Erin Energy (ERINQ) 10-Q 2016 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2016

OR

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

For the transition period from                      to                     

Commission File Number: 01-34525

ERIN ENERGY CORPORATION

Delaware	30-0349798
(State or Other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1330 Post Oak Blvd., Suite 2250, Houston, Texas	77056
(Address of principal executive offices)	(Zip Code)

(713) 797-2940

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer	¨	Accelerated filer	ý
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

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

At November 1, 2016, there were 212,686,734 shares of common stock, par value $0.001 per share, outstanding.

PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements:	3
	Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015 (unaudited)	3
	Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and 2015 (unaudited)	4
	Consolidated Statement of Capital Deficiency for the nine months ended September 30, 2016 (unaudited)	5
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015 (unaudited)	6
	Notes to Unaudited Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28
Item 4.	Controls and Procedures	29
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 5.	Other Information	32
Item 6.	Exhibits	33
Signatures		34

2

PART I. – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ERIN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

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

	September 30,   2016			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	8,304		$	8,363
Restricted cash	2,600			8,661
Accounts receivable - trade	—			1,029
Accounts receivable - partners	558			287
Accounts receivable - related party	1,844			1,186
Accounts receivable - other	44			28
Crude oil inventory	4,932			4,789
Prepaids and other current assets	1,128			684
Total current assets	19,410			25,027
Property, plant and equipment:
Oil and gas properties (successful efforts method of accounting), net	321,976			368,891
Other property, plant and equipment, net	892			1,174
Total property, plant and equipment, net	322,868			370,065
Other non-current assets	90			67
Total assets	$	342,368		$	395,159
LIABILITIES AND CAPITAL DEFICIENCY
Current liabilities:
Accounts payable and accrued liabilities	$	239,173		$	213,120
Accounts payable and accrued liabilities - related party	27,236			30,133
Current portion of long-term debt, net	8,141			96,558
Total current liabilities	274,550			339,811
Long-term notes payable - related party, net	128,987			120,006
Term loan facility, net	78,075			—
Asset retirement obligations	21,994			20,609
Total liabilities	503,606			480,426
Commitments and contingencies (Note 10)
Capital deficiency:
Preferred stock $0.001 par value - 50,000,000 shares authorized; none issued and outstanding as of September 30, 2016 and December 31, 2015, respectively	—			—
Common stock $0.001 par value - 416,666,667 shares authorized; 212,686,734 and 211,615,773 shares issued as of September 30, 2016 and December 31, 2015, respectively	213			212
Additional paid-in capital	792,319			789,615
Accumulated deficit	(954,345		)	(875,891		)
Treasury stock at cost, 90,347 and -0- shares as of September 30, 2016 and December 31, 2015, respectively	(206		)	—
Total deficit - Erin Energy Corporation	(162,019		)	(86,064		)
Non-controlling interest	781			797
Total capital deficiency	(161,238		)	(85,267		)
Total liabilities and capital deficiency	$	342,368		$	395,159

See accompanying notes to unaudited consolidated financial statements.

3

ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues:
Crude oil sales, net of royalties	$	28,619		$	28,667		$	56,699		$	28,667
Operating costs and expenses:
Production costs	24,928			27,651			69,615			53,224
Crude oil inventory (increase) decrease	636			368			534			(9,493		)
Workover expenses	207			354			7,792			972
Exploratory expenses	1,672			5,266			4,934			13,283
Depreciation, depletion and amortization	18,925			43,293			38,593			43,536
Accretion of asset retirement obligations	472			522			1,385			1,398
Loss on settlement of asset retirement obligations	—			779			205			4,233
General and administrative expenses	3,596			3,857			10,950			12,789
Total operating costs and expenses	50,436			82,090			134,008			119,942
Operating loss	(21,817		)	(53,423		)	(77,309		)	(91,275		)
Other income (expense):
Currency transaction gain	3,282			176			14,610			2,167
Interest expense	(5,038		)	(5,650		)	(16,417		)	(12,485		)
Total other expense, net	(1,756		)	(5,474		)	(1,807		)	(10,318		)
Loss before income taxes	(23,573		)	(58,897		)	(79,116		)	(101,593		)
Income tax expense	—			—			—			—
Net loss before non-controlling interest	(23,573		)	(58,897		)	(79,116		)	(101,593		)
Net loss attributable to non-controlling interest	102			215			662			690
Net loss attributable to Erin Energy Corporation	$	(23,471	)	$	(58,682	)	$	(78,454	)	$	(100,903	)
Net loss attributable to Erin Energy Corporation per common share:
Basic	$	(0.11	)	$	(0.28	)	$	(0.37	)	$	(0.48	)
Diluted	$	(0.11	)	$	(0.28	)	$	(0.37	)	$	(0.48	)
Weighted average common shares outstanding:
Basic	212,524			211,517			212,220			211,036
Diluted	212,524			211,517			212,220			211,036

See accompanying notes to unaudited consolidated financial statements.

4

ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CAPITAL DEFICIENCY

For the Nine Months Ended September 30, 2016

(Unaudited)

(In thousands)

	Common Stock		Additional Paid-in Capital		Accumulated Deficit			Treasury Stock			Non-controlling Interest			Total Equity
Balance at December 31, 2015	$	212	$	789,615	$	(896,451	)	$	—		$	797		$	(105,827	)
Correction of prior year error (see Note 13)	—		—		20,560			—			—			20,560
Revised balance at December 31, 2015	212		789,615		(875,891		)	—			797			(85,267		)
Common stock issued	1		363		—			—			—			364
Stock-based compensation	—		2,288		—			—			—			2,288
Warrants issued with debt	—		53		—			—			—			53
Transfer to treasury upon vesting of restricted stock	—		—		—			(206		)	—			(206		)
Non-controlling interest	—		—		—			—			646			646
Net loss	—		—		(78,454		)	—			(662		)	(79,116		)
Balance at September 30, 2016	$	213	$	792,319	$	(954,345	)	$	(206	)	$	781		$	(161,238	)

See accompanying notes to unaudited consolidated financial statements.

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ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2016			2015
Cash flows from operating activities
Net loss, including non-controlling interest	$	(79,116	)	$	(101,593	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation, depletion and amortization	38,593			43,536
Accretion of asset retirement obligations	1,385			1,398
Amortization of debt discount and debt issuance costs	2,640			1,920
Loss on settlement of asset retirement obligations	—			4,233
Foreign currency transaction gain	(14,610		)	(2,167		)
Share-based compensation	2,288			4,398
Payments to settle asset retirement obligations	—			(17,220		)
Change in operating assets and liabilities:
Decrease in accounts receivable	730			390
Decrease (increase) in crude oil inventory	534			(9,493		)
Decrease (increase) in prepaids and other current assets	(467		)	324
Increase in accounts payable and accrued liabilities	54,700			58,126
Net cash provided by (used in) operating activities	6,677			(16,148		)
Cash flows from investing activities
Capital expenditures	(16,475		)	(83,156		)
Net cash used in investing activities	(16,475		)	(83,156		)
Cash flows from financing activities
Proceeds from exercise of stock options and warrants	364			1,855
Payments for treasury stock arising from withholding taxes upon restricted stock vesting	(206		)	—
Repayments of term loan facility	(6,492		)	—
Proceeds from short-term notes payable	504			—
Proceeds from notes payable - related party, net	6,829			63,815
Repayment of short-term notes payable	(449		)	—
Proceeds from short-term borrowings, net	—			11,303
Debt issuance costs	(1,040		)	—
Funds released from restricted cash, net	6,061			—
Funding from non-controlling interest	—			553
Net cash provided by financing activities	5,571			77,526
Effect of exchange rate changes on cash and cash equivalents	4,168			836
Net decrease in cash and cash equivalents	(59		)	(20,942		)
Cash and cash equivalents at beginning of period	8,363			25,143
Cash and cash equivalents at end of period	$	8,304		$	4,201
Supplemental disclosure of cash flow information
Cash paid for:
Interest, net	$	10,090		$	7,886
Supplemental disclosure of non-cash investing and financing activities:
Issuance of common shares for settlement of liabilities	$	—		$	125
Discount on notes payable pursuant to issuance of warrants	$	53		$	4,911
Reduction in oil and gas properties arising from settlement of accounts payable and accrued liabilities	$	9,540		$	—
Reduction in accounts payable from settlement of Northern Offshore contingency	$	—		$	24,307

See accompanying notes to unaudited consolidated financial statements.

6

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Company Description

Erin Energy Corporation (NYSE MKT: ERN; JSE: ERN) is an independent oil and gas exploration and production company engaged in the acquisition and development of energy resources in Africa. The Company’s asset portfolio consists of nine licenses across four countries covering an area of approximately 10 million acres (approximately 40,000 square kilometers). The Company owns producing properties and conducts exploration activities offshore Nigeria, conducts exploration activities offshore Ghana and The Gambia, and both onshore and offshore 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 9 - 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 our Board of Directors, succeeded Dr. Lawal as the Chairman of the Board of Directors, and Segun Omidele, the Company's then Chief Operating Officer, succeeded Dr. Lawal as the Chief Executive Officer.

2. Basis of Presentation and Recently Issued Accounting Standards

The accompanying unaudited consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned direct and indirect subsidiaries, and have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). All significant intercompany transactions and balances have been eliminated in consolidation. The unaudited 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. This Form 10-Q should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on March 24, 2016.

Use of Estimates

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

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

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

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ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

the underlying assets and is depleted using the unit-of-production method in the same manner as the underlying assets.

During the nine months ended September 30, 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.

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 nine months ended September 30, 2016, 90,347 shares were withheld for taxes at a total cost of $0.2 million. The Company had no treasury stock withheld for taxes during the nine months ended September 30, 2015.

The following table sets forth certain information with respect to the withholding and related repurchases of our common stock during the nine months ended September 30, 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
Total	90,347	$	2.28

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

Net Earnings (Loss) Per Common Share

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

The table below sets forth the number of stock options, stock warrants, non-vested restricted stock, and shares issuable upon conversion of the Convertible Subordinated Note that were excluded from dilutive shares outstanding during the three and nine months ended September 30, 2016 and 2015, as these securities are anti-dilutive because the Company was in a loss position during each period.

	Three Months Ended September 30,		Nine Months Ended September 30,
(In thousands)	2016	2015	2016	2015
Stock options	206	1,094	249	1,110
Stock warrants	7	650	2	504
Unvested restricted stock awards	2,128	1,278	1,889	1,308
	2,341	3,022	2,140	2,922

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

8

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 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 debt at floating interest rates, approximate their fair values at September 30, 2016 and December 31, 2015, respectively, principally due to the short-term nature, maturities or nature of interest rates of the above listed items.

Reclassification

Certain reclassifications have been made to the 2015 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 the adoption of this standard on its 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

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ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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.

Adoption of Previously Issued ASUs

In April 2015, the FASB issued 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. The adoption of ASU 2015-03 resulted in the reclassification of approximately $1.6 million of unamortized debt issuance costs related to the Company's Term Loan Facility (see Note 8 - Debt) from prepaids and other current assets to current portion of long-term debt within its consolidated balance sheets as of December 31, 2015. Other than this reclassification, the adoption of ASU 2015-03 did not have an impact on the Company's consolidated financial statements.

3. Liquidity Matters and Going Concern

The Company incurred losses from operations for the three and nine months ended September 30, 2016. As of September 30, 2016, the Company's total current liabilities of $274.6 million exceeded its total current assets of $19.4 million, resulting in a working capital deficit of $255.1 million. As a result of the current low commodity prices and the Company’s low oil production

10

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

volumes due to the recent mechanical problem which was resolved earlier in the year associated with well Oyo-8, 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 of this year. This has resulted in a loss of approximately 1,400 BOPD. The Company is currently working on various intervention options to restore production, including nitrogen lifting from the FPSO via subsea umbilical and/or relocating an existing gaslift line to Oyo-7 to enable continuous gaslift gas injection into the well.

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 remainder of the 2016 exploration and development campaign and (vi) farming-out a portion of its rights to certain of its oil and gas properties. 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.

4. Property, Plant and Equipment

Property, plant and equipment were comprised of the following:

(In thousands)	September 30,   2016			December 31, 2015
Wells and production facilities	$	319,356		$	329,133
Proved properties	386,196			386,196
Work in progress and exploration inventory	66,765			65,043
Oilfield assets	772,317			780,372
Accumulated depletion	(460,781		)	(421,921		)
Oilfield assets, net	311,536			358,451
Unevaluated leaseholds	10,440			10,440
Oil and gas properties, net	321,976			368,891
Other property and equipment	3,092			2,963
Accumulated depreciation	(2,200		)	(1,789		)
Other property and equipment, net	892			1,174
Total property, plant and equipment, net	$	322,868		$	370,065

All of the Company’s oilfield assets are located offshore Nigeria in the Oil Mining Leases 120 and 121 (the "OMLs"). “Work-in-progress and exploration inventory” includes 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.

The Company’s unevaluated leasehold costs include costs to acquire the rights to the exploration acreage in its various oil and gas properties.

5. Suspended Exploratory Well Costs - Work in Progress

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. Plans are underway to secure a rig to drill at least one exploration well in the nearby G-Prospect. The primary objective of the G-Prospect is to target the same Miocene-age sediments as the ones found in the Oyo-7 exploratory drilling objective. Suspended exploratory well costs were $26.5 million at both September 30, 2016 and December 31, 2015 for the costs related to the Miocene exploratory drilling activities.

11

ERIN ENERGY CORPORATION

(formerly CAMAC ENERGY INC.)

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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 has completed a detailed evaluation of the results and has future development plans in the area. Suspended exploratory well costs were $6.5 million at both September 30, 2016 and December 31, 2015 for the costs related to the Pliocene exploration drilling activities in the eastern fault block.

6. Accounts Payable and Accrued Liabilities

The table below sets forth a summary of the Company’s accounts payable and accrued liabilities at September 30, 2016 and December 31, 2015:

(In thousands)	September 30, 2016		December 31, 2015
Accounts payable - vendors	$	168,997	$	153,085
Amounts due to government entities	66,274		53,119
Accrued payroll and benefits	1,696		629
Accrued interest	739		2,510
Other liabilities	1,467		3,777
	$	239,173	$	213,120

7. 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.

On a quarterly basis, the Company reviews the assumptions used to estimate the expected cash flows required to settle the asset retirement obligations, including changes in estimated probabilities, amounts and timing of the settlement of the asset retirement obligations, as well as changes in the legal obligation for each of its properties. Changes in any one or more of these assumptions may cause revisions in the estimated liabilities for the corresponding assets. The following summarizes changes in the Company’s asset retirement obligations during the nine months ended September 30, 2016 (in thousands):

Balance at January 1, 2016	$	20,609
Accretion expense	1,385
Balance at September 30, 2016	$	21,994

8. 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 with TOTSA Total Oil Trading SA ("TOTSA")(the “May Advance”). 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 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 crude oil lifting.

Short-Term Note Payable

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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:

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 Bank PLC ("Zenith"). 90.0% of the Term Loan Facility was available in U.S. dollars, while the remaining 10% was available in Nigerian Naira. U.S. dollar borrowings under the Term Loan Facility currently bear interest at the rate of 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 offshore 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 September 30, 2016, $2.5 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 nine months ended September 30, 2016, the Company made payments of $0.9 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 September 30, 2016, the Company recognized an unrealized foreign currency gain of $4.4 million on the Naira portion of the loan, reducing the balance under the Term Loan Facility to $86.2 million, net of debt discount. Of this amount, $78.1 million was classified as long-term and $8.1 million as short-term. Accrued interest for the Term Loan Facility was $0.7 million as of September 30, 2016. Scheduled principal repayments on the outstanding balance on the Term Loan Facility are as follows (in thousands):

Scheduled payments by year	Principal
2016	$	—
2017	13,388
2018	19,636
2019	21,421
2020 and thereafter	34,284
Total principal payments	88,729
Less: Unamortized debt issuance costs	2,513
Total Term Loan Facility, net	$	86,216

Long-Term Debt – Related Party:

As of September 30, 2016, the Company’s long-term related party debt was $129.0 million, consisting of $24.9 million owed

13

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

under a 2011 Promissory Note, $50.0 million owed under a 2014 Convertible Subordinated Note, $47.7 million, net of discount, owed under a 2015 Convertible Note, and $6.4 million owed under a 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 September 30, 2016, the Company was not in compliance with certain 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 has agreed to waive its rights under all default provisions of each of the Allied Notes through December 2017.

2011 Promissory Note

The Company has a $25.0 million borrowing facility under a Promissory Note (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 November 2016, the 2011 Promissory Note was amended to extend the maturity date to December 31, 2017. 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. The entire $25.0 million facility amount can be utilized for general corporate purposes. As of September 30, 2016, the outstanding principal and accrued interest under the 2011 Promissory Note were $24.9 million and $1.4 million, respectively.

2014 Convertible Subordinated Note

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

At the election of the holder, the 2014 Convertible Subordinated Note is convertible into shares of the Company’s common stock at an initial conversion price of $4.2984 per share, subject to anti-dilution adjustments. The 2014 Convertible Subordinated Note is subordinated to the Company’s existing and future senior indebtedness and is subject to acceleration upon an Event of Default (as defined in the 2014 Convertible Subordinated Note). The following events, among others, constitute an Event of Default under the 2014 Convertible Subordinated Note: the Company failing to pay interest within thirty days of the due date; the Company failing to pay principal when due; bankruptcy, insolvency, liquidation or dissolution of the Company; a material breach of the 2014 Convertible Subordinated Note by the Company that remains unremedied within ten days of such material breach; or a representation or warranty of the Company proves to have been incorrect or materially inaccurate when made. Upon any event of default, all outstanding principal and interest under any loans will become immediately due and payable. As of September 30, 2016, the Company owed $7.2 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 September 30, 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 new borrowing facility with Allied in the form of a Convertible Note (the “2015 Convertible Note”), allowing the Company to borrow up to $50.0 million for general corporate purposes. In March 2016, the maturity date of the 2015 Convertible Note was extended to December 2017. 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

14

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

During the nine months ended September 30, 2016, the Company borrowed an additional $0.5 million under the 2015 Convertible Note and issued to Allied warrants to purchase approximately 48,291 shares of the Company's common stock with an exercise price of ranging from $2.00 to $2.13 per share with a total fair value of approximately $0.1 million.

As of September 30, 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 debt discount, and is being amortized using the effective interest method over the life of the note. As of September 30, 2016, the unamortized balance of the discount was $0.8 million.

Additional warrants are issuable in connection with future borrowings, with the per share price for those warrants determined based on the market price of the Company’s common stock at the time of such future borrowings. As of September 30, 2016, the outstanding balance of the 2015 Convertible Note, net of discount, was $47.7 million. Accrued interest on the 2015 Convertible Note was $4.1 million as of September 30, 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.

During May and June 2016, the Company had additional drawings under the 2016 Promissory Note totaling $1.7 million.

During July and August 2016, the Company had additional drawings under the 2016 Promissory Note totaling $0.7 million.

As of September 30, 2016, the outstanding balance under the 2016 Promissory Note was $6.4 million. Accrued interest on the 2016 Promissory Note was $0.2 million as of September 30, 2016. In November 2016, the maturity date of the 2016 Promissory Note was extended to December 2017.

9. Related Party Transactions

Assets and Liabilities

The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates. The following table sets forth the related party assets and liabilities as of September 30, 2016 and December 31, 2015:

(In thousands)	September 30,   2016		December 31, 2015
Accounts receivable, CEHL	$	1,844	$	1,186
Accounts payable and accrued liabilities, CEHL	$	27,236	$	30,133
Long-term notes payable - related party, CEHL	$	128,987	$	120,006

As of September 30, 2016 and December 31, 2015, the related party receivable balances of $1.8 million and $1.2 million, respectively, were for advance payments made for certain transactions on behalf of affiliates.

As of September 30, 2016 and December 31, 2015, the Company owed $27.2 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 September 30, 2016 and December 31, 2015, accrued and unpaid interest on the various related party notes payable were $13.2 million and $8.3 million, respectively.

15

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

As of September 30, 2016, the Company had a combined note payable balance of $129.0 million owed to affiliates, consisting of a $50.0 million 2014 Convertible Subordinated Note, $24.9 million in borrowings under the 2011 Promissory Note, a $47.7 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 combined note payable balance of $120.0 million owed to an affiliate, consisting of the $50.0 million 2014 Convertible Subordinated Note, $25.0 million in borrowings under the 2011 Promissory Note, and $45.0 million borrowing under the 2015 Convertible Note, net of discount. See Note 8 – Debt for further information relating to the notes payable transactions.

Results from Operations

The table below sets forth a summary of transactions included in the Company's results of operations that were incurred with affiliates during the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands)	2016		2015		2016		2015
Total operating expenses, CEHL	$	4,825	$	4,316	$	8,844	$	9,239
Interest expense, CEHL	$	1,525	$	1,591	$	4,987	$	3,868

Certain affiliates of the Company provide procurement and logistical support services to the Company’s operations. In connection therewith, during the three months ended September 30, 2016 and 2015, the Company incurred operating costs amounting to approximately $4.8 million and $4.3 million, respectively, and during the nine months ended September 30, 2016 and 2015, the Company incurred operating costs amounting to approximately $8.8 million and $9.2 million, respectively

During the three months ended September 30, 2016 and 2015, the Company incurred interest expense, excluding debt discount amortization, totaling approximately $1.5 million and $1.6 million, respectively, in relation to related party notes payable. During the nine months ended September 30, 2016 and 2015, the Company incurred interest expense totaling approximately $5.0 million and $3.9 million, respectively.

10. Commitments and Contingencies

Commitments

In February 2014, a long-term contract was signed for the floating, production, storage, and offloading vessel (“FPSO”) Armada Perdana, which is the vessel currently connected to the Company’s 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. The annual minimum contractual 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 (the "Ghana Petroleum Agreement"). In all cases, the Company entered into these commitments through a subsidiary. To maintain compliance and ownership, the Company is required to fulfill certain minimum work obligations and to make certain payments as stated in each of the Kenya PSCs, the Gambia Licenses, and the Ghana Petroleum Agreement.

Contingencies

Legal Contingencies 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 September 30, 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, Erin Petroleum Nigeria Limited (fka CAMAC Petroleum Limited), as Respondents (the “Arbitration”). The Arbitration is in relation

16

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

to a drilling contract entered into by the Claimants and CAMAC Petroleum Limited, 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, of May 22, 2017.

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 Public Investment Corporation (SOC) Limited, a state-owned company incorporated in the Republic of South Africa (“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) our 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 February 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. A hearing on this motion has been set for 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 September 30, 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 will be 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.  The judgment debt has been partially satisfied prior to the date of this report, and all remaining sums claimed by this contractor are due to be discharged by the end of 2016.

Unrecognized Loss Contingency

As of September 30, 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 $12.7 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

17

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

As part of the condition to the extension of the maturity date of the 2015 Convertible Note, which extension was 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.

11. Stock-Based Compensation

Stock Options

The table below sets forth a summary of stock option activity for the nine months ended September 30, 2016.

	Shares Underlying Options (In Thousands)		Weighted-Average Exercise Price	Weighted-Average Remaining Contractual Term (Years)
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 September 30, 2016	1,147		$2.54	2.2
Expected to vest	289		$3.77	3.7
Exercisable at September 30, 2016	858		$2.13	1.8

During the nine months ended September 30, 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 nine months ended September 30, 2016, options to purchase 157,768 shares of common stock expired, and options to purchase 27,052 shares were forfeited.

Stock Warrants

The table below sets forth a summary of stock warrant activity for the nine months ended September 30, 2016.

	Shares Underlying Warrants (In Thousands)	Weighted-Average Exercise Price	Weighted-Average Remaining Contractual Term (Years)
Outstanding at December 31, 2015	2,935	$3.61	4.2
Granted	48	$2.07	4.6
Exercised	—	$—	—
Forfeited	—	$—	—
Expired	—	$—	—
Outstanding at September 30, 2016	2,983	$3.59	3.5
Expected to vest	—	$—
Exercisable at September 30, 2016	2,983	$3.59	3.5

During the nine months ended September 30, 2016 and in connection with the execution of the 2015 Convertible Note, the Company issued warrants to purchase 48,291 shares of the Company's common stock at exercise prices ranging from $2.00 and $2.13 per share. The warrants are exercisable at any time starting from the date of issuance and have a five-year term.  See Note 8 – Debt - 2015 Convertible Note.

Restricted Stock Awards

The table below sets forth a summary of restricted stock awards (“RSAs”) activity for the nine months ended September 30, 2016.

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

	Shares (In Thousands)		Weighted-Average Grant Date Price Per Share
Restricted Stock
Non-vested at December 31, 2015	1,114		$	3.21
Granted	1,717		$	2.16
Vested	(633	)	$	3.56
Forfeited	(90	)	$	2.59
Non-vested as of September 30, 2016	2,108		$	2.28

During the nine months ended September 30, 2016, the Company granted officers, directors, and employees a total of approximately 1.7 million shares of restricted common stock, including 0.5 million performance-based restricted stock awards ("PBRSA"), with vesting periods varying from immediate vesting to 36 months. During the same period, 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 is $0.4 million over three years.

12. Segment Information

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

Segment activity for the three and nine months ended September 30, 2016 and 2015 are as follows:

(In thousands)	Nigeria			Kenya			The Gambia			Ghana			Corporate and Other			Total
Three months ended September 30,
2016
Revenues	$	28,619		$	—		$	—		$	—		$	—		$	28,619
Operating loss	$	(17,323	)	$	(434	)	$	(728	)	$	(210	)	$	(3,122	)	$	(21,817	)
2015
Revenues	$	28,667		$	—		$	—		$	—		$	—		$	28,667
Operating loss	$	(44,858	)	$	(1,056	)	$	(3,985	)	$	(444	)	$	(3,080	)	$	(53,423	)
Nine months ended September 30,
2016
Revenues	$	56,699		$	—		$	—		$	—		$	—		$	56,699
Operating loss	$	(63,777	)	$	(1,485	)	$	(1,251	)	$	(1,328	)	$	(9,468	)	$	(77,309	)
2015
Revenues	$	28,667		$	—		$	—		$	—		$	—		$	28,667
Operating loss	$	(65,883	)	$	(7,162	)	$	(4,647	)	$	(1,393	)	$	(12,190	)	$	(91,275	)

Total assets by segment as of September 30, 2016 and December 31, 2015, are as follows:

(In thousands)	Nigeria		Kenya		The Gambia		Ghana		Corporate and Other		Total
Total Assets
As of September 30, 2016	$	332,822	$	1,365	$	3,006	$	3,479	$	1,696	$	342,368
As of December 31, 2015	$	387,326	$	1,399	$	3,016	$	2,447	$	971	$	395,159

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ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

13. Correction of Immaterial Error in Previously Issued Consolidated Financial Statement Information

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 information as of and for the year ended December 31, 2015 to correct this error. This correction will be reflected accordingly as they are included in future filings. 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 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, 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 certain amounts within the consolidated balance sheet, statement of operations, and 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

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ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

14. Subsequent Events

In November 2016, the Company received $4.0 million as an advance under a prepayment agreement with TOTSA (the “November Advance”). Interest accrued on the November Advance at the rate of the 60-day LIBOR plus 5% per annum. Repayment of the November Advance will be made from proceeds received from the November crude oil lifting.

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

Our Business

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

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

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

Our asset portfolio consists of nine licenses across four countries covering an area of approximately 10 million acres (approximately 40,000 square kilometers). We own producing properties offshore Nigeria and conduct exploration activities as an operator offshore Nigeria and conduct exploration activities as an operator onshore and offshore Kenya, offshore The Gambia, and offshore Ghana.

Our operating subsidiaries include Erin Petroleum Nigeria Limited, Erin Energy Kenya Limited, Erin Energy Gambia Ltd., and Erin Energy Ghana Limited.

We conduct certain business transactions with our majority shareholder, CAMAC Energy Holdings Limited (“CEHL”) and its affiliates, which include CAMAC Nigeria Limited (“CNL”) and Allied. See Note 9 - Related Party Transactions to the Notes to Unaudited Consolidated Financial Statements 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 our Board of Directors, succeeded Dr. Lawal as the Chairman of the Board of Directors, and Segun Omidele, our then Chief Operating Officer, succeeded Dr. Lawal as the Chief Executive Officer.

Nigeria

The Company currently owns 100% of the economic interests in the Oil Mineral Leases ("OMLs"), which include the currently producing Oyo field.

In early May 2016, with the help of a light intervention vessel, the Company successfully completed well repair operations to resolve the mechanical problem related to well Oyo-8 and successfully resumed production from the well. In early July 2016, well Oyo-7 was shut-in as a result of an emergency shut-in of the Oyo field production. This has resulted in a loss of approximately 1,400 BOPD. The Company is currently working on various intervention options to restore production, including nitrogen lifting from the FPSO via subsea umbilical and/or relocating an existing gaslift line to Oyo-7 to enable continuous gaslift gas injection into the well.

Daily production mainly from well Oyo-8 during the three months ended September 30, 2016 was approximately 6,900 BOPD (approximately 6,100 BOPD net to the Company after royalty).

Current plans include drilling a development well in the Oyo field, and drilling an exploration well in the Miocene formation of the OMLs, subject to capital and rig availability.

Kenya

In May 2012, the Company, through a wholly owned subsidiary, entered into four production sharing contracts with the Government of the Republic of Kenya, covering onshore exploration blocks L1B and L16, and offshore exploration blocks L27 and L28 (the “Kenya PSCs”). Each block requires specific work commitments to be completed by the end of the respective license periods. The Company is the operator of all blocks with the Government having the right to participate up to 20%, either directly or through an appointee, in any area subsequent to declaration of a commercial discovery. The Company is responsible for all exploration expenditures.

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The Company is currently in the First Additional Exploration Period for both onshore blocks, which will last through July 2017. In accordance with the Kenya PSCs, the Company is obligated, for each block, to (i) acquire, process and interpret high density 300 square kilometer 3-D seismic data at a minimum expenditure of $12.0 million and (ii) drill one exploration well to a minimum depth of 3,000 meters at a minimum expenditure of $20.0 million. The Company plans to pursue completion of the work program and is considering the possibility of farming-out a portion of its rights to both blocks to potential partners.

In August 2015, the Company received approval from the Kenya Ministry of Energy and Petroleum for an 18-month extension of the Initial Exploration Period for offshore blocks L27 and L28, which will now last through February 2017. The remaining contractual obligation under the initial exploration period is for the Company to acquire, process and interpret 1,500 square kilometers of 3-D seismic data over both offshore blocks. The Company plans to pursue completion of the work program, and is also considering the possibility of farming-out a portion of its rights to both offshore blocks to potential partners. Upon completion of the work program, the Company has the right to apply for up to two additional two-year exploration periods, with specified additional minimum work obligations, including the acquisition of seismic data and the drilling of one exploratory well on each block during each additional period.

The Gambia

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

The term of the initial exploration period for both blocks A2 and A5, now extended through December 2018, require for the Company to (i) complete the processing and interpretation of approximately 1,500 square kilometers of 3-D seismic data that was acquired in September 2015 and (ii) drill one exploration well on either block A2 or A5 and evaluate the drilling results. The 3-D seismic processing by an outside contractor was completed in the third quarter of 2016, and will be available to the Company upon final payment of the amounts described in the last paragraph of Note 10 - Commitments and Contingencies under “Legal Contingencies and Proceedings". The Company intends to pursue completion of the work program, and is also considering the possibility of farming-out a portion of its rights to both blocks to potential partners.

Ghana

In April 2014, the Company, through an indirect 50%-owned subsidiary, signed a Petroleum Agreement with the Republic of Ghana (the “Petroleum Agreement”) relating to 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 Corporation 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 Company owns 50% of its subsidiary Erin Energy Ghana Limited. The remaining 50% interest is owned by an affiliate of the Company’s majority shareholder. 

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 Petroleum Agreement became effective in January 2015. Having completed 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 Erin Energy an extension of the Initial Exploration Period for eighteen months until the end of July 2018.

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Results of Operations

The following discussion pertains to the Company’s results of operations, financial condition, liquidity and capital resources and should be read together with our unaudited consolidated financial statements and the notes thereto contained in this report, and our audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2015, filed on March 24, 2016 with the SEC.

Three months ended September 30, 2016, compared to three months ended September 30, 2015

Revenues

Revenue is recognized when an oil lifting occurs. Crude oil revenues for the three months ended September 30, 2016 were $28.6 million, as compared to $28.7 million for the same period in 2015. For the three months ended September 30, 2016, the Company sold approximately 583,000 net barrels of oil at an average price of $49.07/Bbl. For the three months ended September 30, 2015, the Company sold approximately 571,000 net barrels of oil at an average price of $50.2/Bbl.

During the three months ended September 30, 2016 and 2015, the average daily production from the Oyo field, net of royalty, over the number of days production occurred, was approximately 6,100 BOPD and 10,200 BOPD, respectively.

Operating Costs and Expenses

Production costs for the three months ended September 30, 2016 were $24.9 million, as compared to $27.7 million for the same period in 2015. Production costs include costs directly related to the production of hydrocarbons. 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 of July 2014 through April 2015, which resulted in a $26.0 million reduction in production costs recognized in June 2015. There was no such reduction in 2016. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized with a corresponding offset to operating costs. The capitalized crude oil inventory costs are subsequently expensed when crude oil is sold.

During the three months ended September 30, 2016, the Company incurred $0.2 million of workover expenses, as compared to workover expenses of $0.4 million for the same period in 2015. The decrease in workover expenses in 2016 compared to the same period 2015 was due to the repair in 2015 of a control module associated with its well Oyo-4 that is currently operating as a gas injection well.

During the three months ended September 30, 2016, the Company incurred $1.7 million of exploration expenses, including $0.4 million spent in Kenya, $0.4 million spent in Nigeria, $0.2 million spent in Ghana, and $0.7 million spent in The Gambia. During the three months ended September 30, 2015, the Company incurred $5.3 million of exploration expenses, including $0.8 million spent in Kenya, $3.9 million in The Gambia primarily for 3-D seismic acquisition, and $0.4 million spent in Ghana.

Depreciation, depletion and amortization (“DD&A”) expenses for the three months ended September 30, 2016, were $18.9 million, as compared to $43.3 million for the same period in 2015. DD&A expenses were higher during the three months ended September 30, 2015 due to the higher depletion rates in 2015 as compared to that in 2016. The average depletion rate for the three months ended September 30, 2016 was $28.55/Bbl, as compared to $66.74/Bbl in the same period in 2015. The decrease in the average depletion rate in 2016 as compared to 2015 was mainly due to the impairment of oil and gas properties recorded at December 31, 2015,

Accretion of asset retirement obligations ("ARO") for the three months ended September 30, 2016 and 2015 was $0.5 million. ARO accretion expense for both 2016 and 2015 relates to the development of wells Oyo-7 and Oyo-8.

There was no plug and abandonment ("P&A") activity during the three months ended September 30, 2016. In April 2015, the Company completed P&A activities for well Oyo-6 that was previously shut-in. Actual P&A expenditures exceeded estimated P&A liabilities by $0.8 million. Accordingly, the Company recognized a $0.8 million loss on settlement of its ARO during the three months ended September 30, 2015.

General and administrative ("G&A") expenses for the three months ended September 30, 2016 were $3.6 million, as compared to $3.9 million in the same period in 2015. G&A decreased in 2016 mainly due to the cost reduction initiatives implemented during 2016, primarily related to employee costs and professional and consulting fees.

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Other Income (Expense), Net

Other expense for the three months ended September 30, 2016 was $1.8 million, consisting of $5.0 million interest expense on borrowings, partially offset by a $3.3 million gain on foreign currency transactions. Other expense for the same period in 2015 was $5.5 million consisting of $5.7 million in interest expense on borrowings, partially offset by a $0.2 million gain on foreign currency transactions.

Income Taxes

Income taxes were nil for each of the three months ended September 30, 2016 and 2015. The Company did not have any taxable income from its oil and gas activities in Nigeria in these respective periods.

Nine months ended September 30, 2016, compared to nine months ended September 30, 2015

Revenues

Revenue is recognized when an oil lifting occurs. Crude oil revenues for the nine months ended September 30, 2016 were $56.7 million, as compared to $28.7 million for the same period in 2015. For the nine months ended September 30, 2016, the Company sold approximately 1,253,000 net barrels of oil at an average price of $45.27/Bbl. For the nine months ended September 30, 2015, the Company sold approximately 571,000 net barrels of oil at an average price of $50.20/Bbl.

During the nine months ended September 30, 2016 and 2015, the average daily production from the Oyo field, net of royalty, over the number of days production occurred, was approximately 4,500 BOPD and 8,700 BOPD, respectively.

Operating Costs and Expenses

Production costs for the nine months ended September 30, 2016 were $69.6 million, as compared to expenditures of $53.2 million for the same period in 2015. Production costs include costs directly related to the production of hydrocarbons. 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 of July 2014 through April 2015, which resulted in a $26.0 million reduction in production costs recognized in June 2015. There was no such reduction in 2016. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized with a corresponding offset to operating costs. The capitalized crude oil inventory costs are subsequently expensed when crude oil is sold.

During the nine months ended September 30, 2016, the Company incurred $7.8 million of workover expenses, as compared to expenditures of $1.0 million for the same period in 2015. The increase in workover expenses is due to the light intervention of well Oyo-8. During the same period 2015, the Company spent $1.0 million to repair a control module associated with its well Oyo-4 that is currently operating as a gas injection well.

During the nine months ended September 30, 2016, the Company incurred $4.9 million of exploration expenses, including $1.2 million spent in Ghana, $1.4 million spent in Kenya, $1.1 million spent in Nigeria, and $1.2 million spent in The Gambia. During the nine months ended September 30, 2015, the Company incurred $13.3 million of exploration expenses, including $6.9 million spent in Kenya primarily for the 2-D seismic acquisition and processing, $4.6 million spent in The Gambia primarily for 3-D seismic acquisition, $1.3 million spent in Ghana, and $0.4 million spent in Nigeria.

DD&A expenses for the nine months ended September 30, 2016, were $38.6 million, as compared to $43.5 million for the same period in 2015. DD&A expenses were higher during the nine months ended September 30, 2015 mainly due to the higher depletion rates in 2015 as compared to that in 2016. The average depletion rate for the nine months ended September 30, 2016 was $30.81/Bbl, as compared to $76.26/Bbl in the same period in 2015. The decrease in the average depletion rate in 2016 as compared to 2015 was mainly due to the impairment of oil and gas properties recorded at December 31, 2015,

Accretion of ARO for both the nine months ended September 30, 2016 and 2015 was $1.4 million.

The Company recorded P&A expenses of $0.2 million during the nine months ended September 30, 2016. In April 2015, the Company completed P&A activities for well Oyo-6 that was previously shut-in. Additional P&A expenditures paid in the nine months ended September 30, 2015, in relation to well Oyo-6 P&A activities were $4.2 million. Accordingly, the Company recognized this cost as a loss on settlement of its ARO during 2015.

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G&A expenses for the nine months ended September 30, 2016 were $11.0 million, as compared to $12.8 million in the same period in 2015. G&A decreased in 2016 mainly due to the cost reduction initiatives implemented during 2016, primarily related to employee costs and professional and consulting fees.

Other Income (Expense), Net

Other expense for the nine months ended September 30, 2016 was $1.8 million, consisting of $16.4 million interest expense on borrowings, partially offset by a $14.6 million gain on foreign currency transactions. Other expense for the same period in 2015 was $10.3 million, consisting of $12.5 million in interest expense on borrowings, net of $2.2 million capitalized interest, partially offset by $2.2 million gain on foreign currency transactions. The increase in interest expense was mainly due to the increase in the average outstanding borrowings during 2016 as compared to 2015, and that no interest was capitalized during 2016.

Income Taxes

Income taxes were nil for each of the nine months ended September 30, 2016 and 2015. The Company did not have any taxable income from its oil and gas activities in Nigeria in these respective periods.

Headline Earnings 

In addition to the Company’s primary listing on the NYSE MKT, the Company’s common stock is also traded on the JSE. The JSE requires the Company to file certain documents that it files with the SEC. The JSE also requires that we calculate Headline Earnings Per Share (“HEPS”) which, per the SEC, is considered a non-GAAP measurement.

As defined in the Circular 3/2009 of The South African Institute of Chartered Accountants, headline earnings is an additional earnings number that excludes certain separately identifiable re-measurements, net of related tax, and related non-controlling interest.

The number of shares used to calculate basic and diluted HEPS is the same as basic and diluted EPS. During the three and nine months ended September 30, 2016 and 2015, there were no separate identifiable re-measurements required and headline earnings was the same as net loss per share as disclosed on the unaudited consolidated statements of operations. Therefore, HEPS for the three months ended September 30, 2016 and 2015, was a loss of $(0.11) and $(0.28), respectively, and for the nine months ended September 30, 2016 and 2015, was a loss of $(0.37) and $(0.48), respectively.

Liquidity

Cash Flows from Operating Activities

Net cash provided by operating activities was $6.7 million for the period, as compared to net cash used in operating activities of $16.1 million in the prior period. Cash used in operating activities in the nine months ended September 30, 2016 decreased by $22.8 million as compared to the same period in 2015 primarily due to a combination of higher revenues, use of vendor financing and higher non-cash adjustments to net loss.

Cash Flows from Investing Activities

Cash used in investing activities for the nine months ended September 30, 2016 was $16.5 million, as compared to $83.2 million for the same period in 2015. Cash used in investing activities for both periods was used primarily to settle outstanding liabilities associated with additions to property, plant, and equipment for the Oyo field redevelopment campaign in the OMLs.

Cash Flows from Financing Activities

Net cash provided by financing activities of $5.6 million in the nine months ended September 30, 2016, consisted of $6.1 million funds released from restricted cash, $6.8 million inflows from short-term borrowings from related parties, $0.5 million proceeds from a short-term note payable, and $0.4 million proceeds from the exercise of stock options, partially offset by $6.5 million principal repayment of our Term Loan Facility, $1.0 million payment for debt issuance costs, $0.4 million repayment of short-term note payable, and $0.2 million payment to settle withholding tax obligations upon vesting of restricted stock awards. Net cash provided by financing activities of $77.5 million for the nine months ended September 30, 2015 consisted of $63.8 million

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borrowings from related parties, $11.3 million advance from Glencore, $1.9 million proceeds from the exercise of stock options and warrants, and $0.6 million in funding from an entity owning a non-controlling interest in the Company's Ghana subsidiary.

Capital Resources

Our primary cash requirements are for capital expenditures for the continued development of the Oyo field in Nigeria, operating expenditures for the Oyo field, exploration activities in unevaluated leaseholds, working capital needs, and interest and principal payments under current indebtedness.

We incurred losses from operations for the three and nine months ended September 30, 2016. As of September 30, 2016, the Company's total current liabilities of $274.6 million exceeded its total current assets of $19.4 million, resulting in a working capital deficit of $255.1 million. As a result of the current low commodity prices and our low oil production volumes due to the recent mechanical problem which was resolved earlier in the year associated with well Oyo-8, we have 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 of this year. This has resulted in a loss of approximately 1,400 BOPD. We are currently working on various intervention options to restore production, including nitrogen lifting from the FPSO via subsea umbilical and/or relocating an existing gaslift line to Oyo-7 to enable continuous gaslift gas injection into the well.

We are 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 remainder of the 2016 exploration and development campaign and (vi) farming-out a portion of our rights to certain of our oil and gas properties. 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.

In February 2016, we lifted and sold approximately 183,000 Bbls of crude oil (approximately 161,000 Bbls net to the Company). Net proceeds to us were approximately $4.9 million.

In April 2016, we lifted and sold approximately 159,000 Bbls of crude oil (approximately 140,000 Bbls net to the Company). Net proceeds to us were approximately $5.6 million.

In June 2016, we lifted and sold approximately 418,000 Bbls of crude oil (approximately 368,000 Bbls net to the Company). Net proceeds to us were approximately $17.6 million.

In August 2016, we lifted and sold approximately 431,000 Bbls of crude oil (approximately 379,000 Bbls net to the Company). Net proceeds to us were approximately $18.9 million.

In September 2016, we lifted and sold approximately 232,000 Bbls of crude oil (approximately 204,000 Bbls net to the Company). Net proceeds to us were approximately $9.8 million.

Although we believe that we will be able to generate sufficient liquidity from the measures described above, our current circumstances raise substantial doubt about our ability to continue to realize the carrying value of our assets and operate as a going concern.

Off-Balance Sheet Arrangements

From time-to-time, we may enter into arrangements that can give rise to off-balance sheet obligations. As of September 30, 2016, material off-balance sheet obligations include operating leases for the FPSO and certain employment contracts. Other than the material off-balance sheet arrangements discussed above, no other arrangements are likely to have a current or future material effect on our financial condition, results from operations, liquidity, capital expenditures or capital resources.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. All statements, other than statements of historical fact, in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected

27

revenues, projected costs and plans and objectives of management for future operations, are, or may be deemed to be, forward-looking statements. Such forward-looking statements involve assumptions, known and unknown risks, uncertainties and other factors, which may cause the actual results, performance or achievements of the Company, to be materially different from historical earnings and those presently anticipated or projected or any future results, performance or achievements expressed or implied by such forward-looking statements contained in this report.

In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “project,” “should,” “will,” “will likely,” or similar expressions. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. We caution you not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Important factors that could affect our financial performance and that could cause actual results for future periods to differ materially from our expectations include, but are not limited to:

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

• our current and future indebtedness;

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

• our ability to develop oil and gas reserves;

• competition from other companies in the energy market;

• political instability and foreign government regulations over international operations;

• our lack of diversification of production and reserves;

• compliance and enforcement of restriction on production and exports;

• compliance and enforcement of environmental laws and regulations;

• our ability to achieve profitability;

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

• other factors disclosed under Item 1. Description of Business, Item 1A. Risk Factors, Item 2. Properties, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2015, and elsewhere in this report.

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

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, please see “Risk Factors” in Item 1A of Part II of this report and in our Quarterly Reports on Form 10-Q for the quarterly periods March 31, 2016 and June 30, 2016 and in our Annual Report on Form 10-K for the year ended December 31, 2015. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Foreign Currency Exchange Risk

Our results of operations and financial conditions are affected by currency exchange rates. While oil sales are denominated in U.S. dollars, portions of our capital and operating costs in Nigeria are denominated in Naira, the Nigerian local currency. Similarly, portions of our exploration costs in Kenya, The Gambia, and Ghana are denominated in each country’s respective local currency.

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Historically, the exchange rate between the U.S. dollar and the local currencies in the countries in which we operate has fluctuated widely in response to international political conditions, general economic conditions, and other factors beyond our control.

The weighted average exchange rate between the U.S. dollar and the Nigerian Naira was 189.38 Naira per each U.S. dollar for the nine months ended September 30, 2016. For the nine months ended September 30, 2016, a 10% fluctuation in the weighted average exchange rate between the U.S. dollar and the Nigerian Naira would have had an approximate $4.6 million impact on our capital and operating costs in Nigeria.

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

Commodity Price Risk

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

Historically, realized commodity prices received for our crude oil sales have been tied to the Brent oil prices. Prices received have been volatile and unpredictable. For the nine months ended September 30, 2016, a $10.00 fluctuation in the prices received for our crude oil sales would have had an approximate $12.5 million impact on our revenues.

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

Interest Rate Risk

We are exposed to changes in interest rates, primarily from possible fluctuations in the London Interbank Borrowing Rate (“LIBOR”). The interest rates on our debt obligations are stated at floating rates tied to the LIBOR. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. For the nine months ended September 30, 2016, the weighted average interest rate on our variable rate debt was 9.2%. Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our various debt facilities would result in an increase of our interest expense by $2.2 million over a twelve month period.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Management of the Company, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2016. Based on their evaluation, as of the end of the period covered by this Form 10-Q, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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The disclosures required in this Item 1 are included in Note 10 - Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements included in Part I, Financial Information, Item 1, Financial Statements and incorporated herein by reference.

Item 1A. Risk Factors

The following risk factors update the Risk Factors included in our Annual Report on Form 10-K filed with the SEC on March 24, 2016 for the fiscal year ended December 31, 2015 (the “Annual Report”). Except as set forth below, there have not been any material changes to the risk factors previously disclosed in Part I, Item 1A of the Annual Report.

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

As of September 30, 2016, we had approximately $50.0 million outstanding in aggregate principal under the 2014 Convertible Subordinated Note, $47.7 million, net of discount, under the 2015 Convertible Note, $86.2 million, net of discount, under the Term Loan Facility, $24.9 million under the 2011 Promissory Note, and $6.4 million under a 2016 Promissory Note, and we may incur additional indebtedness in the future. Our level of indebtedness has, or could have, important consequences to our business because:

• a substantial portion of our cash flows from operations will be dedicated to interest and principal payments and may not be available for operations, working capital, capital expenditures, expansion, acquisitions, general corporate or other purposes;

• it may impair our ability to obtain additional financing in the future for acquisitions, capital expenditures or general corporate purposes;

• it may limit our flexibility in planning for, or reacting to, changes in our business and industry; and

• we may be substantially more leveraged than some of our competitors, which may place us at a relative competitive disadvantage and make us more vulnerable to downturns in our business, our industry or the economy in general.

In addition, the terms of the Term Loan Facility restrict, and the terms of any future indebtedness including any future credit facility may restrict, our ability to incur additional indebtedness and grant liens because of debt or financial covenants we are, or may be, required to meet. Thus, we may not be able to obtain sufficient capital to grow our business or implement our business strategy and may lose opportunities to acquire interests in oil properties or related businesses because of our inability to fund such growth.

Our ability to comply with restrictions and covenants, including those in the Term Loan Facility or in any future credit facility, is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants in the Term Loan Facility could result in a default, which could permit the lenders to accelerate repayments and foreclose on the collateral securing such indebtedness.

Events of default may occur under the Allied related party notes, subject to waivers entered into by the Company and Allied in March 2016 and as subsequently amended. If events of default occur or Allied accelerates the repayment obligations, as to matters not covered or no longer covered by the waivers, cross-defaults will exist under the Allied related party notes, and we will not be able to repay the obligations that become immediately due.

Allied, a related party, is the holder of the 2014 Convertible Subordinated Note, the 2015 Convertible Note, and the 2011 Promissory 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 September 30, 2016, the Company was not in compliance with the default provisions of each 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 December 2017. For additional information regarding defaults, cross-defaults and potential cross-defaults, please see the discussion regarding each debt instrument in Note 8 - Debt to the financial statements included herein. If any of our debt obligations are accelerated due to the events of default or future cross-defaults, we may not be able to repay the obligations that become immediately due and will have severe liquidity restraints.

Due to lack of liquidity, we may not be able to make the required principal and interest payments under the Term Loan Facility due quarterly beginning June 1, 2017.

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As a result of the current low commodity prices and a prior history of low oil production volumes related to mechanical problems with well Oyo-8, the Company has not been able to generate sufficient cash from operations to satisfy certain obligations as they become due. The Company has been relying on short-term promissory notes, such as the 2016 Promissory Note, with an entity related to the Company’s majority shareholder to supplement its liquidity needs, but there can be no assurances that the related party will continue to provide such short-term loans in the future.

Pursuant to the Term Loan Facility, Zenith has the right to review the terms and conditions of the Term Loan Facility.

Our failure to make the required payments under the Term Loan Facility, maturing in 2021, or to comply with its applicable debt covenants could result in a default under the Term Loan Facility and a cross-default under the Allied Notes as described in the preceding risk factor, which could result in the acceleration of the payment of such debt, termination of Zenith’s commitments to make further loans to us, loss of our ownership interests in the secured properties or otherwise materially adversely affect our business, financial condition and results of operations. Also, if we are unable to service our debt obligations generally, we cannot assure you that the Company will continue in its current state or continue to operate as a going concern.

We may be unable to continue as a going concern.

As mentioned in the risk factors above, we have substantial debt obligations and may not be able to maintain adequate liquidity throughout 2016. As a result, the Company’s consolidated financial statements included in this Quarterly Report on Form 10-Q 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. Our financial statements do not include any adjustments that might result from the outcome of this uncertainty. Although the Company believes that it will be able to generate sufficient liquidity, its current circumstances raise substantial doubt about its ability to continue to operate as a going concern. If we become unable to continue as a going concern, we may have to liquidate our assets, and the values we receive for our assets in liquidation or dissolution could be significantly lower than the values reflected in our financial statements.

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

Unregistered Sales of Equity Securities

During the nine months ended September 30, 2016, we borrowed an additional $0.5 million under the 2015 Convertible Note and issued to Allied warrants to purchase approximately 48,291 shares of the Company's common stock with an exercise price ranging from $2.00 to $2.13 per share. For further information, see Note 8 - Debt to the Unaudited Consolidated Financial Statements.

Issuer Purchases of Equity Securities

The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended September 30, 2016.

	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan or Program	Maximum Number  (or Approximate Dollar Value) of Shares that May be Purchased Under the Plans or Programs
September 1 - September 30, 2016	6,162	$	2.29	—	—
Total	6,162	$	2.29	—	—

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

Item 5. Other Information

Effective May 26, 2016 and executed on July 11, 2016, the Company and Mr. Babatunde (Segun) Omidele entered into an Employment Offer Letter (the “Omidele Employment Agreement”) that replaced and superseded the prior employment offer letter, dated as of September 1, 2011, between Mr. Omidele and the Company. The Omidele Employment Agreement sets forth the definitive terms of the compensation arrangements previously disclosed in the Company’s Form 8-K filed March 17, 2016. Pursuant to the Omidele Employment Agreement, Mr. Omidele, while serving as the Chief Executive Officer, receives an annual base salary of $350,000. Mr. Omidele is also eligible for a discretionary cash performance bonus each year targeted at between 0% and 100% of his then-current base salary, as well as additional equity grants valued at up to 200% of his then-current base salary, at the discretion of the Company’s Board. In addition, if the Company terminates Mr. Omidele’s employment without Cause (as defined in the Omidele Employment Agreement), (i) the Company must pay to Mr. Omidele an amount equal to the two times base salary plus target annual bonus as determined by the Board for the year of termination, and (ii) any outstanding restricted stock and stock options will have their vesting period immediately accelerated by 24 months, with all vested Company stock options (including accelerated options) remaining exercisable for a period of 24 months following the date of separation, in exchange for a full release of all claims against the Company and its related parties The agreement also includes confidentiality, noncompetition and nonsolicitation covenants.

Further, the Company and Mr. Omidele entered into on November 14, 2016 a Retention Bonus Agreement (the “Retention Bonus Agreement”). Pursuant to the Retention Bonus Agreement, the Company will pay Mr. Omidele a bonus equal to two times his then-current annual base salary, as defined in the Omidele Employment Agreement, on May 26, 2019 if he is still employed by the Company on that date. The Company will pay such bonus in twenty-four equal monthly installments commencing on the last day of the first month following the termination of Mr. Omidele’s employment with the Company. If his employment with the Company is terminated at any time before May 26, 2019, for any reason, the right to the bonus, or any portion thereof, will lapse and be forfeited.

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Item 6. Exhibits

The following exhibits are filed with this report:

Exhibit Number	Description
3.1	Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 10-SB filed on August 16, 2007).
3.2	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 13, 2010).
3.3	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 19, 2014).
3.4	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 23, 2015).
3.5	Amended and Restated Bylaws of the Company as of April 11, 2011 (incorporated by reference to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q filed on May 3, 2011).
3.6	First Amendment to the Amended and Restated Bylaws of the Company adopted on March 11, 2016 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on March 17, 2016.
10.1	Offer of Employment as Chief Executive Officer, executed July 11, 2016, by and between the Company and Babatunde (Segun) Omidele.
10.2	Retention Bonus Agreement, executed November 14, 2016, by and between the Company and Babatunde (Segun) Omidele.
31.1	Certification of Chief Executive Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101. INS	XBRL Instance Document.
101. SCH	XBRL Schema Document.
101. CAL	XBRL Calculation Linkbase Document.
101. DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101. LAB	XBRL Label Linkbase Document.
101. PRE	XBRL Presentation Linkbase Document.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Erin Energy Corporation

Date: November 14, 2016

/s/ Daniel Ogbonna

Daniel Ogbonna

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

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