities
(19,293)
(84,039)
(298,510)
Cash flows from financing activities
 
 
 
Proceeds from the issuance of common stock
0 
0 
270,000 
Proceeds from the exercise of stock options and warrants
364 
1,855 
415 
Payments for treasury stock arising from withholding taxes upon restricted stock vesting
(228)
0 
0 
Proceeds from (repayments of) term loan facility
(5,968)
(337)
100,000 
Proceeds from note payable - related party, net
6,829 
61,815 
10,649 
Proceeds from short-term note payable
504 
0 
0 
Repayment of short-term note payable
(449)
0 
0 
Debt issuance costs
(1,040)
0 
(2,082)
Funds released from restricted cash, net
6,061 
0 
0 
Funds restricted for debt service
0 
0 
(10,405)
Allied Transaction adjustments
0 
0 
(12,440)
Funding from non-controlling interest
0 
553 
900 
Net cash provided by financing activities
6,073 
63,886 
357,037 
Effect of exchange rate on cash and cash equivalents
5,679 
1,228 
0 
Net increase (decrease) in cash and cash equivalents
(1,186)
(16,780)
24,980 
Cash and cash equivalents at beginning of year
8,363 
25,143 
163 
Cash and cash equivalents at end of year
7,177 
8,363 
25,143 
Cash paid for:
 
 
 
Interest, net of amounts capitalized
10,407 
11,114 
8 
Supplemental disclosure of non-cash investing and financing activities:
 
 
 
Issuance of common shares for settlement of liabilities
0 
125 
0 
Discount on notes payable pursuant to issuance of warrants
53 
4,911 
0 
Reduction in oil and gas properties arising from settlement of accounts payable and accrued liabilities
10,048 
0 
0 
Reduction in accounts payable from settlement of Northern Offshore contingency
0 
24,307 
0 
Receivable from non-controlling interest
0 
552 
0 
Related party accounts payable, net, settled with related party notes payable
0 
0 
(32,880)
Change in asset retirement obligation estimate
$ 0 
$ (4,284)
$ 3,766 
Basis of Presentation and Significant Accounting Policies
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.
 
In February 2014, the Company completed the acquisition of the remaining economic interests that it did not already own in the Production Sharing Contract covering Oil Mining Leases 120 and 121 located offshore Nigeria (the “OMLs”), which include the currently producing Oyo field (the “Allied Assets”), from Allied (the “Allied Transaction”). Pursuant to the terms of the Transfer Agreement entered into with Allied, the Company issued approximately 82.9 million shares of common stock to Allied, as partial consideration for the Allied Assets. Allied is a subsidiary of CEHL, the Company’s majority shareholder, and deemed to be under common control. Accordingly, the net assets acquired from Allied were recorded at their respective carrying values as of the acquisition date. The shares issued to Allied and the financial statements presented for all periods included herein are presented as though the transfer of the Allied Assets had occurred in June 2012, the effective date when Allied acquired the Allied Assets from an independent third party. See Note 4. — Acquisitions for further information.

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

Adoption of Previously Issued ASUs

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires that debt issuance costs be presented as a direct deduction from the carrying amount of the related debt liability, consistent with the presentation of debt discounts. Prior to the issuance of ASU 2015-03, the Company recorded and presented debt issuance costs as part of prepaids and other current assets, separate from the related debt liability. ASU 2015-03 does not change the recognition and measurement requirement for debt issuance costs. Other than this reclassification, the adoption of ASU 2015-03 did not have an impact on the Company's consolidated financial statements.
 
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, 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, 2016 and 2015, consists of $2.6 million and $8.7 million, respectively, 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, 2016 and 2015, no allowance for doubtful accounts was necessary.
 
As of December 31, 2015, the Company had a $1.0 million trade receivable for the remaining balance owed from its December 2015 crude oil sale. As of December 31, 2016, its trade receivable balance was nil.

Partner accounts receivable consist of balances owed from joint venture (“JV”) partners. As of December 31, 2016 and 2015, the Company was owed $0.7 million and $0.3 million 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 market 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 $9.4 million and $4.8 million as of December 31, 2016 and 2015, 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 market, which approximates fair value, and they are regularly assessed for obsolescence. Oilfield materials and supplies inventory balances were $34.7 million and $30.0 million at December 31, 2016 and 2015, 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 13. — 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 a result of the adoption of ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, the Company reclassified approximately $1.6 million of unamortized debt issuance costs related to its Term Loan Facility (see Note 9 - Debt) from prepaids and other current assets to current portion of long-term debt within its consolidated balance sheet as of December 31, 2015.

As of December 31, 2016 and 2015, unamortized debt issuance costs were $2.3 million and $1.6 million, of which $1.6 million and nil was classified as long-term, respectively. The current portion of the debt issuance costs, which was $0.8 million and $1.6 million as of December 31, 2016 and 2015, 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, 2016 and 2015, the Company capitalized nil and $2.2 million, respectively, in interest cost as additions to property, plant and equipment related to the Oyo field redevelopment campaign.

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 year ended December 31, 2016, 99,932 shares were withheld for taxes at a total cost of $0.2 million. The Company had no treasury stock withheld for taxes during the year ended December 31, 2015.

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, 2016.

 
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 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, non-vested restricted stock awards, and stock warrants and conversion of the 2014 Convertible Subordinated Note, 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 Convertible Subordinated Note that were excluded from dilutive shares outstanding during the years ended December 31, 2016, 2015 and 2014, as these securities are anti-dilutive because the Company was in a loss position each year.
 
 
Years Ended December 31,
(In thousands)
2016
 
2015
 
2014
Stock options
230

 
1,101

 
1,038

Stock warrants
3

 
541

 
6

Unvested restricted stock awards
1,942

 
1,275

 
997

Convertible note
—

 
12,379

 
10,932

 
2,175

 
15,296

 
12,973


 
Upon the occurrence of certain events, the Company is also contingently liable to make additional payments to Allied, under the Transfer Agreement, up to an additional amount totaling $50.0 million in cash, or the equivalent in shares of the Company’s common stock, at Allied’s option. See Note 11. — 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, 2016 and 2015, the non-controlling interest recorded in equity was $0.7 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 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. 

The following table presents information about the Company’s oil and gas properties measured at fair value on a non-recurring basis:

 
Level 3
 
As of December 31,
(in thousands)
2016
 
2015
Value of oil and gas properties (1)
$
—

 
$
293,408


(1)
This represents non-financial assets that are measured at fair value on a non-recurring basis due to impairments. This is the fair value of the asset base that was subjected to impairment and does not reflect the entire asset balance as presented on the accompanying balance sheets. Please see Note 5. — Property, Plant and Equipment for further information. Amounts included here are presented only in years where an impairment has occurred.


Other than the write-off of the carrying value of its offshore leases in Kenya (as discussed under Note 5 - 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, 2016 and 2015, 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, 2016 and 2015, the Company sold its crude oil under spot sales contracts with one customer and two customers, respectively. The Company believes that the potential loss of one or both of these customers 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 2015 and 2014 consolidated financial statements to conform to the 2016 presentation. These reclassifications were not material to the accompanying consolidated financial statements.

Recently Issued Accounting Standards

In February 2016, the 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 standard could have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-07, Investments-Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting. ASU No. 2016-07 eliminates the requirement to retroactively adopt the equity method of accounting. ASU No. 2016-07 is effective for interim and annual periods beginning after December 15, 2016, and the Company will adopt this standards update, as required, beginning with the first quarter of 2017. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Consideration (Reporting Revenue Gross versus Net). ASU No. 2016-08 requires that an entity should recognize revenue 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. ASU No. 2016-08 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 standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The areas of simplification in ASU No. 2016-09 involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU No. 2016-09 is effective for interim and annual periods beginning after December 15, 2016, and the Company will adopt this standards update, as required, beginning with the first quarter of 2017. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. ASU No. 2016-10 clarifies two aspects of Topic 606: identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU No. 2016-10 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 standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. ASU No. 2016-11 rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities - Oil and Gas, effective upon adoption of Topic 606. ASU No. 2016-11 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 standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. The core principle of ASU No. 2016-12 is that an entity should recognize revenue 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. ASU No. 2016-12 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 standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in reporting certain items in the statement of cash flows. ASU No. 2016-15 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 Company does not expect adoption of ASU 2016-15 to have a material effect on its consolidated financial statements.

In October 2016, the FASB issued ASU 2016-16, Intra-Entity Transfers of Assets Other Than Inventory, which provides guidance on recognition of current income tax consequences for intra-entity asset transfers (other than inventory) at the time of transfer. This represents a change from current GAAP, where the consolidated tax consequences of intra-entity asset transfers are deferred until the transferred asset is sold to a third party or otherwise recovered through use. The guidance is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption at the beginning of an annual period is permitted. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

In October 2016, the FASB issued ASU 2016-17, Interests Held through Related Parties That Are under Common Control, which modifies existing guidance with respect to how a decision maker that holds an indirect interest in a VIE through a common control party determines whether it is the primary beneficiary of the VIE as part of the analysis of whether the VIE would need to be consolidated. Under this ASU, a decision maker would need to consider only its proportionate indirect interest in the VIE held through a common control party. This ASU is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. ASU 2016-18 is effective for fiscal years beginning after December 15, 2018 (including interim periods within those periods) using a retrospective transition method to each period presented. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.
Company Description
Company Description
COMPANY DESCRIPTION
 
Erin Energy Corporation (NYSE MKT: 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 seven licenses across four countries covering an area of approximately 19,000 square kilometers (approximately 5 million acres). The Company owns producing properties and conducts exploration activities offshore Nigeria, conducts exploration activities offshore Ghana and The Gambia, and onshore Kenya.
 
The Company is headquartered in Houston, Texas and has offices in Lagos, Nigeria, Nairobi, Kenya, Banjul, The Gambia, Accra, Ghana and Johannesburg, South Africa.
 
The Company’s operating subsidiaries include 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 its majority shareholder, CAMAC Energy Holdings Limited (“CEHL”), and its affiliates, which include Allied Energy Plc (“Allied”). See Note 10. — Related Party Transactions for further information.

In May 2016, Dr. Kase L. Lawal retired from service as a member and Executive Chairman of the Board of Directors and Chief Executive Officer. John Hofmeister, a then current member of the Board of Directors, succeeded Dr. Lawal as the Chairman of the Board of Directors, and Babatunde (Segun) Omidele, the Company's then Chief Operating Officer, succeeded Dr. Lawal as the Chief Executive Officer. 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 has 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 conducts a search for a permanent replacement for Mr. Omidele.

Liquidity Matters and Going Concern
Liquidity Matters and Going Concern
LIQUIDITY AND GOING CONCERN

The Company has incurred losses from operations in each of the years ended December 31, 2016, 2015 and 2014. As of December 31, 2016, the Company's total current liabilities of $287.1 million exceeded its total current assets of $22.7 million, resulting in a working capital deficit of $264.4 million. As a result of the current low commodity prices and the Company’s low oil production volumes due to the recent mechanical problem associated with well Oyo-8 that was resolved during the earlier part of 2016, 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 from the field. The Company is currently working on relocating an existing gaslift line to well Oyo-7 to enable continuous gaslift operation. 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 third quarter of 2017.

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 2017 exploration and development campaign, vi) farming-out a portion of our rights to certain of our 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.
Acquisitions
Acquisitions
ACQUISITIONS
 
The Allied Assets
 
In February 2014, the Company completed the Allied Transaction, thereby acquiring the Allied Assets. Pursuant to the terms of the Transfer Agreement, the Company, as partial consideration for the Allied Assets, paid $170.0 million in cash, issued approximately 82.9 million shares of the Company’s common stock and entered into the 2014 Convertible Subordinated Note.
 
To fund the cash portion of the Allied Transaction and a portion of the anticipated capital expenditures for the development of the Oyo field, the Company also entered into a Share Purchase Agreement (the “Share Purchase Agreement”) with the Public Investment Corporation (SOC) Limited, a state-owned company incorporated in the Republic of South Africa (“PIC”), for an aggregate cash investment of $270.0 million through a private placement of 62.8 million shares of common stock (the “Private Placement”). Additional contingent payments are owed to Allied upon the occurrence of certain future events. See Note 11. — Commitments and Contingencies for additional information regarding the contingent payments due to Allied.
 
The table below sets forth a summary of the contractual purchase consideration paid for the Allied Assets (In thousands):
 
Cash consideration paid
$
170,000

Erin Energy Corporation common stock (1)
—

Long-term convertible subordinated note payable - related party
50,000

Total purchase price
$
220,000

Asset acquired and liabilities assumed as of February 21, 2014:
 
Property, plant and equipment, net
$
248,736

Accounts payable
(25,429
)
Asset retirement obligations
(20,890
)
Net assets acquired
202,417

Excess of consideration paid over carrying value of assets acquired
$
17,583

(1) Because the cash and debt consideration exceeds the carrying value of the assets acquired, no value was assigned to the shares issued
 
Because Allied is a wholly owned subsidiary of CEHL, the Company’s majority shareholder, Allied and the Company are deemed under common control. Accordingly, the net assets acquired from Allied were recorded at their respective carrying values as of the acquisition date. The consolidated financial statements, included herein, are presented as though the Allied Transaction had occurred in June 2012, the date Allied acquired the Allied Assets from an independent third party.
 
For the periods prior to January 1, 2014, the Allied Assets were recorded as if CEHL had acquired the Allied Assets and contributed them to the Company. This includes the cost to acquire the Allied Assets from a third party in June 2012, as well as costs related to the drilling of the Oyo-7 well incurred by Allied in 2013.
 
Award of the Tano Block in Ghana
 
In April 2014, the Company, through an indirect 50%-owned subsidiary, signed a Petroleum Agreement with the Republic of Ghana (the “Petroleum Agreement”) for the Expanded Shallow Water Tano block offshore Ghana ("ESWT"). The contracting parties, which hold 90% of the participating interest in the block, are Erin Energy Ghana Limited as the operator, GNPC Exploration and Production Company Limited, and Base Energy (collectively the "Contracting Parties"), holding 60%, 25%, and 15% share of the participating interest of the Contracting Parties, respectively. The Ghana National Petroleum Company initially has a 10% carried interest through the exploration phase, and will have the option to acquire an additional paying interest of up to 10% following a declaration of commercial discovery.
 
The ESWT block contains three previously discovered fields (the "Fields") and the work program requires the Contracting Parties to determine, within nine months of the effective date of the Petroleum Agreement, the economic viability of developing the Fields. In addition, the Petroleum Agreement provides for an initial exploration period of two years from the effective date of the Petroleum Agreement, with specified work obligations during that period, including the reprocessing of existing 2-D and 3-D seismic data and the drilling of one exploration well on the ESWT block. The Contracting Parties have the right to apply for a first extension period of one and one-half years and a second extension period of up to two and one-half years. Each extension period has specified additional minimum work obligations, including (i) conducting geological and geophysical studies during the first extension period and (ii) drilling one exploration well during the first extension period and, depending on the length of the extension, one or two wells during the second extension period.

In January 2015, the Petroleum Agreement became effective, following the signing of a Joint Operating Agreement between the Contracting Parties.
In October 2015, at the completion of the initial technical and commercial evaluation of the Fields, the Contracting Parties concluded that certain fiscal terms in the Petroleum Agreement had to be adjusted in order to achieve commerciality of the Fields under current economic conditions. The Contracting Parties have presented this conclusion to the relevant government entities. The Ghanian Government is currently reviewing the requests for adjustment of the fiscal terms, and has granted the Company an extension of the Initial Exploration Period for eighteen months until the end of July 2018.
Property, Plant and Equipment
Property, Plant and Equipment
PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment were comprised of the following:
 
 
As of December 31,
(In thousands)
2016
 
2015
Wells and production facilities
$
318,739

 
$
329,133

Proved properties
386,196

 
386,196

Work in progress and exploration inventory
34,712

 
65,043

Oilfield assets
739,647

 
780,372

Accumulated depletion
(483,754
)
 
(421,921
)
Oilfield assets, net
255,893

 
358,451

Unevaluated leaseholds
9,820

 
10,440

Oil and gas properties, net
265,713

 
368,891

Other property and equipment
3,040

 
2,963

Accumulated depreciation
(2,324
)
 
(1,789
)
Other property and equipment, net
716

 
1,174

Total property, plant and equipment, net
$
266,429

 
$
370,065


 
All of the Company’s oilfield assets are located offshore Nigeria in the OMLs. “Work-in-progress and exploration inventory” includes suspended costs for wells that are not yet completed, as well as 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. See Note 6. — Suspended Exploratory Well Costs for further information
 
The Company’s unevaluated leasehold costs include costs to acquire the rights to the exploration acreage in its various oil and gas properties. The $9.8 million unevaluated leasehold cost as of December 31, 2016 includes the $1.0 million payment during 2015 to extend the initial exploration period for the Gambia Licenses and the $1.2 million payment in 2014 to acquire rights to the Ghana properties. 
 
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 December 2015, 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 $228.6 million to reduce the carrying value of its oil and gas properties to their estimated fair values as of December 31, 2015. In addition, the Company recorded a charge of $32.6 million to write-off the carrying value of well Oyo-5 from work in progress because the Company no longer intends to recomplete it into a water injection well under current plans.
Suspended Exploratory Well Costs
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, 2015, the Company’s suspended exploratory well costs were $26.5 million for the costs related to the Miocene exploratory drilling activities. Plans are underway to secure a rig to drill at least one exploration well in the nearby G-Prospect. However, due to current economics, the primary objective of the G-Prospect is 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 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, 2015 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 current drilling plans will no longer specifically target such area due to current economics.
Accounts Payable and Accrued Liabilities
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, 2016 and 2015:
 
As of December 31,
(In thousands)
2016
 
2015
Accounts payable - vendors
$
173,306

 
$
153,085

Amounts due to government entities
66,573

 
53,119

Accrued interest
3,074

 
2,510

Accrued payroll and benefits
1,204

 
629

Other liabilities
806

 
3,777

 
$
244,963

 
$
213,120

Asset Retirement Obligations
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, 2016 and 2015:
 
(In thousands)
2016
 
2015
Asset retirement obligations at January 1
$
20,609

 
$
26,533

Accretion expense
1,867

 
1,931

Additions
—

 
9,416

Revisions in estimated liabilities
—

 
(4,284
)
Loss on settlement of asset retirement obligations
—

 
3,653

Payments to settle asset retirement obligations
—

 
(16,640
)
Asset retirement obligations at December 31
$
22,476

 
$
20,609


 
In April 2015, the Company completed plug and abandonment ("P&A") activities for well Oyo-6 that was previously shut-in. Actual P&A expenditures exceeded estimated P&A liabilities by approximately $3.7 million. Accordingly, the Company recorded a $3.7 million loss on settlement of asset retirement obligations during the year ended December 31, 2015.

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, 2016 and 2015:
 
 
As of December 31,
(In thousands)
2016
 
2015
Asset retirement obligations, current portion
$
—

 
$
—

Asset retirement obligations, long-term portion
22,476

 
20,609

 
$
22,476

 
$
20,609

Debt
Debt
DEBT
 
Short-Term Debt:

Short-Term Borrowing - TOTSA Advances

In May 2016, the Company received $4.7 million as an advance under a prepayment agreement (the “May Advance”) with TOTSA Total Oil Trading SA ("TOTSA"). Interest accrued on the May Advance at the rate of the 60-day LIBOR plus 5% per annum. Repayment of the May Advance was made from proceeds received from the June 2016 crude oil lifting.

In August 2016, the Company received $6.0 million as an advance under a prepayment agreement with TOTSA (the “August Advance”). Interest accrued on the August Advance at the rate of the 60-day LIBOR plus 5% per annum. Repayment of the August Advance was made from proceeds received from the August 2016 crude oil lifting.

Short-Term Note Payable

In June 2016, the Company borrowed approximately $0.5 million under a 30-day Promissory Note agreement entered into with a Nigerian bank (the “2016 Short-Term Note”), and had a facility flat fee of 2.5%. The 2016 Short-Term Note was renewed for another 30 days in July 2016 at a flat fee facility rate of 2.5%, and was fully repaid in July 2016.

Long-Term Debt- Term Loan Facility:

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, 2016, $2.3 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, 2016, the Company made payments of $0.4 million and $5.6 million for the principal repayment of the Naira portion of the loan and for the U.S. dollar principal, respectively.

As of December 31, 2016, the Company recognized an unrealized foreign currency gain of $4.3 million on the Naira portion of the loan, reducing the balance under the Term Loan Facility to $87.1 million, net of debt discount. Of this amount, $74.4 million was classified as long-term and $12.6 million as short-term. Accrued interest for the Term Loan Facility was $3.1 million as of December 31, 2016. Scheduled principal repayments on the outstanding balance on the Term Loan Facility are as follows (in thousands):

Scheduled payments by year
 
Principal
2017
 
$
13,413

2018
 
19,673

2019
 
21,460

2020
 
27,265

2021 and thereafter
 
7,609

Total principal payments
 
$
89,420

Less: Unamortized debt issuance costs
 
2,347

Total Term Loan Facility, net
 
$
87,073



Long-Term Debt - Related Party:

As of December 31, 2016, 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, is the holder of each of the 2011 Promissory Note, the 2014 Convertible Subordinated Note, and the 2015 Convertible Note (collectively the “Allied Notes”). Each of the Allied 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, 2016, the Company was not in compliance with the default provisions of the Allied Notes with respect to the payment of quarterly interest. Further, the risk of cross-default exists for each of the Allied Notes if the holder of the Term Loan Facility exercises its right to terminate the Term Loan Facility and accelerate its maturity. Allied agreed to waive its rights under all default provisions of each of the Allied Notes through April 2018.

2011 Promissory Note
 
The Company has a $25.0 million borrowing facility under the 2011 Promissory Note with Allied. 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 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. 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, 2016, the outstanding principal and accrued interest under the 2011 Promissory Note was $24.9 million and $1.6 million, respectively.
 
2014 Convertible Subordinated Note
 
As partial consideration in connection with the February 2014 acquisition of the Allied Assets, the Company issued the $50.0 million 2014 Convertible Subordinated Note in favor of Allied. 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 agreement 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, 2016, the Company owed $8.0 million in interest under the 2014 Convertible Subordinated Note.

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. Allied 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 of December 31, 2016, the outstanding principal under the 2014 Convertible Subordinated Note was $50.0 million.

2015 Convertible Note

In March 2015, the Company entered into a borrowing facility with Allied in the form of 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 MKT for a share of common stock for the five complete trading days immediately preceding the conversion date.

As of December 31, 2016, the Company had borrowed $48.5 million under the note and issued to Allied warrants to purchase approximately 2.7 million shares of the Company’s common stock at prices ranging from $2.00 to $7.85 per share. The total fair market value of the warrants amounting to $5.0 million based on the Black-Scholes option pricing model was recorded as a discount from the note, and is being amortized using the effective interest method over the life of the note. As of December 31, 2016, the unamortized balance of the note discount was nil.

Additional warrants are issuable in connection with future borrowings, with the per share price for those warrants determined based on the market price of the Company’s common stock at the time of such future borrowings. As of December 31, 2016, the outstanding balance of the 2015 Convertible Note, net of discount, was $48.5 million. Accrued interest on the 2015 Convertible Note was $4.9 million as of December 31, 2016.

2016 Promissory Note

In March 2016, the Company borrowed $3.0 million under a short-term Promissory Note agreement entered into with an entity related to the Company's majority shareholder, which accrued interest at a rate of the 30-day LIBOR plus 7% per annum.

In April 2016, the Company borrowed an additional sum of $1.0 million from the same lender, under another short-term Promissory Note, which also accrued interest at a rate of the 30-day LIBOR plus 7% per annum.

In May 2016, the Lender of the two Promissory Notes agreed to combine both notes into a $10.0 million borrowing facility (the "2016 Promissory Note"). Interest accrues at a rate of the 30-day LIBOR plus 7% per annum.

Subsequent to the combination of both notes into the 2016 Promissory Note, the Company had additional drawings under the 2016 Promissory Note totaling $2.4 million.

As of December 31, 2016, the outstanding balance under the 2016 Promissory Note was $6.4 million. Accrued interest on the 2016 Promissory Note was $0.4 million as of December 31, 2016. 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.
Related Party Transactions
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. The table below sets forth the related party assets and liabilities as of December 31, 2016 and 2015:
 
 
As of December 31,
(In thousands)
2016
 
2015
Accounts receivable, CEHL
$
1,956

 
$
1,186

Accounts payable and accrued liabilities, CEHL
$
29,513

 
$
30,133

Long-term notes payable - related party, CEHL
$
129,796

 
$
120,006



As of December 31, 2016 and 2015, the related party receivable balances of $2.0 million and $1.2 million, respectively, were for advance payments made for certain transactions on behalf of affiliates.
 
As of December 31, 2016 and 2015, the Company owed $29.5 million and $30.1 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, 2016 and 2015, accrued and unpaid interest on the various related party notes payable were $15.2 million and $8.3 million, respectively.

As of December 31, 2016, 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 borrowing under the 2015 Convertible Note, net of discount, and $6.4 million under the 2016 Promissory Note. As of December 31, 2015, the Company had a long-term note payable balance of $120.0 million owed to an affiliate, consisting of $25.0 million in borrowings under the 2011 Promissory Note, $50.0 million in borrowings under the 2014 Convertible Subordinated Note, and $45.0 million borrowing under the 2015 Convertible Note, net of discount. See Note 9. — 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, 2016, 2015 and 2014:
 
 
Year Ended December 31,
(In thousands)
2016
 
2015
 
2014
Total operating expenses, CEHL
$
14,621

 
$
15,106

 
$
14,449

Interest expense, CEHL
$
6,843

 
$
5,490

 
$
2,414


 
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, 2016, 2015 and 2014, the Company incurred operating costs amounting to approximately $14.6 million, $15.1 million and $14.4 million, respectively.

During the years ended December 31, 2016, 2015 and 2014, the Company incurred interest expense, excluding debt discount amortization, totaling approximately $6.8 million, $5.5 million and $2.4 million, respectively, in relation to 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’s majority shareholder owns the remaining 50% non-controlling interest in the Erin Energy Ghana Limited subsidiary. See Note 4. — Acquisitions for further information.
Commitments and Contingencies
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, 2016 and thereafter:
 
 
Payments Due By Period
(In thousands)
Total
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
Operating lease obligations:
 
 
 
 
 
 
 
 
 
 
 
 
 
FPSO and drilling rig
         leases - Nigeria
$
193,451

 
$
48,363

 
$
48,362

 
$
48,363

 
$
48,363

 
$
—

 
$
—

Office leases
1,600

 
537

 
493

 
450

 
81

 
39

 
—

Minimum work obligations:
 
 
 
 
 
 
 
 
 
 
 
 
 
Kenya
65,133

 
65,133

 
—

 
—

 
—

 
—

 
—

The Gambia
1,200

 
600

 
600

 
—

 
—

 
—

 
—

Ghana
10,650

 
10,650

 
—

 
—

 
—

 
—

 
—

Total
$
272,034

 
$
125,283

 
$
49,455

 
$
48,813

 
$
48,444

 
$
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.

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, 2016, 2015 and 2014, was $1.1 million, $0.9 million and $1.0 million, respectively. At December 31, 2016, minimum future rental commitments for office leases were a total of $1.6 million.
 
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, 2016, 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 is 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. The Claimants are seeking an order that the Respondents pay the sum of approximately $20.2 million together with interest and costs.  The Company filed its Statement of Defense on October 4, 2016. The London Court of International Arbitration has set the arbitration hearing to begin on October 3, 2017 with a possible earlier hearing start date, subject to availability.

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 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 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 our 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, which motions were heard on January 18, 2017.

On May 13, 2016, CEONA Contracting (UK) Limited ("Ceona") initiated arbitration proceedings against the Company for $2.9 million, together with costs, expenses and interest, for work done in relation to the Company's ordinary course of business.  On August 22, 2016, the parties entered into a settlement agreement, and as a result thereof, the Company decreased its accounts payable and accrued liabilities by $2.7 million with a corresponding decrease to its oil and gas properties as of December 31, 2016.  Also as part of the settlement agreement, the Company paid $1.1 million to Ceona on August 31, 2016.

On July 29, 2016, a judgment was entered against the Company in the amount of $2.4 million, including interest, in relation to amounts due to a contractor (Polarcus MC Ltd.) in the ordinary course of business.  A further sum of $0.4 million was payable under the relevant contract, and the contractor has made a further claim, which is disputed by the Company, for an additional $0.3 million plus legal costs. Under a further court order dated September 9, 2016, further proceedings in respect of the matter have been stayed pending fulfillment of certain settlement terms.  As of the date of this report, the judgment debt has been completely satisfied, with all remaining sums claimed by this contractor discharged in January 2017.

Unrecognized Loss Contingency

As of December 31, 2016, 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, the likelihood of being assessed penalty and interest is reasonably possible, with an estimated liability up to $17.1 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 shall be determined by calculating the average closing price of the Company’s common stock over a period of thirty days, counted back from the first business day immediately prior to the approval of a development plan by DPR or the date of the first hydrocarbon production in commercial quantities, as applicable.
 
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 to Allied 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 to Allied an amount equal to twenty percent (20%) of any successful equity fundraising event completed during the remaining term of the 2015 Convertible Note.
Stock Based Compensation
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, 2016.

 
Shares
Underlying
Options
(In Thousands)
 
Weighted-Average
Exercise Price
 
Weighted-Average
Remaining
Contractual Term
(Years)
Stock Options
 
Outstanding at December 31, 2015
2,532

 
$2.29
 
1.6
Granted
—

 
$—
 
—
Exercised
(1,200
)
 
$1.84
 
—
Forfeited
(27
)
 
$3.42
 
—
Expired
(158
)
 
$3.70
 
—
Outstanding at December 31, 2016
1,147

 
$2.54
 
2.0
Expected to vest
908

 
$2.21
 
1.6
Exercisable at December 31, 2016
239

 
$3.79
 
3.4

 
During the year ended December 31, 2016, the Company issued 437,638 shares of common stock as a result of the exercise of stock options, of which 246,838 shares of common stock were issued as a result of the cashless exercise of 1,008,803 options. Also, during the year ended December 31, 2016, options to purchase 157,768 shares of common stock expired, and options to purchase 27,052 shares were forfeited.

The total intrinsic value of options outstanding and options exercisable were $0.9 million and $0.9 million, respectively, at December 31, 2016. The total intrinsic values realized by recipients on options exercised were $0.7 million, $0.01 million, and $0.9 million in 2016, 2015 and 2014, respectively.
 
The Company recorded compensation expense relative to stock options in 2016, 2015 and 2014 of $0.4 million, $1.3 million and $1.3 million, respectively. As of December 31, 2016, there were approximately $0.3 million of total unrecognized compensation cost related to stock options, with $0.2 million and $0.1 million to be recognized during the years ended December 31, 2017 and 2018, 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.
 
 
2016
 
2015
 
2014
Expected price volatility
—%
 
77.1% - 83.1%

 
87.7
%
Risk free interest rate (U.S. treasury bonds)
—%
 
1.0 to 1.2 %

 
1.1
%
Expected annual dividend yield
—
 
—

 
—

Expected option term (years)
—
 
3.0

 
3.0

Weighted-average grant date fair value per share
—
 
$
2.73

 
$
1.92


 
Stock Warrants
 
The table below sets forth a summary of stock warrant activity for the year ended December 31, 2016.
 
 
Shares
Underlying
Warrants
(In Thousands)
 
Weighted-Average
Exercise Price
 
Weighted-Average
Remaining
Contractual Term
(Years)
Stock warrants
 
Outstanding at December 31, 2015
2,935

 
$3.61
 
4.2
Granted
48

 
$2.07
 
4.3
Exercised
—

 
$—
 
—
Forfeited
—

 
$—
 
—
Expired
—

 
$—
 
—
Outstanding at December 31, 2016
2,983

 
$3.59
 
3.2
Expected to vest
—

 
$—
 
—
Exercisable at December 31, 2016
2,983

 
$3.59
 
3.2


The total intrinsic value of warrants outstanding and exercisable was $1.0 million at December 31, 2016.

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 9 – Debt - 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 approximately $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, 2016, 2015 and 2014, the Company recognized stock-based compensation expense of nil, $0.4 million and $0.1 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.
 
 
2016
 
2015
 
2014
Expected price volatility
84.7% - 84.8%

 
76.8% - 83.2%

 
82.7
%
Risk free interest rate (U.S. treasury bonds)
0.8
%
 
0.8% - 1.1%

 
1.1
%
Expected annual dividend yield
—

 
—

 
—

Expected option term (years)
3.0

 
3.0

 
3.0

Weighted-average grant date fair value per share
$
1.12

 
$
1.86

 
$
1.80


 
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, 2016.
 
 
Shares
(In Thousands)
 
Weighted-Average
Grant Date Fair
Value
Restricted Stock
 
 
 
Non-vested at December 31, 2015
1,114

 
$3.21
Granted
1,716

 
$2.16
Vested
(669
)
 
$3.56
Forfeited
(89
)
 
$2.59
Non-vested as of December 31, 2016
2,072

 
$2.25

 
During the year ended December 31, 2016, the Company granted its officers, directors, and employees a total of approximately 1.7 million shares of restricted common stock, including 0.5 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, 2016, 89,461 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 $0.3 million over three years.

The Company recorded compensation expense relative to RSAs, including PBRSAs, in 2016, 2015 and 2014 of $2.5 million, $3.3 million and $1.7 million, respectively.
 
The total grant date fair value of RSA shares that vested during 2016 and 2015 was approximately $2.1 million and $3.1 million, respectively. As of December 31, 2016, there were approximately $1.7 million of total unrecognized compensation cost related to non-vested RSAs, with $1.5 million and $0.2 million to be recognized during the years ended December 31, 2017 and 2018, respectively.
Income Taxes
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)
2016
 
2015
 
2014
Net loss attributable to Erin Energy Corporation before income tax expense
$
(142,401
)
 
$
(430,937
)
 
$
(96,062
)
Expected income tax provision at statutory rate of 35%
(49,840
)
 
(150,828
)
 
(33,622
)
Increase (decrease) due to:
 
 
 
 
 
Foreign rate differential
(17,202
)
 
(59,467
)
 
(10,083
)
Change in valuation allowance
71,148

 
256,910

 
98,376

Investment tax credit - Nigeria
1,991

 
(35,580
)
 
(40,765
)
Non-deductible expenses and other
(6,097
)
 
(11,035
)
 
(13,906
)
Total income tax expense
$
—

 
$
—

 
$
—



Significant components of our deferred tax assets are as follows:
 
As of December 31,
(In thousands)
2016
 
2015
Basis difference in fixed assets
$
(3,249
)
 
$
11,893

Unused capital allowances
572,051

 
506,795

Net operating losses
109,230

 
88,391

Other
12,421

 
12,226

 
690,453

 
619,305

Valuation allowance
(690,453
)
 
(619,305
)
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.
 
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 $690.5 million and $619.3 million were recorded as of December 31, 2016 and 2015, respectively.
 
At December 31, 2016 and 2015, the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.
 
The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:
 
United States:
2007
-
2016
Nigeria:
2010
-
2016
Kenya:
2012
-
2016
The Gambia:
2012
-
2016
Segment Information
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, 2016, 2015, and 2014.
 
(In thousands)
Nigeria
 
Kenya
 
The Gambia
 
Ghana
 
Corporate and Other
 
Total
For the Years Ended December 31,
 
 
 
 
 
 
 
 
 
 
 
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
)
2014
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
53,844

 
$
—

 
$
—

 
$
—

 
$
—

 
$
53,844

Operating loss
$
(64,716
)
 
$
(12,130
)
 
$
(1,347
)
 
$
(492
)
 
$
(14,640
)
 
$
(93,325
)
 
The table below sets forth the total assets by segment as of December 31, 2016 and 2015.
 
(In thousands)
Nigeria
 
Kenya
 
The Gambia
 
Ghana
 
Corporate and Other
 
Total
Total Assets
 
 
 
 
 
 
 
 
 
 
 
December 31, 2016
$
281,050

 
$
698

 
$
3,034

 
$
3,648

 
$
771

 
$
289,201

December 31, 2015
$
387,326

 
$
1,399

 
$
3,016

 
$
2,447

 
$
971

 
$
395,159

Selected Unaudited Quarterly Financial Data
Selected Unaudited Quarterly Financial Data
SELECTED UNAUDITED QUARTERLY FINANCIAL DATA (In thousands, except for per share amounts)
 
 
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
)
 
Three Months Ended,
 
March 31, 2015
 
June 30, 2015
 
September 30, 2015
 
December 31, 2015
Total revenues
$
—

 
$
—

 
$
28,667

 
$
39,762

Operating loss
$
(32,031
)
 
$
(5,821
)
 
$
(53,423
)
 
$
(325,158
)
Net loss attributable to Erin Energy Corporation
$
(33,059
)
 
$
(9,162
)
 
$
(58,682
)
 
$
(330,034
)
Net loss per common share attributable to
   Erin Energy Corporation
 
 
 
 
 
 
 
Basic
$
(0.16
)
 
$
(0.04
)
 
$
(0.28
)
 
$
(1.56
)
Diluted
$
(0.16
)
 
$
(0.04
)
 
$
(0.28
)
 
$
(1.56
)
Correction of Immaterial Error in Previously Issued Consolidated Financial Statements
Correction of Immaterial Error in Previously Issued Consolidated Financial Statements
CORRECTION OF IMMATERIAL ERROR IN PREVIOUSLY ISSUED CONSOLIDATED FINANCIAL STATEMENTS
 
Prior to the filing of the Company's September 30, 2016 Form 10-Q, the management of the Company determined that the impairment calculation of its oil and gas properties as of December 31, 2015 did not exclude estimated future cash flows related to future abandonment costs. As a result, the Company is revising certain of its consolidated financial statements as of and for the year ended December 31, 2015 to correct this error. This prior year error correction did not change the net cash flows provided by or used in operating, investing or financing activities previously reported. The effect of this correction on capital deficiency as of December 31, 2015 was a reduction of $20.6 million, as reflected in the Statement of Changes in Capital Deficiency as of December 31, 2015. After considering Staff Accounting Bulletin No. 99, Assessing Materiality, management does not deem this revision to be material to its consolidated financial statements due to its consideration of the amount and direction of the error and its impact on the quality of key oil and natural gas industry financial metrics.

As a result of the correction, the originally reported net loss for the year ended December 31, 2015 was decreased by $20.6 million, and originally reported basic and diluted loss per share for the year ended December 31, 2015 was decreased by $0.09 per share. 

The following table reflects the amounts within the consolidated balance sheet, statement of operations, and statement of cash flows as originally reported to amounts as now reflected as of and for the year ended December 31, 2015.
(In thousands)
December 31, 2015
 
 
As Originally
 
 
 
 
 
 
Reported
 
Adjustments
 
Corrected
Consolidated Balance Sheet
 
 
 
 
 
 
  Oil and gas properties, net
 
$
348,331

 
$
20,560

 
$
368,891

  Total property, plant and equipment, net
 
$
349,505

 
$
20,560

 
$
370,065

  Accumulated deficit
 
$
(896,451
)
 
$
20,560

 
$
(875,891
)
  Total capital deficiency
 
$
(105,827
)
 
$
20,560

 
$
(85,267
)
 
 
 
 
 
 
 
Consolidated Statement of Operations - for the year ended
 
 
 
 
 
 
  Impairment of oil and gas properties
 
$
281,768

 
$
(20,560
)
 
$
261,208

  Total operating costs and expenses
 
$
505,422

 
$
(20,560
)
 
$
484,862

  Net loss
 
$
(451,497
)
 
$
20,560

 
$
(430,937
)
  Basic and diluted loss per share attributable to Erin Energy Corporation
 
$
(2.13
)
 
$
0.09

 
$
(2.04
)
 
 
 
 
 
 
 
Consolidated Statement of Cash Flows - for the year ended
 
 
 
 
 
 
  Net loss, including non-controlling interest
 
$
(452,459
)
 
$
20,560

 
$
(431,899
)
  Impairment of oil and gas properties
 
$
281,768

 
$
(20,560
)
 
$
261,208

Subsequent Events
Subsequent Events
SUBSEQUENT EVENTS

Subsequent to December 31, 2016, the Company issued 31,841 shares of common stock upon the cashless exercise of stock options.

Subsequent to December 31, 2016, the Company granted to employees approximately 0.4 million shares of restricted stock, and granted performance-based restricted stock awards (PBRSA) to certain officers totaling 0.2 million shares.

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.

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 an exclusive off-take contract with Glencore dated January 18, 2017 (the “Off-take Contract”) 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 is required to deposit $10.0 million 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 must be entered into by the parties thereto as conditions precedent to the initial drawdown on the MCB Finance Facility.

EPNL may 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 may be 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 three-month LIBOR plus a 6% margin. After a grace period that ends 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 conditions to closing as is customary with such facilities and customary events of default.

Also on February 6, 2017, the Company and PIC also entered into the Financing Support Agreement. Pursuant to the Financing Support Agreement, PIC agrees 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 is a condition precedent to the closing of the MCB Finance Facility.

In consideration for this undertaking, the Company has 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 receives funds under the MCB Finance Facility, with an exercise price equal to such closing market price. 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.

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.

Execution of Drilling Rig Contract

In March 2017, the Company entered into a drilling services contract with Pacific Drilling using the Pacific Bora drilling rig. The Company plans to use 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 option to extend the contract, if exercised, would be used to drill two of its offshore Nigeria exploration prospects in the prolific Miocene geological zone. The Pacific Bora is a highly efficient sixth generation double-hulled drillship currently in Nigeria and expected to be mobilized to the Oyo field and on site in June 2017. The contract provides for a base operating rate of $195,000 per day. The rig can be used for both drilling and well completion.
Basis of Presentation and Significant Accounting Policies (Policies)
Basis of Presentation 
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.
 
In February 2014, the Company completed the acquisition of the remaining economic interests that it did not already own in the Production Sharing Contract covering Oil Mining Leases 120 and 121 located offshore Nigeria (the “OMLs”), which include the currently producing Oyo field (the “Allied Assets”), from Allied (the “Allied Transaction”). Pursuant to the terms of the Transfer Agreement entered into with Allied, the Company issued approximately 82.9 million shares of common stock to Allied, as partial consideration for the Allied Assets. Allied is a subsidiary of CEHL, the Company’s majority shareholder, and deemed to be under common control. Accordingly, the net assets acquired from Allied were recorded at their respective carrying values as of the acquisition date. The shares issued to Allied and the financial statements presented for all periods included herein are presented as though the transfer of the Allied Assets had occurred in June 2012, the effective date when Allied acquired the Allied Assets from an independent third party. See Note 4. — Acquisitions for further information.

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

Principles of Consolidation 
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 
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, 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
 
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
 
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 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, 2016 and 2015, no allowance for doubtful accounts was necessary.
Crude Oil Inventory 
Crude Oil Inventory
 
Inventories of crude oil are valued at the lower of cost or market using the first-in, first-out method and include certain costs directly related to the production process and depletion, depreciation and amortization attributable to the underlying oil and gas properties.
Successful Efforts Method of Accounting for Oil and Gas Activities 
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 market, which approximates fair value, and they are regularly assessed for obsolescence. Oilfield materials and supplies inventory balances were $34.7 million and $30.0 million at December 31, 2016 and 2015, 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 
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 
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
 
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 
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 13. — Income Taxes for further information.
Debt Issuance Costs 
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 
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.

Reporting and Functional Currency 
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 are included in results of operations.
Net Earnings (Loss) Per Common Share 
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, non-vested restricted stock awards, and stock warrants and conversion of the 2014 Convertible Subordinated Note, 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 
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, 2016 and 2015, 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).

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 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. 

Reclassification 
Reclassification
 
Certain reclassifications have been made to the 2015 and 2014 consolidated financial statements to conform to the 2016 presentation. These reclassifications were not material to the accompanying consolidated financial statements.
Recently Issued Accounting Standards 
Recently Issued Accounting Standards

In February 2016, the 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 standard could have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-07, Investments-Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting. ASU No. 2016-07 eliminates the requirement to retroactively adopt the equity method of accounting. ASU No. 2016-07 is effective for interim and annual periods beginning after December 15, 2016, and the Company will adopt this standards update, as required, beginning with the first quarter of 2017. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Consideration (Reporting Revenue Gross versus Net). ASU No. 2016-08 requires that an entity should recognize revenue 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. ASU No. 2016-08 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 standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The areas of simplification in ASU No. 2016-09 involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU No. 2016-09 is effective for interim and annual periods beginning after December 15, 2016, and the Company will adopt this standards update, as required, beginning with the first quarter of 2017. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. ASU No. 2016-10 clarifies two aspects of Topic 606: identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU No. 2016-10 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 standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. ASU No. 2016-11 rescinds SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities - Oil and Gas, effective upon adoption of Topic 606. ASU No. 2016-11 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 standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. The core principle of ASU No. 2016-12 is that an entity should recognize revenue 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. ASU No. 2016-12 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 standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in reporting certain items in the statement of cash flows. ASU No. 2016-15 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 Company does not expect adoption of ASU 2016-15 to have a material effect on its consolidated financial statements.

In October 2016, the FASB issued ASU 2016-16, Intra-Entity Transfers of Assets Other Than Inventory, which provides guidance on recognition of current income tax consequences for intra-entity asset transfers (other than inventory) at the time of transfer. This represents a change from current GAAP, where the consolidated tax consequences of intra-entity asset transfers are deferred until the transferred asset is sold to a third party or otherwise recovered through use. The guidance is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption at the beginning of an annual period is permitted. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

In October 2016, the FASB issued ASU 2016-17, Interests Held through Related Parties That Are under Common Control, which modifies existing guidance with respect to how a decision maker that holds an indirect interest in a VIE through a common control party determines whether it is the primary beneficiary of the VIE as part of the analysis of whether the VIE would need to be consolidated. Under this ASU, a decision maker would need to consider only its proportionate indirect interest in the VIE held through a common control party. This ASU is effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. ASU 2016-18 is effective for fiscal years beginning after December 15, 2018 (including interim periods within those periods) using a retrospective transition method to each period presented. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.
Basis of Presentation and Significant Accounting Policies (Tables)
Schedule of Shares Withholding and Repurchases of Common Stock 
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, 2016.

 
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.
Schedule of Anti-dilutive Securities 
The table below sets forth the number of stock options, warrants, non-vested restricted stock, and shares issuable upon conversion of Convertible Subordinated Note that were excluded from dilutive shares outstanding during the years ended December 31, 2016, 2015 and 2014, as these securities are anti-dilutive because the Company was in a loss position each year.
 
 
Years Ended December 31,
(In thousands)
2016
 
2015
 
2014
Stock options
230

 
1,101

 
1,038

Stock warrants
3

 
541

 
6

Unvested restricted stock awards
1,942

 
1,275

 
997

Convertible note
—

 
12,379

 
10,932

 
2,175

 
15,296

 
12,973

Fair Value Measurements, Nonrecurring 
The following table presents information about the Company’s oil and gas properties measured at fair value on a non-recurring basis:

 
Level 3
 
As of December 31,
(in thousands)
2016
 
2015
Value of oil and gas properties (1)
$
—

 
$
293,408


(1)
This represents non-financial assets that are measured at fair value on a non-recurring basis due to impairments. This is the fair value of the asset base that was subjected to impairment and does not reflect the entire asset balance as presented on the accompanying balance sheets. Please see Note 5. — Property, Plant and Equipment for further information. Amounts included here are presented only in years where an impairment has occurred.
Acquisitions (Tables) (Contractual Purchase Consideration)
Schedule of Purchase Consideration Assets Acquired and Liabilities Assumed
The table below sets forth a summary of the contractual purchase consideration paid for the Allied Assets (In thousands):
 
Cash consideration paid
$
170,000

Erin Energy Corporation common stock (1)
—

Long-term convertible subordinated note payable - related party
50,000

Total purchase price
$
220,000

Asset acquired and liabilities assumed as of February 21, 2014:
 
Property, plant and equipment, net
$
248,736

Accounts payable
(25,429
)
Asset retirement obligations
(20,890
)
Net assets acquired
202,417

Excess of consideration paid over carrying value of assets acquired
$
17,583

(1) Because the cash and debt consideration exceeds the carrying value of the assets acquired, no value was assigned to the shares issued
Property, Plant and Equipment (Tables)
Property, Plant and Equipment
Property, plant and equipment were comprised of the following:
 
 
As of December 31,
(In thousands)
2016
 
2015
Wells and production facilities
$
318,739

 
$
329,133

Proved properties
386,196

 
386,196

Work in progress and exploration inventory
34,712

 
65,043

Oilfield assets
739,647

 
780,372

Accumulated depletion
(483,754
)
 
(421,921
)
Oilfield assets, net
255,893

 
358,451

Unevaluated leaseholds
9,820

 
10,440

Oil and gas properties, net
265,713

 
368,891

Other property and equipment
3,040

 
2,963

Accumulated depreciation
(2,324
)
 
(1,789
)
Other property and equipment, net
716

 
1,174

Total property, plant and equipment, net
$
266,429

 
$
370,065

Accounts Payable and Accrued Liabilities (Tables)
Schedule of Accounts Payable and Accrued Liabilities
The table below sets forth a summary of the Company’s accounts payable and accrued liabilities at December 31, 2016 and 2015:
 
As of December 31,
(In thousands)
2016
 
2015
Accounts payable - vendors
$
173,306

 
$
153,085

Amounts due to government entities
66,573

 
53,119

Accrued interest
3,074

 
2,510

Accrued payroll and benefits
1,204

 
629

Other liabilities
806

 
3,777

 
$
244,963

 
$
213,120

Asset Retirement Obligations (Tables)
Summary of Changes in Asset Retirement Obligations 
The following table summarizes changes in the Company’s asset retirement obligations during the years ended December 31, 2016 and 2015:
 
(In thousands)
2016
 
2015
Asset retirement obligations at January 1
$
20,609

 
$
26,533

Accretion expense
1,867

 
1,931

Additions
—

 
9,416

Revisions in estimated liabilities
—

 
(4,284
)
Loss on settlement of asset retirement obligations
—

 
3,653

Payments to settle asset retirement obligations
—

 
(16,640
)
Asset retirement obligations at December 31
$
22,476

 
$
20,609

Summary of Current and Long-term Portions of Asset Retirement Obligations 
The table below shows the current and long-term portions of the Company's asset retirement obligations as of the end of December 31, 2016 and 2015:
 
 
As of December 31,
(In thousands)
2016
 
2015
Asset retirement obligations, current portion
$
—

 
$
—

Asset retirement obligations, long-term portion
22,476

 
20,609

 
$
22,476

 
$
20,609

Debt Debt (Tables)
Schedule of Principal Repayments of Long-term Debt
Scheduled principal repayments on the outstanding balance on the Term Loan Facility are as follows (in thousands):

Scheduled payments by year
 
Principal
2017
 
$
13,413

2018
 
19,673

2019
 
21,460

2020
 
27,265

2021 and thereafter
 
7,609

Total principal payments
 
$
89,420

Less: Unamortized debt issuance costs
 
2,347

Total Term Loan Facility, net
 
$
87,073

Related Party Transactions (Tables)
Summary of Related Party Transactions and Balances
The table below sets forth the related party assets and liabilities as of December 31, 2016 and 2015:
 
 
As of December 31,
(In thousands)
2016
 
2015
Accounts receivable, CEHL
$
1,956

 
$
1,186

Accounts payable and accrued liabilities, CEHL
$
29,513

 
$
30,133

Long-term notes payable - related party, CEHL
$
129,796

 
$
120,006

The table below sets forth the transactions incurred with affiliates during the years ended December 31, 2016, 2015 and 2014:
 
 
Year Ended December 31,
(In thousands)
2016
 
2015
 
2014
Total operating expenses, CEHL
$
14,621

 
$
15,106

 
$
14,449

Interest expense, CEHL
$
6,843

 
$
5,490

 
$
2,414

Commitments and Contingencies (Tables)
Significant Future Commitments on Non-Cancellable Operating Leases and Estimated Obligations Arising from its Minimum Work Obligations
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, 2016 and thereafter:
 
 
Payments Due By Period
(In thousands)
Total
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
Operating lease obligations:
 
 
 
 
 
 
 
 
 
 
 
 
 
FPSO and drilling rig
         leases - Nigeria
$
193,451

 
$
48,363

 
$
48,362

 
$
48,363

 
$
48,363

 
$
—

 
$
—

Office leases
1,600

 
537

 
493

 
450

 
81

 
39

 
—

Minimum work obligations:
 
 
 
 
 
 
 
 
 
 
 
 
 
Kenya
65,133

 
65,133

 
—

 
—

 
—

 
—

 
—

The Gambia
1,200

 
600

 
600

 
—

 
—

 
—

 
—

Ghana
10,650

 
10,650

 
—

 
—

 
—

 
—

 
—

Total
$
272,034

 
$
125,283

 
$
49,455

 
$
48,813

 
$
48,444

 
$
39

 
$
—

Stock Based Compensation (Tables)
Summary of Restricted Stock Activity 
The table below sets forth a summary of RSA activity for the year ended December 31, 2016.
 
 
Shares
(In Thousands)
 
Weighted-Average
Grant Date Fair
Value
Restricted Stock
 
 
 
Non-vested at December 31, 2015
1,114

 
$3.21
Granted
1,716

 
$2.16
Vested
(669
)
 
$3.56
Forfeited
(89
)
 
$2.59
Non-vested as of December 31, 2016
2,072

 
$2.25
Summary of Stock Option Activity 
The table below sets forth a summary of stock warrant activity for the year ended December 31, 2016.
 
 
Shares
Underlying
Warrants
(In Thousands)
 
Weighted-Average
Exercise Price
 
Weighted-Average
Remaining
Contractual Term
(Years)
Stock warrants
 
Outstanding at December 31, 2015
2,935

 
$3.61
 
4.2
Granted
48

 
$2.07
 
4.3
Exercised
—

 
$—
 
—
Forfeited
—

 
$—
 
—
Expired
—

 
$—
 
—
Outstanding at December 31, 2016
2,983

 
$3.59
 
3.2
Expected to vest
—

 
$—
 
—
Exercisable at December 31, 2016
2,983

 
$3.59
 
3.2
Summary of Weighted-Average Amounts for Assumptions 
The table below shows the weighted-average amounts and the assumptions used in the model for warrants issued during each year.
 
 
2016
 
2015
 
2014
Expected price volatility
84.7% - 84.8%

 
76.8% - 83.2%

 
82.7
%
Risk free interest rate (U.S. treasury bonds)
0.8
%
 
0.8% - 1.1%

 
1.1
%
Expected annual dividend yield
—

 
—

 
—

Expected option term (years)
3.0

 
3.0

 
3.0

Weighted-average grant date fair value per share
$
1.12

 
$
1.86

 
$
1.80

Summary of Stock Option Activity 
The table below sets forth a summary of stock option activity for the year ended December 31, 2016.

 
Shares
Underlying
Options
(In Thousands)
 
Weighted-Average
Exercise Price
 
Weighted-Average
Remaining
Contractual Term
(Years)
Stock Options
 
Outstanding at December 31, 2015
2,532

 
$2.29
 
1.6
Granted
—

 
$—
 
—
Exercised
(1,200
)
 
$1.84
 
—
Forfeited
(27
)
 
$3.42
 
—
Expired
(158
)
 
$3.70
 
—
Outstanding at December 31, 2016
1,147

 
$2.54
 
2.0
Expected to vest
908

 
$2.21
 
1.6
Exercisable at December 31, 2016
239

 
$3.79
 
3.4
Summary of Weighted-Average Amounts for Assumptions 
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.
 
 
2016
 
2015
 
2014
Expected price volatility
—%
 
77.1% - 83.1%

 
87.7
%
Risk free interest rate (U.S. treasury bonds)
—%
 
1.0 to 1.2 %

 
1.1
%
Expected annual dividend yield
—
 
—

 
—

Expected option term (years)
—
 
3.0

 
3.0

Weighted-average grant date fair value per share
—
 
$
2.73

 
$
1.92

Income Taxes (Tables)
Reconciliation of Expected Statutory U.S. Federal Income Tax Provision 
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)
2016
 
2015
 
2014
Net loss attributable to Erin Energy Corporation before income tax expense
$
(142,401
)
 
$
(430,937
)
 
$
(96,062
)
Expected income tax provision at statutory rate of 35%
(49,840
)
 
(150,828
)
 
(33,622
)
Increase (decrease) due to:
 
 
 
 
 
Foreign rate differential
(17,202
)
 
(59,467
)
 
(10,083
)
Change in valuation allowance
71,148

 
256,910

 
98,376

Investment tax credit - Nigeria
1,991

 
(35,580
)
 
(40,765
)
Non-deductible expenses and other
(6,097
)
 
(11,035
)
 
(13,906
)
Total income tax expense
$
—

 
$
—

 
$
—

Significant Components of Deferred Tax Assets 
Significant components of our deferred tax assets are as follows:
 
As of December 31,
(In thousands)
2016
 
2015
Basis difference in fixed assets
$
(3,249
)
 
$
11,893

Unused capital allowances
572,051

 
506,795

Net operating losses
109,230

 
88,391

Other
12,421

 
12,226

 
690,453

 
619,305

Valuation allowance
(690,453
)
 
(619,305
)
Net deferred income tax assets
$
—

 
$
—

Summary of Tax Years Remain Subject to Examination 
The following table summarizes the tax years that remain subject to examination by major tax jurisdictions:
 
United States:
2007
-
2016
Nigeria:
2010
-
2016
Kenya:
2012
-
2016
The Gambia:
2012
-
2016
Segment Information (Tables)
Schedule of Segment Activity
The table below sets forth segment activity for the years ended December 31, 2016, 2015, and 2014.
 
(In thousands)
Nigeria
 
Kenya
 
The Gambia
 
Ghana
 
Corporate and Other
 
Total
For the Years Ended December 31,
 
 
 
 
 
 
 
 
 
 
 
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
)
2014
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
53,844

 
$
—

 
$
—

 
$
—

 
$
—

 
$
53,844

Operating loss
$
(64,716
)
 
$
(12,130
)
 
$
(1,347
)
 
$
(492
)
 
$
(14,640
)
 
$
(93,325
)
 
The table below sets forth the total assets by segment as of December 31, 2016 and 2015.
 
(In thousands)
Nigeria
 
Kenya
 
The Gambia
 
Ghana
 
Corporate and Other
 
Total
Total Assets
 
 
 
 
 
 
 
 
 
 
 
December 31, 2016
$
281,050

 
$
698

 
$
3,034

 
$
3,648

 
$
771

 
$
289,201

December 31, 2015
$
387,326

 
$
1,399

 
$
3,016

 
$
2,447

 
$
971

 
$
395,159

Selected Unaudited Quarterly Financial Data (Tables)
Schedule of Selected Unaudited Quarterly Financial Data
 
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
)
 
Three Months Ended,
 
March 31, 2015
 
June 30, 2015
 
September 30, 2015
 
December 31, 2015
Total revenues
$
—

 
$
—

 
$
28,667

 
$
39,762

Operating loss
$
(32,031
)
 
$
(5,821
)
 
$
(53,423
)
 
$
(325,158
)
Net loss attributable to Erin Energy Corporation
$
(33,059
)
 
$
(9,162
)
 
$
(58,682
)
 
$
(330,034
)
Net loss per common share attributable to
   Erin Energy Corporation
 
 
 
 
 
 
 
Basic
$
(0.16
)
 
$
(0.04
)
 
$
(0.28
)
 
$
(1.56
)
Diluted
$
(0.16
)
 
$
(0.04
)
 
$
(0.28
)
 
$
(1.56
)
Correction of Immaterial Error in Previously Issued Consolidated Financial Statements (Tables)
Schedule of Error Corrections and Prior Period Adjustments
The following table reflects the amounts within the consolidated balance sheet, statement of operations, and statement of cash flows as originally reported to amounts as now reflected as of and for the year ended December 31, 2015.
(In thousands)
December 31, 2015
 
 
As Originally
 
 
 
 
 
 
Reported
 
Adjustments
 
Corrected
Consolidated Balance Sheet
 
 
 
 
 
 
  Oil and gas properties, net
 
$
348,331

 
$
20,560

 
$
368,891

  Total property, plant and equipment, net
 
$
349,505

 
$
20,560

 
$
370,065

  Accumulated deficit
 
$
(896,451
)
 
$
20,560

 
$
(875,891
)
  Total capital deficiency
 
$
(105,827
)
 
$
20,560

 
$
(85,267
)
 
 
 
 
 
 
 
Consolidated Statement of Operations - for the year ended
 
 
 
 
 
 
  Impairment of oil and gas properties
 
$
281,768

 
$
(20,560
)
 
$
261,208

  Total operating costs and expenses
 
$
505,422

 
$
(20,560
)
 
$
484,862

  Net loss
 
$
(451,497
)
 
$
20,560

 
$
(430,937
)
  Basic and diluted loss per share attributable to Erin Energy Corporation
 
$
(2.13
)
 
$
0.09

 
$
(2.04
)
 
 
 
 
 
 
 
Consolidated Statement of Cash Flows - for the year ended
 
 
 
 
 
 
  Net loss, including non-controlling interest
 
$
(452,459
)
 
$
20,560

 
$
(431,899
)
  Impairment of oil and gas properties
 
$
281,768

 
$
(20,560
)
 
$
261,208

Company Description - Additional Information (Details)
Dec. 31, 2016
acre
Dec. 31, 2016
sqkm
license
country
Organization, Consolidation and Presentation of Financial Statements [Abstract]
 
 
Number of exploration and production licenses
7 
7 
Number of countries company operates in Africa
4 
4 
Area of land held for exploration activities
5,000,000 
19,000 
Basis of Presentation and Significant Accounting Policies - Additional Information (Details) (USD $)
0 Months Ended 12 Months Ended 12 Months Ended 1 Months Ended
Apr. 22, 2015
Dec. 31, 2016
customer
Dec. 31, 2015
customer
Dec. 31, 2014
Dec. 31, 2016
Minimum
Dec. 31, 2016
Maximum
Dec. 31, 2016
Ghana
Joint Venture partners
Dec. 31, 2015
Ghana
Joint Venture partners
Dec. 31, 2016
Except Kenya off-shore leases
Feb. 28, 2014
Allied
Dec. 31, 2016
Allied
Dec. 31, 2016
Trade Accounts Receivable
Dec. 31, 2015
Trade Accounts Receivable
Dec. 31, 2016
Fair Value, Inputs, Level 1
Fair Value, Measurements, Nonrecurring
Dec. 31, 2015
Fair Value, Inputs, Level 1
Fair Value, Measurements, Nonrecurring
Dec. 31, 2016
Long-term Debt, Current Maturities
Dec. 31, 2015
Long-term Debt, Current Maturities
Dec. 31, 2016
Long-term Debt
Dec. 31, 2015
Long-term Debt
Dec. 31, 2015
Accounting Standards Update 2015-03
Long-term Debt, Current Maturities
Dec. 31, 2015
Accounting Standards Update 2015-03
Prepaid Expenses and Other Current Assets
Basis Of Presentation And Significant Accounting Policies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business acquisition, number of shares issued
 
 
 
 
 
 
 
 
 
82,900,000 
 
 
 
 
 
 
 
 
 
 
 
Reverse stock split, conversion ratio
0.1667 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted cash
 
$ 2,600,000 
$ 8,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts receivable
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounts receivable, current
 
 
 
 
 
 
 
 
 
 
 
0 
1,000,000 
 
 
 
 
 
 
 
 
Accounts receivable - partners
 
674,000 
287,000 
 
 
 
700,000 
300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil inventory
 
9,398,000 
4,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oilfield materials and supplies inventory
 
34,700,000 
30,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Productive oil and gas properties, estimated useful life (years)
 
 
 
 
3 years 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less: Unamortized debt issuance costs
 
2,347,000 
1,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,600,000 
(1,600,000)
Deferred finance costs, noncurrent
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,600,000 
0 
 
 
Debt issuance costs, current
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
800,000 
1,600,000 
 
 
 
 
Capitalized interest cost
 
0 
2,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of shares withheld (in shares)
 
99,932 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock, issued value
 
200,000 
212,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contingent additional payments under transfer agreement
 
 
 
 
 
 
 
 
 
 
50,000,000 
 
 
 
 
 
 
 
 
 
 
Noncontrolling interest in joint ventures
 
700,000 
800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value, oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
293,408,000 
 
 
 
 
 
 
Impairment of oil and gas properties
 
$ 645,000 
$ 261,208,000 
$ 0 
 
 
 
 
$ 0 
 
 
 
 
 
 
 
 
 
 
 
 
Number of crude oil customers
 
1 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basis of Presentation and Significant Accounting Policies - Shares Withholding and Repurchases of Common Stock (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Total Number of Shares Purchased (in shares)
99,932 
0 
Average Price Paid Per Share (in dollars per share)
$ 2.28 
 
January 1 - January 31, 2016
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Total Number of Shares Purchased (in shares)
3,643 
 
Average Price Paid Per Share (in dollars per share)
$ 4.02 
 
February 1 - February 29, 2016
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Total Number of Shares Purchased (in shares)
62,152 
 
Average Price Paid Per Share (in dollars per share)
$ 2.16 
 
March 1 - March 31, 2016
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Total Number of Shares Purchased (in shares)
17,318 
 
Average Price Paid Per Share (in dollars per share)
$ 2.31 
 
May 1 - May 31, 2016
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Total Number of Shares Purchased (in shares)
1,072 
 
Average Price Paid Per Share (in dollars per share)
$ 2.48 
 
September 1 - September 30, 2016
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Total Number of Shares Purchased (in shares)
6,162 
 
Average Price Paid Per Share (in dollars per share)
$ 2.29 
 
November 1 - November 30, 2016
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Total Number of Shares Purchased (in shares)
6,175 
 
Average Price Paid Per Share (in dollars per share)
$ 2.35 
 
December 1 - December 31, 2016
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Total Number of Shares Purchased (in shares)
3,410 
 
Average Price Paid Per Share (in dollars per share)
$ 2.10 
 
Basis of Presentation and Significant Accounting Polices - Schedule of Anti-dilutive Securities (Details)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
Anti-dilutive securities (in shares)
2,175 
15,296 
12,973 
Stock options
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
Anti-dilutive securities (in shares)
230 
1,101 
1,038 
Stock warrants
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
Anti-dilutive securities (in shares)
3 
541 
6 
Unvested restricted stock awards
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
Anti-dilutive securities (in shares)
1,942 
1,275 
997 
Convertible note
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
Anti-dilutive securities (in shares)
0 
12,379 
10,932 
Liquidity Matters and Going Concern (Details) (USD $)
9 Months Ended
Sep. 30, 2016
bbl
Dec. 31, 2016
Dec. 31, 2015
Liquidity Matters [Abstract]
 
 
 
Current liabilities
 
$ 287,100,000 
$ 339,811,000 
Current assets
 
22,706,000 
25,027,000 
Working capital, accumulated deficit, current
 
$ (264,400,000)
 
Production, emergency shut-in, barrels of oil lost per day
1,400 
 
 
Acquisitions - Additional information (Details) (USD $)
Share data in Millions, unless otherwise specified
1 Months Ended 12 Months Ended 1 Months Ended
Feb. 28, 2014
Feb. 28, 2014
Share Purchase Agreement
Private Placement
Feb. 28, 2014
Allied Transaction
Convertible Subordinated Note
Apr. 30, 2014
Tano Block in Ghana
field
Dec. 31, 2016
Tano Block in Ghana
Apr. 30, 2014
Tano Block in Ghana
Ghana
Apr. 30, 2014
Tano Block in Ghana
CAMAC Energy
Apr. 30, 2014
Tano Block in Ghana
Ghana Limited
Apr. 30, 2014
Tano Block in Ghana
GNPC Exploration and Production Company Limited
Apr. 30, 2014
Tano Block in Ghana
Base Energy
Apr. 30, 2014
First Extension Period
Tano Block in Ghana
well
Apr. 30, 2014
Second Extension Period
Tano Block in Ghana
Apr. 30, 2014
Minimum
Second Extension Period
Tano Block in Ghana
well
Apr. 30, 2014
Maximum
Second Extension Period
Tano Block in Ghana
well
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash consideration
$ 170,000,000 
 
$ 170,000,000 
 
 
 
 
 
 
 
 
 
 
 
Business acquisition, number of shares issued
 
62.8 
82.9 
 
 
 
 
 
 
 
 
 
 
 
Business acquisition, value of shares issued
 
$ 270,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Production sharing contracts with governments or authorities (percent)
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
Maximum participation (percent)
 
 
 
 
 
 
90.00% 
60.00% 
25.00% 
15.00% 
 
 
 
 
Additional on exploration (percent)
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
Number of previously discovered fields
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
Initial exploration period (years)
 
 
 
2 years 
 
 
 
 
 
 
 
 
 
 
Maximum number of additional exploration period (years)
 
 
 
 
 
 
 
 
 
 
1 year 6 months 
2 years 6 months 
 
 
Number of exploration wells
 
 
 
 
 
 
 
 
 
 
1 
 
1 
2 
Initial Exploration extension period
 
 
 
 
18 months 
 
 
 
 
 
 
 
 
 
Property, Plant and Equipment (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Property, Plant and Equipment [Abstract]
 
 
Wells and production facilities
$ 318,739 
$ 329,133 
Proved properties
386,196 
386,196 
Work in progress and exploration inventory
34,712 
65,043 
Oilfield assets
739,647 
780,372 
Accumulated depletion
(483,754)
(421,921)
Oilfield assets, net
255,893 
358,451 
Unevaluated leaseholds
9,800 
10,440 
Oil and gas properties, net
265,713 
368,891 
Other property and equipment
3,040 
2,963 
Accumulated depreciation
(2,324)
(1,789)
Other property and equipment, net
716 
1,174 
Total property, plant and equipment, net
$ 266,429 
$ 370,065 
Property, Plant and Equipment - Additional Information (Details) (USD $)
12 Months Ended 1 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
The Gambia
Dec. 31, 2015
Ghana
Dec. 31, 2016
Kenya
Dec. 31, 2016
Uncompleted Wells Equipment and Facilities
Dec. 31, 2016
Miocene and Pilocene Exploratory Drilling Activities
Property Plant And Equipment [Line Items]
 
 
 
 
 
 
 
 
Exploratory expenses
$ 39,269,000 
$ 16,437,000 
$ 14,283,000 
 
 
 
 
$ 33,000,000 
Unevaluated leaseholds
9,800,000 
10,440,000 
 
 
 
 
 
 
Payments to acquire rights to the properties
 
 
 
1,000,000 
1,200,000 
 
 
 
Impairment of oil and gas properties
645,000 
261,208,000 
0 
 
 
600,000 
32,600,000 
 
Noncash Impairment of oil and gas properties
 
$ 228,600,000 
 
 
 
 
 
 
Suspended Exploratory Well Costs - Additional Information (Details) (USD $)
1 Months Ended 12 Months Ended
Aug. 31, 2014
ft
m
reservoir
Nov. 30, 2013
interval
ft
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
 
 
 
 
 
Number of hydrocarbons Miocene formation intervals
 
3 
 
 
 
Number of feet encountered by Hydrocarbons in three intervals, as interpreted by “LWD” data
 
65 
 
 
 
Exploration expense
 
 
$ 39,269,000 
$ 16,437,000 
$ 14,283,000 
Pliocene formation Eastern fault block vertical depth, feet
6,059 
 
 
 
 
Pliocene formation Eastern fault block vertical depth, meters
1,847 
 
 
 
 
Number of Pliocene formation Eastern fault block new oil and gas reservoirs
4 
 
 
 
 
Hydrocarbons Pliocene formation Eastern fault block gross thickness
112 
 
 
 
 
Miocene Exploratory Drilling Activities
 
 
 
 
 
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
 
 
 
 
 
Suspended exploratory well cost
 
 
 
26,500,000 
 
Exploration expense
 
 
26,500,000 
 
 
Pliocene Exploratory Drilling Activity
 
 
 
 
 
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
 
 
 
 
 
Suspended exploratory well cost
 
 
 
6,500,000 
 
Exploration expense
 
 
$ 6,500,000 
 
 
Accounts Payable and Accrued Liabilities (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Payables and Accruals [Abstract]
 
 
Accounts payable - vendors
$ 173,306 
$ 153,085 
Amounts due to government entities
66,573 
53,119 
Accrued interest
3,074 
2,510 
Accrued payroll and benefits
1,204 
629 
Other liabilities
806 
3,777 
Total accounts payable and accrued liabilities
$ 244,963 
$ 213,120 
Asset Retirement Obligations - Summary of Change in Asset Retirement Obligations (Details) (USD $)
In Thousands, unless otherwise specified
1 Months Ended 12 Months Ended
Apr. 30, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
 
 
Beginning balance, asset retirement obligation
 
$ 20,609 
$ 26,533 
 
Accretion expense
 
1,867 
1,931 
2,166 
Additions
 
0 
9,416 
 
Revisions in estimated liabilities
 
0 
(4,284)
3,766 
Loss on settlement of asset retirement obligations
 
0 
3,653 
0 
Payments to settle asset retirement obligations
 
0 
(16,640)
0 
Ending balance, asset retirement obligation
 
22,476 
20,609 
26,533 
Loss on settlement of asset retirement obligations
$ 3,700 
$ 205 
$ 3,700 
$ 0 
Asset Retirement Obligations - Summary of Current and Long-term Portions of Asset Retirement Obligations (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Asset Retirement Obligation [Abstract]
 
 
 
Asset retirement obligations, current portion
$ 0 
$ 0 
 
Asset retirement obligations, long-term portion
22,476 
20,609 
 
Asset retirement obligations
$ 22,476 
$ 20,609 
$ 26,533 
Debt - Additional Information (Details) (USD $)
12 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 7 Months Ended 1 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended 3 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2015
Promissory Note To Allied
Dec. 31, 2016
2015 Convertible Note
Aug. 31, 2016
Notes Payable, Other Payables
Prepayment Agreement with Total Oil Trading SA
May 31, 2016
Notes Payable, Other Payables
Prepayment Agreement with Total Oil Trading SA
Jul. 31, 2016
Notes Payable to Banks
2016 Short-Term Note
Jun. 30, 2016
Notes Payable to Banks
2016 Short-Term Note
Dec. 31, 2016
Allied
Dec. 31, 2016
Allied
Promissory Note To Allied
Dec. 31, 2016
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Apr. 30, 2016
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Mar. 31, 2016
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Aug. 31, 2016
60-Day London Interbank Offered Rate (LIBOR)
Notes Payable, Other Payables
Prepayment Agreement with Total Oil Trading SA
May 31, 2016
60-Day London Interbank Offered Rate (LIBOR)
Notes Payable, Other Payables
Prepayment Agreement with Total Oil Trading SA
Apr. 30, 2016
1-Month LIBOR
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Mar. 31, 2016
1-Month LIBOR
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Dec. 31, 2016
London Interbank Offered Rate (LIBOR)
Allied
Promissory Note To Allied
Dec. 31, 2016
Line of Credit
Allied
Promissory Note To Allied
Dec. 31, 2016
Line of Credit
Majority Shareholder
Promissory Note to Majority Shareholder Related Party
May 31, 2016
Line of Credit
Majority Shareholder
Promissory Note to Majority Shareholder Related Party
May 31, 2016
Line of Credit
1-Month LIBOR
Majority Shareholder
Promissory Note to Majority Shareholder Related Party
Dec. 31, 2015
Convertible Subordinated Debt
Feb. 28, 2014
Convertible Subordinated Debt
Allied
Dec. 31, 2016
Convertible Subordinated Debt
Allied
Dec. 31, 2016
Convertible Subordinated Debt
London Interbank Offered Rate (LIBOR)
Allied
Dec. 31, 2015
Convertible Debt
2015 Convertible Note
Dec. 31, 2016
Convertible Debt
Allied
2015 Convertible Note
Mar. 31, 2015
Convertible Debt
Allied
2015 Convertible Note
Aug. 8, 2016
Term Loan Facility
Jun. 30, 2016
Term Loan Facility
Sep. 30, 2014
Term Loan Facility
Dec. 31, 2016
Term Loan Facility
Sep. 30, 2014
Term Loan Facility
London Interbank Offered Rate (LIBOR)
Dec. 31, 2016
Term Loan Facility, Naira Portion
Dec. 31, 2016
Term Loan Facility, U.S. Dollar Portion
Dec. 31, 2016
Minimum
2015 Convertible Note
Dec. 31, 2016
Minimum
Allied
Dec. 31, 2016
Maximum
2015 Convertible Note
Dec. 31, 2016
Maximum
Allied
Mar. 15, 2017
Subsequent Event
Allied
Promissory Note To Allied
Mar. 15, 2017
Subsequent Event
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Mar. 15, 2017
Subsequent Event
Convertible Debt
London Interbank Offered Rate (LIBOR)
Allied
2015 Convertible Note
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from short-term debt
 
 
 
 
 
$ 6,000,000 
$ 4,700,000 
 
$ 500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, basis spread on variable rate (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.00% 
5.00% 
7.00% 
7.00% 
2.00% 
 
 
 
7.00% 
 
 
 
5.00% 
 
 
 
 
 
 
 
11.10% 
 
 
 
 
 
 
 
 
5.00% 
Line of credit facility, commitment fee (percent)
 
 
 
 
 
 
 
2.50% 
2.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, term (years)
 
 
 
 
 
 
 
30 years 
30 years 
 
30 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5 years 
 
 
 
 
 
 
5 years 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument, convertible, conversion price (dollars per share)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 4.2984 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 3.415 
$ 3.415 
 
Maximum borrowing capacity
 
 
 
 
 
 
 
 
 
 
25,000,000.0 
 
 
 
 
 
 
 
 
 
 
10,000,000 
 
 
 
 
 
 
 
50,000,000 
 
 
100,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, maximum borrowing capacity available in USD (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
90.00% 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, maximum borrowing capacity available in Nigerian Naira (percent)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, principal payment moratorium period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, reduction of funding of debt service reserve account, price of oil per barrel initial threshold
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
55 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, commitment fee amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,400,000 
 
2,600,000 
 
 
 
 
 
 
 
 
 
 
Unamortized debt issuance costs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,300,000 
 
 
 
 
 
 
 
 
 
 
Debt instrument, default, maximum time period (days)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30 days 
 
 
 
 
 
 
 
 
30 days 
 
 
 
 
 
 
 
 
 
 
Unremedied material breach, maximum time period (days)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10 days 
 
 
 
 
 
 
 
 
30 days 
 
 
 
 
 
 
 
 
 
 
Annual principal payment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
400,000 
5,600,000 
 
 
 
 
 
 
 
Foreign currency transaction gain unrealized
15,674,000 
2,520,000 
1,572,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4,300,000 
 
 
 
 
 
 
 
 
 
 
Total Term Loan Facility, net
87,073,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
87,073,000 
 
 
 
 
 
 
 
 
 
 
Long-term debt, excluding current maturities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
45,000,000 
48,500,000 
 
 
 
 
74,400,000 
 
 
 
 
 
 
 
 
 
 
Current portion of long-term debt, net
12,627,000 
96,558,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12,600,000 
 
 
 
 
 
 
 
 
 
 
Interest payable
 
 
 
 
 
 
 
 
 
 
 
400,000 
 
 
 
 
 
 
 
1,600,000 
 
 
 
 
 
8,000,000 
 
 
4,900,000 
 
 
 
 
3,100,000 
 
 
 
 
 
 
 
 
 
 
Term loan facility
129,800,000 
120,006,000 
 
 
 
 
 
 
 
 
 
6,400,000 
 
 
 
 
 
 
 
 
 
 
 
50,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Promissory note
129,800,000 
 
 
25,000,000 
 
 
 
 
 
 
24,900,000 
 
1,000,000 
3,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes payable - related party
50,000,000 
 
 
 
 
 
 
 
 
50,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum threshold proceeds from capital market debt issuance for mandatory prepayment option
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
250,000,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, gross
89,420,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48,500,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of securities called by warrants (shares)
 
 
 
 
48,291 
 
 
 
 
2,700,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exercise price of warrants (dollars per share)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 2.00 
$ 2.00 
$ 2.13 
$ 7.85 
 
 
 
Warrants issued with debt
53,000 
4,911,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unamortized debt issuance costs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from short-term note payable
$ 504,000 
$ 0 
$ 0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 2,400,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt - Schedule of Principal Repayments of Long-term Debt (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Debt Disclosure [Abstract]
 
 
2017
$ 13,413 
 
2018
19,673 
 
2019
21,460 
 
2020
27,265 
 
2021 and thereafter
7,609 
 
Total principal payments
89,420 
 
Less: Unamortized debt issuance costs
2,347 
1,600 
Total Term Loan Facility, net
$ 87,073 
 
Related Party Transactions - Additional Information (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Apr. 30, 2014
Apr. 30, 2014
Affiliate
Dec. 31, 2015
Promissory Note To Allied
Dec. 31, 2016
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Apr. 30, 2016
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Mar. 31, 2016
Majority Shareholder
Line of Credit
Promissory Note to Majority Shareholder Related Party
Dec. 31, 2015
Convertible Debt
2015 Convertible Note
Dec. 31, 2015
Convertible Subordinated Debt
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Accounts receivable, CEHL
$ 1,956,000 
$ 1,186,000 
 
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
29,500,000 
30,100,000 
 
 
 
 
 
 
 
 
 
Related party, accrued interest on notes payable
15,200,000 
8,300,000 
 
 
 
 
 
 
 
 
 
Promissory note
129,800,000 
 
 
 
 
25,000,000 
 
1,000,000 
3,000,000 
 
 
Convertible subordinate note issued
50,000,000 
 
 
 
 
 
 
 
 
 
 
Long-term debt, excluding current maturities
 
 
 
 
 
 
 
 
 
45,000,000 
 
Term loan facility
129,800,000 
120,006,000 
 
 
 
 
6,400,000 
 
 
 
50,000,000 
Compensation incurred with affiliate
14,600,000 
15,106,000 
14,449,000 
 
 
 
 
 
 
 
 
Interest expense, related party
$ 6,843,000 
$ 5,490,000 
$ 2,414,000 
 
 
 
 
 
 
 
 
Non-controlling interest, ownership percentage
 
 
 
50.00% 
50.00% 
 
 
 
 
 
 
Commitments and Contingencies - Summary of the Company Significant Future Commitments on Non-cancellable Operating Leases and Estimated Obligations Arising from its Minimum Work Obligations (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Commitments And Contingencies [Line Items]
 
Total
$ 272,034 
2017
125,283 
2018
49,455 
2019
48,813 
2020
48,444 
2021
39 
Thereafter
0 
Operating lease obligation - FPSO and drilling rig leases - Nigeria
 
Commitments And Contingencies [Line Items]
 
Total
193,451 
2017
48,363 
2018
48,362 
2019
48,363 
2020
48,363 
2021
0 
Thereafter
0 
Operating lease obligation - Office leases
 
Commitments And Contingencies [Line Items]
 
Total
1,600 
2017
537 
2018
493 
2019
450 
2020
81 
2021
39 
Thereafter
0 
Minimum work obligations |
Kenya
 
Commitments And Contingencies [Line Items]
 
Total
65,133 
2017
65,133 
2018
0 
2019
0 
2020
0 
2021
0 
Thereafter
0 
Minimum work obligations |
The Gambia
 
Commitments And Contingencies [Line Items]
 
Total
1,200 
2017
600 
2018
600 
2019
0 
2020
0 
2021
0 
Thereafter
0 
Minimum work obligations |
Ghana
 
Commitments And Contingencies [Line Items]
 
Total
10,650 
2017
10,650 
2018
0 
2019
0 
2020
0 
2021
0 
Thereafter
$ 0 
Commitments and Contingencies - Additional Information (Details) (USD $)
12 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2016
Nigerian Department of Petroleum Resources
Dec. 31, 2016
Kenya
Dec. 31, 2016
Kenya
contract
Dec. 31, 2016
The Gambia
contract
Dec. 31, 2016
NIGERIA
Jun. 30, 2015
Long-term Floating Production Storage and Offloading System Contract
Feb. 28, 2014
Long-term Floating Production Storage and Offloading System Contract
bbl
Dec. 31, 2016
Long-term Floating Production Storage and Offloading System Contract
Jan. 22, 2016
TransOcean Offshore Gulf of Guinea VII Limited and Indigo Drilling Limited [Member]
Feb. 5, 2016
February 2014 Transactions
people
Aug. 31, 2016
Settlement with CEONA Contracting (UK) Limited [Member]
Aug. 22, 2016
Settlement with CEONA Contracting (UK) Limited [Member]
Aug. 22, 2016
Settlement with CEONA Contracting (UK) Limited [Member]
May 13, 2016
Settlement with CEONA Contracting (UK) Limited [Member]
Jul. 29, 2016
Settlement with Contractor Polarcus MC Ltd. [Member]
Jul. 29, 2016
Settlement with Contractor Polarcus MC Ltd. [Member]
Mar. 15, 2016
Convertible Debt
2015 Convertible Note
Commitments And Contingencies Disclosure [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Initial term of contract (years)
 
 
 
 
 
 
 
 
 
7 years 
 
 
 
 
 
 
 
 
 
 
Additional term of contract (years)
 
 
 
 
 
 
 
 
 
2 years 
 
 
 
 
 
 
 
 
 
 
Barrels processing capacity (bbl)
 
 
 
 
 
 
 
 
 
40,000 
 
 
 
 
 
 
 
 
 
 
Maximum storage capacity for the FPSO (bbl)
 
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
Reduction of accrued production costs
 
 
 
 
 
 
 
 
$ 26,000,000 
 
 
 
 
 
 
 
 
 
 
 
Other minimum commitment, due in first year
 
 
 
 
 
 
 
 
 
 
48,400,000 
 
 
 
 
 
 
 
 
 
Minimum work obligation in mineral property
 
 
 
 
 
4 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
Write-off of offshore leases
 
 
 
 
600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rent expense
1,100,000 
900,000 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Future minimum payments due
1,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimate of possible loss
 
 
 
 
 
 
 
17,100,000 
 
 
 
20,200,000 
 
 
 
 
2,900,000 
 
300,000 
 
Number of plaintiffs
 
 
 
 
 
 
 
 
 
 
 
 
7 
 
 
 
 
 
 
 
Increase (decrease) in accounts payable and accrued liabilities
66,147,000 
84,000,000 
56,845,000 
 
 
 
 
 
 
 
 
 
 
 
(2,700,000)
 
 
 
 
 
Decrease in oil and gas properties
(265,713,000)
(368,891,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
2,700,000 
 
 
 
 
Loss contingency accrual, payments
 
 
 
 
 
 
 
 
 
 
 
 
 
1,100,000 
 
 
 
 
 
 
Litigation settlement, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2,400,000 
 
 
Loss contingency accrual
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
400,000 
 
Payment of cash or the equivalent in shares
 
 
 
$ 25,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payment of cash or the equivalent of shares in period
 
 
 
15 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of shares to be issued in period
 
 
 
30 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percent owed on debt fundraising event
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.00% 
Percent owed on equity fundraising event
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20.00% 
Stock Based Compensation - Additional Information (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2016
Stock warrants
Dec. 31, 2015
Stock warrants
Dec. 31, 2014
Stock warrants
Dec. 31, 2016
2009 Equity Incentive Plan
Dec. 31, 2015
2009 Equity Incentive Plan
Dec. 31, 2014
2009 Equity Incentive Plan
Dec. 31, 2016
Employee Stock Option
Dec. 31, 2015
Employee Stock Option
Dec. 31, 2014
Employee Stock Option
Dec. 31, 2018
Employee Stock Option
Scenario, Forecast
Dec. 31, 2017
Employee Stock Option
Scenario, Forecast
Dec. 31, 2016
Employee Stock Option
2009 Equity Incentive Plan
Minimum
Dec. 31, 2016
Employee Stock Option
2009 Equity Incentive Plan
Maximum
Dec. 31, 2016
Cashless Stock Option
Dec. 31, 2016
Unvested restricted stock awards
Dec. 31, 2015
Unvested restricted stock awards
Dec. 31, 2014
Unvested restricted stock awards
Dec. 31, 2016
Unvested restricted stock awards
Maximum
Dec. 31, 2016
Unvested restricted stock awards
2009 Equity Incentive Plan
Dec. 31, 2015
Unvested restricted stock awards
2009 Equity Incentive Plan
Dec. 31, 2018
Unvested restricted stock awards
2009 Equity Incentive Plan
Scenario, Forecast
Dec. 31, 2017
Unvested restricted stock awards
2009 Equity Incentive Plan
Scenario, Forecast
Dec. 31, 2016
Officer
Performance-Based Restricted Stock
Dec. 31, 2016
2015 Convertible Note
Dec. 31, 2016
2015 Convertible Note
Minimum
Dec. 31, 2016
2015 Convertible Note
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of shares authorized (in shares)
 
 
 
 
16,700,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expiration period (years)
 
 
 
 
 
 
 
 
 
 
 
 
5 years 
10 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock issued during period (in shares)
 
 
 
 
 
 
 
437,638 
 
 
 
 
 
 
246,838 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock exercised in period (in shares)
 
 
 
 
 
 
 
1,200,000 
 
 
 
 
 
 
1,008,803 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock expired in period (in shares)
157,768 
 
 
 
 
 
 
158,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock forfeited in period (in shares)
27,052 
 
 
 
 
 
 
27,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options outstanding intrinsic value
 
$ 1,000,000 
 
 
$ 900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options exercisable intrinsic value
 
1,000,000 
 
 
900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options exercised in period intrinsic value
 
 
 
 
700,000 
10,000 
900,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Allocated share-based compensation expense
 
0 
400,000 
100,000 
 
 
 
400,000 
1,300,000 
1,300,000 
 
 
 
 
 
2,500,000 
3,300,000 
1,700,000 
 
 
 
 
 
 
 
 
 
Compensation cost not yet recognized
 
 
 
 
 
 
 
300,000 
 
 
100,000 
200,000 
 
 
 
1,700,000 
 
 
 
 
 
200,000 
1,500,000 
 
 
 
 
Number of securities called by warrants (shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48,291 
 
 
Exercise price of warrants (dollars per share)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 2.00 
$ 2.13 
Warrants exercisable from date of issuance, term period (years)
5 years 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issued warrants to third parties (in shares)
 
300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issued warrants to third parties at exercise price (in dollars per share)
 
$ 3.36 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Granted (shares)
 
48,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,716,000 
 
 
 
 
 
 
 
500,000 
 
 
 
Award vesting period (years)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36 months 
 
 
 
 
3 years 
 
 
 
Restricted common stock forfeited in period (in shares)
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
89,461 
 
 
 
 
 
 
 
 
 
 
 
Percentage of additional shares awarded
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.00% 
 
 
 
Compensation not yet recognized, shared-based awards other than options
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
300,000 
 
 
 
Cost not yet recognized, period for recognition (years)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
Grant date fair value vested in period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 2,100,000 
$ 3,100,000 
 
 
 
 
 
 
Expected option term (years)
 
3 years 
3 years 
3 years 
 
 
 
0 years 
3 years 
3 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock Based Compensation - Summary of Stock Option Activity (Details) (USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
 
 
Forfeited (shares)
(27,052)
 
Expired (shares)
(157,768)
 
Stock Options
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
 
 
Options, Outstanding (shares)
2,532,000 
 
Granted (shares)
0 
 
Exercised (shares)
(1,200,000)
 
Forfeited (shares)
(27,000)
 
Expired (shares)
(158,000)
 
Options, Outstanding (shares)
1,147,000 
2,532,000 
Expected to vest (shares)
908,000 
 
Exercisable at end of period (shares)
239,000 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
 
 
Options Outstanding, Weighted-Average Exercise Price (dollars per share)
$ 2.29 
 
Granted (dollars per share)
$ 0.00 
 
Exercised (dollars per share)
$ 1.84 
 
Forfeited (dollars per share)
$ 3.42 
 
Expired (dollars per share)
$ 3.70 
 
Options Outstanding, Weighted-Average Exercise Price (dollars per share)
$ 2.54 
$ 2.29 
Expected to vest (dollars per share)
$ 2.21 
 
Exercisable at end of period (dollars per share)
$ 3.79 
 
Options Outstanding, Weighted-Average Remaining Contractual Term (Years)
2 years 
1 year 7 months 6 days 
Expected to vest, Weighted-Average Remaining Contractual Term (Years)
1 year 7 months 6 days 
 
Exercisable at end of period, Weighted-Average Remaining Contractual Term (Years)
3 years 4 months 24 days 
 
Stock Based Compensation - Summary of Weighted-Average Amounts for Assumptions (Details)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Stock warrants
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Expected price volatility (percent)
 
 
82.70% 
Expected price volatility, minimum
84.70% 
76.80% 
 
Expected price volatility, maximum
84.80% 
83.20% 
 
Risk free interest rate (U.S. Treasury bonds) (percent)
0.80% 
 
1.10% 
Risk free interest rate (U.S. Treasury bonds), minimum
 
0.80% 
 
Risk free interest rate (U.S. Treasury bonds), maximum
 
1.10% 
 
Expected annual dividend yield (percent)
0.00% 
0.00% 
0.00% 
Expected option term (years)
3 years 
3 years 
3 years 
Weighted-average grant date fair value per share (dollars per share)
$ 1.12 
$ 1.86 
$ 1.80 
Stock Options
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Expected price volatility (percent)
0.00% 
 
87.70% 
Expected price volatility, minimum
 
77.10% 
 
Expected price volatility, maximum
 
83.10% 
 
Risk free interest rate (U.S. Treasury bonds) (percent)
0.00% 
 
1.10% 
Risk free interest rate (U.S. Treasury bonds), minimum
 
1.00% 
 
Risk free interest rate (U.S. Treasury bonds), maximum
 
1.20% 
 
Expected annual dividend yield (percent)
0.00% 
0.00% 
0.00% 
Expected option term (years)
0 years 
3 years 
3 years 
Weighted-average grant date fair value per share (dollars per share)
$ 0.00 
$ 2.73 
$ 1.92 
Stock Based Compensation - Summary of Stock Warrants Activity (Details) (Stock warrants, USD $)
12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Stock warrants
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
 
 
Outstanding (shares)
2,935,000 
 
Granted (shares)
48,000 
 
Exercised (shares)
0 
 
Forfeited (shares)
0 
 
Expired (shares)
0 
 
Outstanding (shares)
2,983,000 
2,935,000 
Expected to vest (shares)
0 
 
Exercisable at period end (shares)
2,983,000 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
 
Outstanding (dollars per share)
$ 3.61 
 
Granted (dollars per share)
$ 2.07 
 
Exercised (dollars per share)
$ 0.00 
 
Forfeited (dollars per share)
$ 0.00 
 
Expired (dollars per share)
$ 0.00 
 
Outstanding (dollars per share)
$ 3.59 
$ 3.61 
Expected to vest (dollars per share)
$ 0.00 
 
Exercisable at period end (dollars per share)
$ 3.59 
 
Weighted-Average Remaining Contractual Term (Years)
3 years 2 months 12 days 
4 years 2 months 12 days 
Granted, Weighted-Average Remaining Contractual Term (Years)
4 years 4 months 2 days 
 
Exercisable at period end, Weighted-Average Remaining Contractual Term (Years)
3 years 2 months 12 days 
 
Stock Based Compensation - Summary of Restricted Stock Activity (Details) (Unvested restricted stock awards, USD $)
12 Months Ended
Dec. 31, 2016
Unvested restricted stock awards
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
 
Outstanding (shares)
1,114,000 
Granted (shares)
1,716,000 
Vested (shares)
(669,000)
Forfeited (shares)
(89,461)
Outstanding (shares)
2,072,000 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
 
Outstanding (dollars per share)
$ 3.21 
Granted (dollars per share)
$ 2.16 
Vested (dollars per share)
$ 3.56 
Forfeited (dollars per share)
$ 2.59 
Outstanding (dollars per share)
$ 2.25 
Income Taxes - Reconciliation of Expected Statutory U.S. Federal Income Tax Provision (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Income Tax [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Net loss attributable to Erin Energy Corporation before income tax expense
$ (63,947)
$ (23,471)
$ (22,572)
$ (32,411)
$ (330,034)
$ (58,682)
$ (9,162)
$ (33,059)
$ (142,401)
$ (430,937)
$ (96,062)
Expected income tax provision at statutory rate of 35%
 
 
 
 
 
 
 
 
(49,840)
(150,828)
(33,622)
Increase (decrease) due to:
 
 
 
 
 
 
 
 
 
 
 
Foreign rate differential
 
 
 
 
 
 
 
 
(17,202)
(59,467)
(10,083)
Change in valuation allowance
 
 
 
 
 
 
 
 
71,148 
256,910 
98,376 
Non-deductible expenses and other
 
 
 
 
 
 
 
 
(6,097)
(11,035)
(13,906)
Total income tax expense
 
 
 
 
 
 
 
 
0 
0 
0 
Expected income tax provision at statutory rate
 
 
 
 
 
 
 
 
35.00% 
35.00% 
35.00% 
NIGERIA
 
 
 
 
 
 
 
 
 
 
 
Increase (decrease) due to:
 
 
 
 
 
 
 
 
 
 
 
Investment tax credit - Nigeria
 
 
 
 
 
 
 
 
$ 1,991 
$ (35,580)
$ (40,765)
Income Taxes - Significant Components of Deferred Tax Assets (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Income Tax Disclosure [Abstract]
 
 
Basis difference in fixed assets
$ (3,249)
$ 11,893 
Unused capital allowances
572,051 
506,795 
Net operating losses
109,230 
88,391 
Other
12,421 
12,226 
Gross deferred income tax assets
690,453 
619,305 
Valuation allowance
(690,500)
(619,305)
Net deferred income tax assets
$ 0 
$ 0 
Income Taxes - Additional Information (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Dec. 31, 2015
Income Tax Disclosure [Abstract]
 
 
Valuation allowance
$ 690,500 
$ 619,305 
Income Taxes - Summary of Tax Years Remain Subject to Examination (Details)
12 Months Ended
Dec. 31, 2016
United States |
Minimum
 
Income Tax Examination [Line Items]
 
Tax years subject to examination
2007 
United States |
Maximum
 
Income Tax Examination [Line Items]
 
Tax years subject to examination
2016 
NIGERIA |
Minimum
 
Income Tax Examination [Line Items]
 
Tax years subject to examination
2010 
NIGERIA |
Maximum
 
Income Tax Examination [Line Items]
 
Tax years subject to examination
2016 
Kenya |
Minimum
 
Income Tax Examination [Line Items]
 
Tax years subject to examination
2012 
Kenya |
Maximum
 
Income Tax Examination [Line Items]
 
Tax years subject to examination
2016 
The Gambia |
Minimum
 
Income Tax Examination [Line Items]
 
Tax years subject to examination
2012 
The Gambia |
Maximum
 
Income Tax Examination [Line Items]
 
Tax years subject to examination
2016 
Segment Information - Segment Activity (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 21,116 
$ 28,619 
$ 23,151 
$ 4,929 
$ 39,762 
$ 28,667 
$ 0 
$ 0 
$ 77,815 
$ 68,429 
$ 53,844 
Operating loss
(59,683)
(21,817)
(27,199)
(28,293)
(325,158)
(53,423)
(5,821)
(32,031)
(136,992)
(416,433)
(93,325)
Total Assets
289,201 
 
 
 
395,159 
 
 
 
289,201 
395,159 
 
Operating Segments |
Nigeria Segment
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
77,815 
68,429 
53,844 
Operating loss
 
 
 
 
 
 
 
 
(119,346)
(387,448)
(64,716)
Total Assets
281,050 
 
 
 
387,326 
 
 
 
281,050 
387,326 
 
Operating Segments |
Kenya Segment
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
0 
0 
0 
Operating loss
 
 
 
 
 
 
 
 
(2,569)
(8,038)
(12,130)
Total Assets
698 
 
 
 
1,399 
 
 
 
698 
1,399 
 
Operating Segments |
The Gambia Segment
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
0 
0 
0 
Operating loss
 
 
 
 
 
 
 
 
(1,570)
(5,209)
(1,347)
Total Assets
3,034 
 
 
 
3,016 
 
 
 
3,034 
3,016 
 
Operating Segments |
Ghana Segment
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating loss
 
 
 
 
 
 
 
 
(1,677)
(1,931)
(492)
Total Assets
3,648 
 
 
 
2,447 
 
 
 
3,648 
2,447 
 
Corporate and Other
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
0 
0 
0 
Operating loss
 
 
 
 
 
 
 
 
(11,830)
(13,807)
(14,640)
Total Assets
$ 771 
 
 
 
$ 971 
 
 
 
$ 771 
$ 971 
 
Selected Unaudited Quarterly Financial Data - Schedule of Selected Unaudited Quarterly Financial Data (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ 21,116 
$ 28,619 
$ 23,151 
$ 4,929 
$ 39,762 
$ 28,667 
$ 0 
$ 0 
$ 77,815 
$ 68,429 
$ 53,844 
Operating loss
(59,683)
(21,817)
(27,199)
(28,293)
(325,158)
(53,423)
(5,821)
(32,031)
(136,992)
(416,433)
(93,325)
Net loss attributable to Erin Energy Corporation
$ (63,947)
$ (23,471)
$ (22,572)
$ (32,411)
$ (330,034)
$ (58,682)
$ (9,162)
$ (33,059)
$ (142,401)
$ (430,937)
$ (96,062)
Net loss per common share attributable to Erin Energy Corporation
 
 
 
 
 
 
 
 
 
 
 
Basic (Dollars per share)
$ (0.30)
$ (0.11)
$ (0.11)
$ (0.15)
$ (1.56)
$ (0.28)
$ (0.04)
$ (0.16)
 
 
 
Diluted (Dollars per share)
$ (0.30)
$ (0.11)
$ (0.11)
$ (0.15)
$ (1.56)
$ (0.28)
$ (0.04)
$ (0.16)
 
 
 
Correction of Immaterial Error in Previously Issued Consolidated Financial Statements (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Oil and gas properties, net
$ 265,713,000 
 
 
 
$ 368,891,000 
 
 
 
$ 265,713,000 
$ 368,891,000 
 
 
Total property, plant and equipment, net
266,429,000 
 
 
 
370,065,000 
 
 
 
266,429,000 
370,065,000 
 
 
Accumulated deficit
(1,018,292,000)
 
 
 
(875,891,000)
 
 
 
(1,018,292,000)
(875,891,000)
 
 
Total capital deficiency
(224,620,000)
 
 
 
(85,267,000)
 
 
 
(224,620,000)
(85,267,000)
334,005,000 
387,946,000 
Impairment of oil and gas properties
 
 
 
 
 
 
 
 
645,000 
261,208,000 
0 
 
Total operating costs and expenses
 
 
 
 
 
 
 
 
214,807,000 
484,862,000 
147,169,000 
 
Net loss attributable to Erin Energy Corporation
(63,947,000)
(23,471,000)
(22,572,000)
(32,411,000)
(330,034,000)
(58,682,000)
(9,162,000)
(33,059,000)
(142,401,000)
(430,937,000)
(96,062,000)
 
Basic and diluted loss per share attributable to Erin Energy Corporation (USD per share)
 
 
 
 
 
 
 
 
 
$ (2.04)
 
 
Net loss
 
 
 
 
 
 
 
 
(143,242,000)
(431,899,000)
(96,308,000)
 
Scenario, Previously Reported
 
 
 
 
 
 
 
 
 
 
 
 
Oil and gas properties, net
 
 
 
 
348,331,000 
 
 
 
 
348,331,000 
 
 
Total property, plant and equipment, net
 
 
 
 
349,505,000 
 
 
 
 
349,505,000 
 
 
Accumulated deficit
 
 
 
 
(896,451,000)
 
 
 
 
(896,451,000)
 
 
Total capital deficiency
 
 
 
 
(105,827,000)
 
 
 
 
(105,827,000)
 
 
Impairment of oil and gas properties
 
 
 
 
 
 
 
 
 
281,768,000 
 
 
Total operating costs and expenses
 
 
 
 
 
 
 
 
 
505,422,000 
 
 
Net loss attributable to Erin Energy Corporation
 
 
 
 
 
 
 
 
 
(451,497,000)
 
 
Basic and diluted loss per share attributable to Erin Energy Corporation (USD per share)
 
 
 
 
 
 
 
 
 
$ (2.13)
 
 
Net loss
 
 
 
 
 
 
 
 
 
(452,459,000)
 
 
Restatement Adjustment
 
 
 
 
 
 
 
 
 
 
 
 
Oil and gas properties, net
 
 
 
 
20,560,000 
 
 
 
 
20,560,000 
 
 
Total property, plant and equipment, net
 
 
 
 
20,560,000 
 
 
 
 
20,560,000 
 
 
Accumulated deficit
 
 
 
 
20,560,000 
 
 
 
 
20,560,000 
 
 
Total capital deficiency
 
 
 
 
20,560,000 
 
 
 
 
20,560,000 
 
 
Impairment of oil and gas properties
 
 
 
 
 
 
 
 
 
(20,560,000)
 
 
Total operating costs and expenses
 
 
 
 
 
 
 
 
 
(20,560,000)
 
 
Net loss attributable to Erin Energy Corporation
 
 
 
 
 
 
 
 
 
20,600,000 
 
 
Basic and diluted loss per share attributable to Erin Energy Corporation (USD per share)
 
 
 
 
 
 
 
 
 
$ 0.09 
 
 
Net loss
 
 
 
 
 
 
 
 
 
20,560,000 
 
 
Accumulated Deficit
 
 
 
 
 
 
 
 
 
 
 
 
Total capital deficiency
(1,018,292,000)
 
 
 
(875,891,000)
 
 
 
(1,018,292,000)
(875,891,000)
(444,954,000)
(348,892,000)
Net loss
 
 
 
 
 
 
 
 
(142,401,000)
(430,937,000)
(96,062,000)
 
Accumulated Deficit |
Restatement Adjustment
 
 
 
 
 
 
 
 
 
 
 
 
Total capital deficiency
 
 
 
 
$ 20,600,000 
 
 
 
 
$ 20,600,000 
 
 
Subsequent Events - Additional Information (Details) (USD $)
12 Months Ended 3 Months Ended 1 Months Ended 3 Months Ended 0 Months Ended 3 Months Ended 1 Months Ended 0 Months Ended
Dec. 31, 2016
Cashless Stock Option
Dec. 31, 2016
Unvested restricted stock awards
Dec. 31, 2016
Officer
Performance-Based Restricted Stock
Mar. 15, 2017
Subsequent Event
Cashless Stock Option
Mar. 15, 2017
Subsequent Event
Unvested restricted stock awards
Feb. 28, 2017
Subsequent Event
Glencore Energy UK Ltd.
Feb. 28, 2017
Subsequent Event
Glencore Energy UK Ltd.
London Interbank Offered Rate (LIBOR)
Mar. 15, 2017
Subsequent Event
Officer
Performance-Based Restricted Stock
Feb. 6, 2017
Line of Credit
MCB Finance Facility
Subsequent Event
Mar. 15, 2017
Line of Credit
MCB Finance Facility
Subsequent Event
Feb. 6, 2017
Line of Credit
MCB Finance Facility
Subsequent Event
Mar. 6, 2017
Line of Credit
MCB Finance Facility
Subsequent Event
3-month London Interbank Offered Rate (LIBOR)
Feb. 6, 2017
Line of Credit
MCB Finance Facility
EPNL
Subsequent Event
Feb. 6, 2017
Line of Credit
MCB Finance Facility
Bank Guarantee
South African Public Investment Corporation
Subsequent Event
Mar. 15, 2017
Pacific Bora Drilling Rig
Subsequent Event
well
Mar. 15, 2017
Pacific Bora Drilling Rig
Nigeria
Subsequent Event
well
Subsequent Event [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock issued during period (in shares)
246,838 
 
 
31,841 
 
 
 
 
 
 
 
 
 
 
 
 
Equity instrument other than options, grants in the period (shares)
 
1,716,000 
500,000 
 
400,000 
 
 
200,000 
 
 
 
 
 
 
 
 
Proceeds from advance
 
 
 
 
 
$ 13,600,000 
 
 
 
 
 
 
 
 
 
 
Advance interest rate spread
 
 
 
 
 
 
6.50% 
 
 
 
 
 
 
 
 
 
Maximum borrowing capacity
 
 
 
 
 
 
 
 
 
 
100,000,000.0 
 
 
 
 
 
Deposit requirement
 
 
 
 
 
 
 
 
 
 
 
 
10,000,000 
 
 
 
Debt instrument, basis spread on variable rate (percent)
 
 
 
 
 
 
 
 
 
 
 
6.00% 
 
 
 
 
Bank guarantee amount
 
 
 
 
 
 
 
 
 
 
 
 
 
100,000,000 
 
 
Debt instrument, fee, dividend multiplier percentage for warrants issued
 
 
 
 
 
 
 
 
20.00% 
 
 
 
 
 
 
 
Upfront fee
 
 
 
 
 
 
 
 
 
2.50% 
 
 
 
 
 
 
Number of wells with option to drill
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 
2 
Base operating rate per day
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 195,000