Erin Energy Corp. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Erin Energy Corp.	q32017exhibit_322.htm
EX-32.1 - EXHIBIT 32.1 - Erin Energy Corp.	q32017exhibit_321.htm
EX-31.2 - EXHIBIT 31.2 - Erin Energy Corp.	q32017exhibit_312.htm
EX-31.1 - EXHIBIT 31.1 - Erin Energy Corp.	q32017exhibit_311.htm
EX-10.4 - EXHIBIT 10.4 - Erin Energy Corp.	q32017exhibit_104.htm

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, 2017



¨	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”, “smaller reporting company”, and "emerging growth 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	¨
		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

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

At November 1, 2017, there were 214,954,229 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, 2017 (unaudited) and December 31, 2016	3

	Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016 (unaudited)	4

	Consolidated Statement of Capital Deficiency for the nine months ended September 30, 2017 (unaudited)	5

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016 (unaudited)	6

	Notes to Unaudited Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37

Item 4.	Controls and Procedures	37

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 5.	Other Information	40

Item 6.	Exhibits	41

Signatures		42

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, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	18,132		$	7,177
Restricted cash	13,761			2,600
Accounts receivable - trade	14,691			—
Accounts receivable - partners	2,232			674
Accounts receivable - related party	2,821			1,956
Accounts receivable - other	5			29
Crude oil inventory	1,333			9,398
Prepaids and other current assets	2,462			872
Total current assets	55,437			22,706

Property, plant and equipment:
Oil and gas properties (successful efforts method of accounting), net	173,594			265,713
Other property, plant and equipment, net	425			716
Total property, plant and equipment, net	174,019			266,429

Other non-current assets	35			66

Total assets	$	229,491		$	289,201

LIABILITIES AND CAPITAL DEFICIENCY
Current liabilities:
Accounts payable and accrued liabilities	$	261,742		$	244,963
Accounts payable and accrued liabilities - related party	33,388			29,513
Accounts payable - partners	87			—
Short-term note payable - related party	200			—
Current portion of long-term debt, net	69,080			12,627
Derivative liability	1,751			—
Total current liabilities	366,248			287,103

Long-term notes payable - related party, net	129,821			129,796
Long-term debt, net	68,786			74,446
Asset retirement obligations	23,910			22,476

Total liabilities	588,765			513,821

Commitments and contingencies (Note 9)

Capital deficiency:
Preferred stock $0.001 par value - 50,000,000 shares authorized; none issued and outstanding as of September 30, 2017 and December 31, 2016, respectively	—			—
Common stock $0.001 par value - 416,666,667 shares authorized; 214,954,229 and 212,622,218 shares outstanding as of September 30, 2017 and December 31, 2016, respectively	215			213
Additional paid-in capital	798,210			792,972
Accumulated deficit	(1,157,434		)	(1,018,292		)
Treasury stock at cost, 304,481 and 99,932 shares as of September 30, 2017 and December 31, 2016, respectively	(936		)	(228		)
Total deficit - Erin Energy Corporation	(359,945		)	(225,335		)
Non-controlling interest	671			715
Total capital deficiency	(359,274		)	(224,620		)
Total liabilities and capital deficiency	$	229,491		$	289,201

See accompanying notes to unaudited consolidated financial statements.

ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues:
Crude oil sales, net of royalties	$	33,643		$	28,619		$	79,509		$	56,699

Operating costs and expenses:
Production costs	22,358			24,928			59,548			69,615
Crude oil inventory decrease	4,100			636			4,017			534
Workover expenses	—			207			(713		)	7,792
Exploratory expenses	1,313			1,672			3,711			4,934
Depreciation, depletion and amortization	13,059			18,925			50,229			38,593
Accretion of asset retirement obligations	489			472			1,434			1,385
Impairment of oil and gas properties	—			—			78,711			—
Loss on settlement of asset retirement obligations	—			—			—			205
General and administrative expenses	2,354			3,596			9,026			10,950
Total operating costs and expenses	43,673			50,436			205,963			134,008

Loss on disposal of other property and equipment	—			—			149			—
Gain on sale of oil and gas properties	—			—			(2,348		)	—

Operating loss	(10,030		)	(21,817		)	(124,255		)	(77,309		)

Other income (expense):
Currency transaction gain	1,542			3,282			5,027			14,610
Interest expense	(5,963		)	(5,038		)	(20,837		)	(16,417		)
Gain (loss) on fair value of derivative liability	(22		)	—			15			—
Total other expense, net	(4,443		)	(1,756		)	(15,795		)	(1,807		)

Loss before income taxes	(14,473		)	(23,573		)	(140,050		)	(79,116		)
Income tax expense	—			—			—			—
Net loss before non-controlling interest	(14,473		)	(23,573		)	(140,050		)	(79,116		)

Net loss attributable to non-controlling interest	403			102			908			662

Net loss attributable to Erin Energy Corporation	$	(14,070	)	$	(23,471	)	$	(139,142	)	$	(78,454	)

Net loss attributable to Erin Energy Corporation per common share:
Basic	$	(0.07	)	$	(0.11	)	$	(0.65	)	$	(0.37	)
Diluted	$	(0.07	)	$	(0.11	)	$	(0.65	)	$	(0.37	)
Weighted average common shares outstanding:
Basic	213,732			212,524			213,293			212,220
Diluted	213,732			212,524			213,293			212,220

See accompanying notes to unaudited consolidated financial statements.

ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CAPITAL DEFICIENCY

For the Nine Months Ended September 30, 2017

(Unaudited)

(In thousands)



	Common Stock		Additional Paid-in Capital		Accumulated Deficit			Treasury Stock			Non-controlling Interest			Total Equity
Balance at December 31, 2016	$	213	$	792,972	$	(1,018,292	)	$	(228	)	$	715		$	(224,620	)
Common stock issued	2		3,619		—			—			—			3,621
Stock-based compensation	—		1,619		—			—			—			1,619
Transfer to treasury arising from withholding taxes upon vesting of restricted stock and exercise of stock options	—		—		—			(708		)	—			(708		)
Non-controlling interest	—		—		—			—			864			864
Net loss	—		—		(139,142		)	—			(908		)	(140,050		)
Balance at September 30, 2017	$	215	$	798,210	$	(1,157,434	)	$	(936	)	$	671		$	(359,274	)

See accompanying notes to unaudited consolidated financial statements.

ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)



	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities
Net loss, including non-controlling interest	$	(140,050	)	$	(79,116	)

Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization	50,229			38,593
Accretion of asset retirement obligations	1,434			1,385
Impairment of oil and gas properties	78,711			—
Amortization of debt discount and debt issuance costs	3,602			2,640
Unrealized foreign currency transaction gain	(2,372		)	(10,442		)
Loss on disposal of other property and equipment	149			—
Gain on sale of oil and gas properties	(2,348		)	—
Gain on fair value of derivative liability	(15		)	—
Settlement of accounts payable and accrued expenses	(6,934		)	—
Share-based compensation	1,619			2,288
Change in operating assets and liabilities:
Decrease (increase) in accounts receivable	(12,144		)	730
Decrease in crude oil inventory	4,017			534
Increase in prepaids and other current assets	(1,466		)	(467		)
Increase in accounts payable and accrued liabilities	40,121			54,700
Net cash provided by operating activities	14,553			10,845

Cash flows from investing activities
Capital expenditures	(41,656		)	(16,475		)
Net cash used in investing activities	(41,656		)	(16,475		)

Cash flows from financing activities
Proceeds from exercise of stock options and warrants	—			364
Payments for treasury stock arising from withholding taxes upon restricted stock vesting and exercise of stock options	(708		)	(206		)
Proceeds from MCB Finance Facility	63,191			—
Repayments of MCB Finance Facility	(141		)	—
Repayments of term loan facility	(4,668		)	(6,492		)
Proceeds from short-term notes payable	—			504
Proceeds from short-term notes payable - related party	200			—
Repayment of short-term notes payable	—			(449		)
Proceeds from notes payable - related party, net	—			6,829
Debt issuance costs	(8,655		)	(1,040		)
Funds restricted for debt service	(11,161		)	—
Funds released from restricted cash	—			6,061
Net cash provided by financing activities	38,058			5,571

Net increase in cash and cash equivalents	10,955			(59		)
Cash and cash equivalents at beginning of period	7,177			8,363
Cash and cash equivalents at end of period	$	18,132		$	8,304

Supplemental disclosure of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	7,731		$	10,090
Supplemental disclosure of non-cash investing and financing activities:
Discount on notes payable pursuant to issuance of warrants	$	1,766		$	53
Reduction in oil and gas properties arising from settlements of accounts payable and accrued liabilities	$	11,328		$	9,540
Shares issued from settlement of accounts payable and accrued liabilities	$	3,527		$	—
Shares issued for services	$	94		$	—

See accompanying notes to unaudited consolidated financial statements.

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Company Description

Erin Energy Corporation (NYSE American: ERN; JSE: ERN) (the "Company") 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 five licenses across three countries covering an area of approximately 1.5 million acres (approximately 6,000 square kilometers). The Company owns producing properties and conducts exploration activities offshore Nigeria, and conducts exploration activities offshore Ghana and The Gambia.

The Company is headquartered in Houston, Texas and has offices in Lagos, Nigeria, Nairobi, Kenya, Banjul, The Gambia, and Accra, Ghana.

The Company’s operating subsidiaries include Erin Petroleum Nigeria Limited (“EPNL”), Erin Energy Kenya Limited ("EEKL"), 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 consolidated subsidiaries.

On February 16, 2017, Babatunde (Segun) Omidele informed the Company that he would resign from service as a member of the Board of Directors ("the Board") and as the Chief Executive Officer of the Company. The Board accepted his resignation effective as of February 22, 2017. The Board appointed Jean-Michel Malek, the Company’s Senior Vice President, General Counsel and Secretary, to serve as Interim Chief Executive Officer effective February 22, 2017 while the Board conducted a search for a permanent replacement for Mr. Omidele. Effective on May 18, 2017, the Board appointed Sakiru Adefemi (Femi) Ayoade as the Company’s Chief Executive Officer to replace the then Interim Chief Executive Officer, Jean-Michel Malek.

Changes in Control during 2017

The Company was advised by Oltasho Nigeria Limited (“Oltasho”) and Latmol Investment Limited (“Latmol”) that on (a) April 3, 2017, an aggregate of 116,108,833 shares of the Company’s common stock previously held by Allied Energy Plc. (“Allied”), were transferred to Oltasho; and (b) April 13, 2017, an aggregate of 1,515,927 shares of the Company’s common stock previously held by CAMAC Int’l (Nigeria) Ltd. (“CAMAC International”), were transferred to Latmol. Prior to April 2017, the shares of common stock previously held by Allied and CAMAC International were beneficially owned by Dr. Kase Lawal, the Company’s former Chairman and former Chief Executive Officer, due to his ownership of equity interests in such entities and voting and dispositive control over the securities held by such entities.

The shares transferred to Oltasho and Latmol represented approximately 54.6% of the Company’s outstanding voting shares (53.9% owned by Allied and 0.7% owned by CAMAC International) as of the dates of transfer and as such, represented a change in control of the Company. The Company has been advised that the shares held by Oltasho are beneficially owned by Alhaji Murhi Busari, its Chairman, and the shares held by Latmol are beneficially owned by Alhaji Murhi Busari, its Chairman.

On July 5, 2017, Oltasho and Latmol entered into a Voting Agreement with Dr. Lawal (the “Voting Agreement”) resulting in another change in control of the Company. Pursuant to the Voting Agreement, Oltasho and Latmol provided complete authority to Dr. Lawal to vote the 117,624,760 shares foreclosed upon (and any other securities of the Company obtained by Oltasho and/or Latmol in the future) at any and all meetings of stockholders of the Company and via any written consents. Those 117,624,760 shares represent approximately 54.6% of the Company’s common stock as of the parties’ entry into the Voting Agreement. The Voting Agreement has a term of approximately 10 years, through July 31, 2027, but can be terminated at any time with the mutual consent of the parties. In connection with their entry into the Voting Agreement, Oltasho and Latmol each provided Dr. Lawal an irrevocable voting proxy to vote the shares covered by the Voting Agreement. Additionally, during the term of such agreement, Oltasho and Latmol agreed not to transfer the shares covered by the Voting Agreement except pursuant to certain limited exceptions. According to the Voting Agreement, Oltasho and Latmol have no desire to control the Company and believe that voting control of the Company was best determined by Dr. Lawal, a United States resident, who has extensive knowledge of United States laws and the assets and operations of the Company, as Dr. Lawal was, until he retired in 2015, the Chairman and Chief Executive Officer of the Company. Due to the Voting Agreement, Dr. Lawal will continue to hold voting control over the Company.

The Company conducts certain business transactions with CAMAC Energy Holdings Limited (“CEHL”), and its affiliates, which include Allied, which are entities controlled by Dr. Lawal. These entities are deemed to be related parties for financial reporting purposes. See Note 8 - Related Party Transactions for further information.

2. Basis of Presentation and Recently Issued Accounting Standards

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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, 2016, filed with the SEC on March 16, 2017.

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, calculations related to derivative liabilities, 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.

Restricted Cash

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

Restricted cash as of September 30, 2017 totaling $13.8 million consists of $2.6 million held in a debt service reserve account to secure certain interest and principal repayments pursuant to the Term Loan Facility in Nigeria and $11.2 million held in a debt service reserve account as required under the MCB Finance Facility (see Note 7 - Debt for further information and definitions of the Term Loan Facility and MCB Finance Facility). Restricted cash as of December 31, 2016 consists of $2.6 million held in a debt service reserve account to secure certain interest and principal repayments pursuant to the Term Loan Facility in Nigeria.

Successful Efforts Method of Accounting for Oil and Gas Activities

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

Capitalized Interest

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

During the nine months ended September 30, 2017 and 2016, the Company capitalized $2.2 million and nil, respectively, of interest

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

costs as additions to property, plant and equipment.

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, 2017, 204,549 shares were withheld for payroll taxes at a total cost of $0.7 million. During the nine months ended September 30, 2016, 90,347 shares were withheld for payroll taxes at a total cost of $0.2 million.

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, 2017.



	Total Number of Shares Purchased (1)	Average Price Paid Per Share
January 1 - January 31, 2017	12,650	$	3.55
February 1 - February 28, 2017	158,264	3.82
May 1 - May 31, 2017	33,635	1.75
Total	204,549	$	3.46



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

Net 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, as well as the conversions of the 2011 Promissory Note, the 2014 Convertible Subordinated Note and the 2016 Promissory Note (collectively, the "Convertible Notes", each defined and described in greater detail under Note 7 - Debt), 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 Notes that were excluded from dilutive shares outstanding during the three and nine months ended September 30, 2017 and 2016, respectively, 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)	2017	2016	2017	2016
Stock options	98	206	140	249
Stock warrants	4	7	7	2
Unvested restricted stock awards	1,408	2,128	1,759	1,889
	1,510	2,341	1,906	2,140

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 9 - Commitments and Contingencies for further information.

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

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.

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


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


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


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

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

Fair Value on a Recurring Basis

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

As discussed under Note 7 - Debt, the Company recognized a derivative liability relating to the portion of the amount drawn from the MCB Financing Facility as of September 30, 2017 in which issuance of stock warrants is expected on the day the Company receives funds under the MCB Finance Facility. The Company utilized a combination of a lattice-binomial option-pricing model and the Black-Scholes valuation model to determine the estimated fair value of this derivative liability.

The following table sets forth the Company’s oil and gas properties and derivative liability that is accounted for at fair value using Level 3 assumptions on a recurring basis as of September 30, 2017 and December 31, 2016:



	Level 3
(in thousands)	September 30, 2017		December 31, 2016
Liabilities:
Derivative liability	$	1,751	$	—

The fair value of the derivative liability is estimated using a combination of a lattice-binomial option-pricing model and the Black-Scholes valuation model with the following assumptions as of September 30, 2017:

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS



	September 30, 2017
Estimated market value of common stock on measurement date	$	2.85
Estimated exercise price	$	2.85
Risk-free interest rate (1)	1.62		%
Expected warrant term (years)	3
Expected volatilities (2)	10.0% - 38.9%
Expected annual dividend yield	—



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

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



	Three Months Ended		Nine Months Ended
(in thousands)	September 30, 2017		September 30, 2017
Beginning balance	$	656	$	—
Loss (gain) on fair value of derivative liability	22		(15		)
Additions	1,073		1,977
Revisions	—		(211		)
Transfers	—		—
Ending balance	$	1,751	$	1,751

Change in unrealized loss (gain) included in earnings relating to derivatives still held as of September 30, 2017	$	22	$	(15	)

Fair Value of Financial Instruments

The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, restricted cash, accounts receivable, inventory, deposits, accounts payable and accrued liabilities, and debts at floating interest rates, approximate their fair values at September 30, 2017 and December 31, 2016, respectively, principally due to the short-term nature, maturities or nature of interest rates of the above listed items.

Reclassification

Certain amounts in prior periods have been reclassified to conform with current period presentation.

Recently Issued Accounting Standards

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

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). This ASU clarifies the definition of a business with the objective of adding guidance to assist entities with

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

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

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

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

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

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

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

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Improvements to Accounting for Hedging Activities. ASU No. 2017-12 amends and better aligns an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. To meet that objective, the amendments expand and refine hedge accounting for both non-financial and financial risk components and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. ASU No. 2017-12 is effective for interim and annual periods beginning after December

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

15, 2018, and the Company will adopt this standards update, as required, beginning with the first quarter of 2019. The adoption of this standard update is not expected to have a material impact on the Company’s consolidated financial statements.

3. Liquidity Matters and Going Concern

The Company incurred losses from operations for the three and nine months ended September 30, 2017. As of September 30, 2017, the Company's total current liabilities of $366.2 million exceeded its total current assets of $55.4 million, resulting in a working capital deficit of $310.8 million. As a result of the current low commodity prices, the Company has not been able to generate sufficient cash from operations to satisfy certain obligations as they became due.

Well Oyo-7 is currently shut-in as a result of an emergency shut-in of the Oyo field production that occurred in early July 2016. This has resulted in a loss of approximately 1,400 barrels of oil per day (BOPD). The Company is currently working on relocating an existing gaslift line to well Oyo-7 to enable continuous gaslift operation to assist in restoring lost production volumes. For cost effectiveness, the relocation of the gaslift line to well Oyo-7 is now planned to be combined with the Oyo-9 subsea equipment installation scheduled for the second half of 2018. During an approximately two (2) week period starting from late June 2017 to early July 2017, the owners of the floating, production, storage, and offloading vessel (“FPSO”) Armada Perdana suspended its operations due to an impasse in contract negotiations that led to a temporary shut-in of the Oyo-8 well during this period. The FPSO operation was fully restored and the production from the Oyo-8 well was re-established on July 6, 2017. Contract negotiations have resumed.

The Company is currently pursuing a number of actions, including (i) obtaining additional funds through public or private financing sources, (ii) restructuring existing debts from lenders, (iii) obtaining forbearance of debt from trade creditors, (iv) reducing ongoing operating costs, (v) minimizing projected capital costs for the remaining 2017 exploration and development campaign, (vi) farming-out a portion of its rights to certain of its oil and gas properties and (vii) exploring potential business combination transactions. There can be no assurances that sufficient liquidity can be raised from one or more of these actions or that these actions can be consummated within the period needed to meet certain obligations.

The Company's consolidated financial statements have been prepared under the assumption that it will continue as a going concern, which assumes the continuity of operations, the realization of assets and the satisfaction of liabilities as they come due in the normal course of business. Although the Company believes that it will be able to generate sufficient liquidity from the measures described above, its current circumstances raise substantial doubt about its ability to continue to operate as a going concern. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

4. Property, Plant and Equipment

Property, plant and equipment were comprised of the following:



(In thousands)	September 30, 2017			December 31, 2016
Wells and production facilities	$	308,451		$	318,739
Proved properties	386,196			386,196
Work in progress and exploration inventory	81,951			34,712
Oilfield assets	776,598			739,647
Accumulated depletion	(609,204		)	(483,754		)
Oilfield assets, net	167,394			255,893
Unevaluated leaseholds	6,200			9,820
Oil and gas properties, net	173,594			265,713

Other property and equipment	2,895			3,040
Accumulated depreciation	(2,470		)	(2,324		)
Other property and equipment, net	425			716

Total property, plant and equipment, net	$	174,019		$	266,429

All of the Company’s oilfield assets are located offshore Nigeria in the Oil Mining Leases 120 and 121 (the "OMLs"). “Work-in-progress and exploration inventory” includes warehouse inventory items purchased as part of the redevelopment plan of the Oyo field.

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

The Gambia Sale Agreement

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

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

Impairment of Oil and Gas Properties

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

5. Accounts Payable and Accrued Liabilities

The table below sets forth a summary of the Company’s accounts payable and accrued liabilities at September 30, 2017 and December 31, 2016:



(In thousands)	September 30, 2017		December 31, 2016
Accounts payable - vendors	$	179,467	$	173,306
Amounts due to government entities	77,139		66,573
Accrued payroll and benefits	1,164		3,074
Accrued interest	3,972		1,204
Other liabilities	—		806
	$	261,742	$	244,963

6. Asset Retirement Obligations

The Company’s asset retirement obligations primarily represent the estimated fair value of the amounts that will be incurred to plug, abandon and remediate 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. The following summarizes changes in the Company’s asset retirement obligations during the nine months ended September 30, 2017 (in thousands):

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS



Balance at January 1, 2017	$	22,476
Accretion expense	1,434
Balance at September 30, 2017	$	23,910

7. Debt

Short-Term Debt:

Short-Term Borrowing - Glencore Advance

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

In September 2017, the Company received $23.5 million as an advance (the “September Advance”) under an exclusive off-take contract with Glencore (the “Off-take Contract”). Interest accrued on the September Advance at the rate of LIBOR plus 6.5%. Repayment of the September Advance was made from the September 2017 crude oil lifting.

Short-Term Debt - Related Party

On September 19, 2017, the Company, through its wholly-owned subsidiary EPNL, borrowed $0.2 million under a short-term loan agreement (the "2017 Short-Term Note") entered into with CAMAC Nigeria Limited, an affiliated company, at the flat interest rate of 5% and matures November 30, 2017.

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") for a five-year senior secured term loan providing initial borrowing capacity of up to $100.0 million. Of the total commitment provided, 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 LIBOR plus 9.0%. 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, subject to the provisions under the Override Deed (defined below). 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 moratorium on principal payments until June 2017 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, 2017, $1.7 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

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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, 2017, the Company made payments of $0.4 million and $4.2 million for the principal repayment of the Naira portion of the loan and for the U.S. dollar principal, respectively.

As of September 30, 2017, the Company recognized an unrealized foreign currency gain of $5.0 million on the Naira portion of the loan, reducing the balance under the Term Loan Facility to $82.3 million, net of debt discount. Of this amount, $59.7 million was classified as long-term and $22.6 million as short-term. Accrued interest for the Term Loan Facility was $2.1 million as of September 30, 2017.

MCB Finance Facility and Related Agreements

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

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

The MCB Finance Facility is supported by the SBSA guarantee as facilitated by PIC, the assignment of the Off-take Contract and the assignment by way of security of certain accounts, including a debt service reserve account, as set forth in the MCB Finance Facility. EPNL was required to deposit $10.0 million (see Note 2 – Basis of Presentation and Recently Issued Accounting Standards

- Restricted Cash) at the closing of the MCB Finance Facility into the debt service reserve account with MCB and maintain that balance for so long as borrowings are outstanding under the MCB Finance Facility. The aforementioned guarantee and security agreements were entered into by the parties thereto before the initial drawdown on the MCB Finance Facility.

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

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

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

The Company did not make the principal payment due and a portion of interest due on September 30, 2017. Also, on June 27, 2017, a vendor filed a suit against a wholly-owned subsidiary of the Company seeking an amount in excess of $10.0 million (see Note 9 - Commitments and Contingencies for further information). These constitute events of default under the MCB Finance Facility. In October 2017, the Company obtained a waiver of default on these events from MCB.

The Company made its initial drawdown under the MCB Finance Facility in March 2017 (the "March 2017 drawdown"). As part of the March 2017 drawdown, the Company incurred debt issuance costs amounting to $8.7 million. As of September 30, 2017,

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

$7.5 million of the debt issuance costs remained unamortized, which is shown as a discount to long-term debt on the consolidated balance sheet. As of September 30, 2017, the amount drawn under the MBC Finance Facility was $63.2 million. Accrued interest and unused commitment fees under the MCB Finance Facility was $1.9 million as of September 30, 2017.

During the nine months ended September 30, 2017, the Company paid $0.1 million for the principal repayment of the MCB Finance Facility.

Under the MCB Finance Facility, the Company is required to maintain specified financial ratios. Maintenance of these financial ratios (the "cover ratios"), including a debt service cover ratio and a life cover ratio, commenced during the quarter after the initial drawdown. As of September 30, 2017, the Company is in compliance with the cover ratios.

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

In consideration for this undertaking, the Company agreed to pay PIC an upfront fee equal to 250 basis points on the guarantee amount and issue to PIC warrants to purchase a number of shares of the Company’s common stock in an amount equal to the guarantee amount multiplied by 20% divided by the closing market price of the Company’s common stock on the day that EPNL receives the funds available under the MCB Finance Facility (the "warrants issuance date), with an exercise price equal to such closing market price. The Company recognized a derivative liability for the warrants that are expected to be issued for the portion of the amount drawn under the MCB Finance Facility at September 30, 2017. See Note 2 – Basis of Presentation and Recently Issued Accounting Standards - Fair Value Measurements for further information. The Company also has agreed to indemnify PIC from and against certain claims and losses. The amount of any and all indemnifiable losses suffered by PIC agreed or otherwise required to be paid by the Company will be paid in cash or, at the option of PIC, may be paid in newly issued shares of the Company’s common stock. In March 2017, the Company paid $2.5 million to PIC in fees under the Financing Support Agreement which is recorded as debt issuance costs as discussed above and is being amortized to interest expense over the life of the MCB Financing Facility.

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

Long-Term Debt Maturities

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



Scheduled payments by year	Principal
2017 (remainder)	$	24,931
2018	62,054
2019	21,277
2020	26,597
2021 and thereafter	12,198
Total principal payments	147,057
Less: Unamortized debt issuance costs	(9,191		)
Total Long term debt, net	$	137,866

Long-Term Debt – Related Party:

As of September 30, 2017, the Company’s long-term related party debt was $129.8 million, consisting of $24.9 million owed under a 2011 Promissory Note, $50.0 million owed under a 2014 Convertible Subordinated Note, $48.5 million, net of discount,

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

owed under a 2015 Convertible Note, and $6.4 million owed under a 2016 Promissory Note.

Allied, a related party, was the holder of each of the 2011 Promissory Note, the 2014 Convertible Subordinated Note, and the 2015 Convertible Note (collectively the "Related Party Notes"). During the nine months ended September 30, 2017, Oltasho became the holder of each of the Related Party Notes. Please also see Note 1 - Company Description for changes in control in the Company which occurred during 2017.

Each of the Related Party Notes contains certain default and cross-default provisions, including failure to pay interest and principal amounts when due and default under other indebtedness. As of September 30, 2017, the Company was not in compliance with certain default provisions of the Related Party Notes with respect to the payment of quarterly interest. Further, the risk of cross-default exists for each of the Related Party Notes if the holder of the Term Loan Facility exercises its right to terminate the Term Loan Facility and accelerate its maturity. In July 2017, Oltasho agreed to waive through their respective maturity dates its rights under all default provisions of each of the Related Party Notes.

2011 Promissory Note

EPNL, the Company's wholly owned subsidiary, has a $25.0 million borrowing facility under a promissory note (the "2011 Promissory Note"). Interest accrues on the outstanding principal under the 2011 Promissory Note at a rate of the 30-day LIBOR plus 2% per annum, payable quarterly. In March 2017, the 2011 Promissory Note became convertible, at the sole option of the holder, into shares of the Company’s common stock at a conversion price of $3.415 per share. In July 2017, the 2011 Promissory Note was amended to extend the maturity date to December 2019. The entire $25.0 million facility amount can be utilized for general corporate purposes. The stock of the Company’s subsidiary that holds the exploration licenses in The Gambia and Kenya were pledged as collateral to secure the 2011 Promissory Note, pursuant to an Equitable Share Mortgage arrangement. As of September 30, 2017, the outstanding principal and accrued interest under the 2011 Promissory Note were $24.9 million and $2.2 million, respectively.

As referred to above, this Note was transferred to Oltasho during the nine months ended September 30, 2017.

2014 Convertible Subordinated Note

As partial consideration in connection with the February 2014 acquisition of interests in Oil Mining Leases ("OMLs") located offshore Nigeria from Allied, the Company issued 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 acquisition date.

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, 2017, the Company owed $10.5 million in accrued 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. The holder may assign all or any part of its rights and obligations under the 2014 Convertible Subordinated Note to any person upon written notice to the Company. In July 2017, the 2014 Convertible Subordinated Note was amended to extend the maturity date to December 2019. As of September 30, 2017, the outstanding principal under the 2014 Convertible Subordinated Note was $50.0 million.

As referred to above, this Note was transferred to Oltasho during the nine months ended September 30, 2017.

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

2015 Convertible Note

In March 2015, the Company entered into a 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 July 2017, the maturity date of the 2015 Convertible Note was extended to December 2019. Interest accrues at the rate of LIBOR plus 5%, and is payable quarterly.

The 2015 Convertible Note is convertible into shares of the Company’s common stock upon the occurrence and continuation of an event of default, at the sole option of the holder. The number of shares issuable upon conversion is equal to the sum of the principal amount and the accrued and unpaid interest divided by the conversion price, defined as the volume weighted average of the closing sales prices on the NYSE American for a share of common stock for the five complete trading days immediately preceding the conversion date.

As of September 30, 2017, 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, 2017, the debt discount has been fully amortized.

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, 2017, the outstanding balance of the 2015 Convertible Note, net of discount, was $48.5 million. Accrued interest on the 2015 Convertible Note was $7.3 million as of September 30, 2017.

As referred to above, this Note was transferred to Oltasho during the nine months ended September 30, 2017.

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 then majority shareholder, which accrued interest at a rate of the 30-day LIBOR plus 7% per annum.

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

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

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

As of September 30, 2017, the outstanding balance under the 2016 Promissory Note was $6.4 million. Accrued interest on the 2016 Promissory Note was $0.8 million as of September 30, 2017. In March 2017, the 2016 Promissory Note became convertible, at the sole option of the holder, into shares of the Company’s common stock at a conversion price of $3.415 per share. In July 2017, the maturity date of the 2016 Promissory Note was extended to April 2023.

8. Related Party Transactions

Assets and Liabilities

The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates. Effective April 3, 2017, Oltasho became a majority shareholder of the Company and the holder of the Related Party Notes. The following table sets forth the related party assets and liabilities as of September 30, 2017 and December 31, 2016:

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS



(In thousands)	September 30, 2017		December 31, 2016
Accounts receivable	$	2,821	$	1,956
Accounts payable and accrued liabilities	$	33,388	$	29,513
Short-term note payable - related party	$	200	$	—
Long-term notes payable - related party	$	129,821	$	129,796

As of September 30, 2017 and December 31, 2016, the related party receivable balances of $2.8 million and $2.0 million, respectively, were for advance payments made for certain transactions on behalf of affiliates.

As of September 30, 2017 and December 31, 2016, the Company owed $33.4 million and $29.5 million, respectively, to affiliates primarily for logistical and support services in relation to the Company's oilfield operations in Nigeria, as well as accrued interest on the various related party notes payable. As of September 30, 2017 and December 31, 2016, accrued and unpaid interest on the various related party notes payable was $21.1 million and $15.2 million, respectively.

As of September 30, 2017, the Company had a related party short term note payable balance of $0.2 million under a short term loan agreement entered into with an affiliate.

As of September 30, 2017, the Company had a combined note payable balance of $129.8 million owed to Oltasho and an affiliate, consisting of a $50.0 million 2014 Convertible Subordinated Note, $24.9 million in borrowings under the 2011 Promissory Note, a $48.5 million borrowing under the 2015 Convertible Note, net of discount, and $6.4 million under the 2016 Promissory Note. As of December 31, 2016, the Company had a combined note payable balance of $129.8 million owed to affiliates, consisting of the $50.0 million 2014 Convertible Subordinated Note, $24.9 million in borrowings under the 2011 Promissory Note, $48.5 million borrowing under the 2015 Convertible Note, net of discount, and $6.4 million under the 2016 Promissory Note. See Note 7 – Debt for further information relating to the notes payable transactions.

Results from Operations

The table below sets forth a summary of transactions included in the Company's results of operations that were incurred with affiliates during the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands)	2017		2016		2017		2016
Total operating expenses	$	2,333	$	4,825	$	7,058	$	8,844
Interest expense	$	2,084	$	1,525	$	6,031	$	4,987

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, 2017 and 2016, the Company incurred operating costs amounting to approximately $2.3 million and $4.8 million, respectively, and during the nine months ended September 30, 2017 and 2016, the Company incurred operating costs amounting to approximately $7.1 million and $8.8 million, respectively.

During the three months ended September 30, 2017 and 2016, the Company incurred interest expense, excluding debt discount amortization, totaling approximately $2.1 million and $1.5 million, respectively, in relation to related party notes payable. During the nine months ended September 30, 2017 and 2016, the Company incurred interest expense totaling approximately $6.0 million and $5.0 million, respectively.

9. Commitments and Contingencies

Commitments

In February 2014, a long-term contract was signed for the floating, production, storage, and offloading vessel (“FPSO”) Armada Perdana, which is the vessel currently connected to the Company’s 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.

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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. Among the Kenya PSCs in which the Company has remaining obligations, production sharing contracts related to offshore blocks L27 and L28 expired in February 2017, with the Company having no intention to renew or extend these leases. In June 2017, the Company farmed out 80% of its interest and operatorship of its offshore A2 and A5 blocks under the Gambia Licenses and will retain a 20% working interest in both blocks. See Note 4 – Property, Plant and Equipment for further information relating to the Sale Agreement.

In March 2017, the Company entered into a drilling services contract with Pacific Drilling using the Pacific Bora drilling rig. The Company used this rig to drill well Oyo-9 on the Oyo field in the deepwater offshore Nigeria. Under the contract, the Company has the option to drill up to two additional wells. The option to extend the contract, if exercised, would be used to drill two of its offshore Nigeria exploration prospects in the prolific Miocene geological zone. The Pacific Bora is a highly efficient sixth generation double-hulled drillship currently in Nigeria and was mobilized to the Oyo field and on site August 1, 2017. The contract provides for a base operating rate of $195,000 per day. The rig can be used for both drilling and well completion. In October 2017, the Company successfully completed the drilling phase of the Oyo-9 well. However, due to chronic delays in the release of the remaining funds and improper interference by the guarantor of the MCB Finance Facility, the Company temporarily suspended the completion and hookup of the Oyo-9 well.

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, 2017, and through the filing date of this report, the Company does not believe the ultimate resolution of such actions or potential actions of which the Company is currently aware will have a material effect on its consolidated financial position or results of operations.

On January 22, 2016, a request for arbitration was filed with the London Court of International Arbitration by Transocean Offshore Gulf of Guinea VII Limited and Indigo Drilling Limited, as Claimants, against the Company and its Nigerian subsidiary, EPNL, as Respondents (the “Arbitration”). The Arbitration was in relation to a drilling contract entered into by the Claimants and EPNL, and a parent company guarantee provided by the Company in relation thereto. On July 19, 2017, the London Court of International Arbitration issued a “First Partial Final Award by Consent” (the “Consent Award”) in a proceeding between the Claimants and Respondents to resolve claims by the Claimants arising out of a contract for oilfield services done in relation to the Company's ordinary course of business. Pursuant to the Consent Award, the Respondents are liable to pay Claimants approximately $14.0 million and 11.8 million Nigerian Naira (NGN), equal to approximately $33,000 U.S. dollars.

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 interests in Oil Mining Leases located offshore Nigeria from Allied pursuant to the Transfer Agreement and (2) issued shares to 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 then majority shareholder, CEHL. The complaint also purports to assert a direct breach of fiduciary duty claim on behalf of the putative class against the seven individuals who served on 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 former Chief Executive Officer of the Company. The plaintiff is seeking, on behalf of the Company and the putative class, an undisclosed amount of compensatory damages. The Company is named solely as a nominal defendant against whom the plaintiff seeks no recovery. On March 3, 2016, all of the defendants, including the Company, filed motions to dismiss the complaint, which motions were heard on January 18, 2017. The plaintiffs filed a motion to supplement their petition to include a claim relating to what Allied paid or did not pay Nigerian Agip Exploration Limited for the asset. On May 23, 2017, the court granted plaintiffs’ motion to supplement petition. On June 23, 2017, the defendants filed short motions to dismiss the supplemental allegations. The plaintiffs filed their response on July 12, 2017 and the defendants filed a reply on July 21, 2017.

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

On July 13, 2017, Multiplan Nigeria Limited ("Multiplan") entered into a settlement agreement and release (the “Multiplan Settlement Agreement”) with EPNL for $3.0 million, to resolve claims by Multiplan for work done in relation to the Company's ordinary course of business. As a result thereof, the Company decreased its accounts payable and accrued liabilities by $0.2 million with a corresponding decrease to its oil and gas properties as of September 30, 2017. As part of the Multiplan Settlement Agreement, the Company paid $1.0 million to Multiplan in July 2017, and all remaining amounts claimed by Mulitiplan are due to be discharged by EPNL prior to the end of 2017.

On July 14, 2017, Aker Solutions Inc. ("Aker") entered into a settlement agreement and release (the “Aker Settlement Agreement”) with EPNL for $2.5 million, to resolve claims by Aker for work done in relation to the Company's ordinary course of business. As a result thereof, the Company decreased its accounts payable and accrued liabilities by $10.2 million with a corresponding decrease to its oil and gas properties as of September 30, 2017. As part of the Aker Settlement Agreement, EPNL paid $1.0 million to Aker in July 2017, and all remaining amounts claimed by Aker are due to be discharged by EPNL prior to the end of 2017.

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

Unrecognized Loss Contingency

As of September 30, 2017, the Company has not accrued penalty and interest related to certain outstanding transactional tax obligations in Nigeria, including withholding taxes, value-added taxes, Nigerian Oil and Gas Industry Content Development Act (NCD) tax, Cabotage taxes, and Niger Delta Development Corporation taxes (NDDC). As of the date of this report, the Company believes that, based on its experience with local practices in Nigeria, the likelihood of being assessed penalty and interest is reasonably possible, with an estimated liability up to $22.1 million.

Contingency under the Allied Transfer Agreement

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

Contingency under the 2015 Convertible Note

As part of the condition to the extension of the maturity date of the 2015 Convertible Note, which extension was entered into in March 2016, the Company is required to (i) pay to Allied an amount equal to ten percent (10%) towards existing liabilities 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%) towards existing liabilities of any successful equity fundraising event completed during the remaining term of the 2015 Convertible Note. Despite the 2015 Convertible Note being transferred to Oltasho (See Note 7 - Debt) the amounts due under the provision of this extension remain due to Allied. The execution of the MCB Financing Facility in February 2017 triggered item (i) above of which a payment is due to Allied under these provisions.

10. Stock-Based Compensation

Stock Options

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The table below sets forth a summary of stock option activity for the nine months ended September 30, 2017.



	Shares Underlying Options (In Thousands)		Weighted-Average Exercise Price	Weighted-Average Remaining Contractual Term (Years)
Outstanding at December 31, 2016	1,147		$2.54	2.0
Granted	745		$2.26	1.0
Exercised	(511	)	$1.81	—
Forfeited	(639	)	$2.69	—
Expired	(145	)	$3.55	—
Outstanding at September 30, 2017	597		$2.40	1.8
Expected to vest	145		$1.88	4.7
Exercisable at September 30, 2017	452		$2.57	0.9

During the nine months ended September 30, 2017, the Company issued 183,160 shares of common stock as a result of the exercise of stock options, all of which were issued as a result of the cashless exercise of options to purchase 510,555 shares of common stock. Also, during the nine months ended September 30, 2017, options to purchase 638,891 shares of common stock were forfeited and options to purchase 145,000 shares of common stock expired.

The estimated fair value of stock options granted during the nine months ended September 30, 2017 was approximately $0.9 million, and was computed using the Black-Scholes option pricing model.

Stock Warrants

The table below sets forth a summary of stock warrant activity for the nine months ended September 30, 2017.



	Shares Underlying Warrants (In Thousands)	Weighted-Average Exercise Price	Weighted-Average Remaining Contractual Term (Years)
Outstanding at December 31, 2016	2,983	$3.59	3.2
Granted	—	$—	—
Exercised	—	$—	—
Forfeited	—	$—	—
Expired	—	$—	—
Outstanding at September 30, 2017	2,983	$3.59	2.5
Expected to vest	—	$—	—
Exercisable at September 30, 2017	2,983	$3.59	2.5

Restricted Stock Awards

The table below sets forth a summary of restricted stock awards (“RSAs”) activity for the nine months ended September 30, 2017.



	Shares (In Thousands)		Weighted-Average Grant Date Price Per Share
Non-vested at December 31, 2016	2,072		$	2.25
Granted	1,122		$	3.00
Vested	(1,038	)	$	2.39
Forfeited	(746	)	$	2.98
Non-vested as of September 30, 2017	1,410		$	2.36

During the nine months ended September 30, 2017, the Company granted officers, directors, and employees a total of approximately 1.1 million shares of restricted common stock, including 0.2 million performance-based restricted stock awards ("PBRSA"), with

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

vesting periods varying from immediate vesting to 36 months. During the same period, 0.7 million shares of restricted common stock were forfeited.

The fair value of RSAs granted during the nine months ended September 30, 2017 was approximately $3.4 million, which is being amortized to expense over the respective vesting periods of each grant.

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 $0.1 million over three years.

Issuance of Common Shares

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

Also during September 2017, the Company issued 1,282,355 shares of restricted common stock to a vendor under the September 2017 Settlement Agreement with a fair value of $3.5 million (See Note 9 - Commitments and Contingencies).

11. Segment Information

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

Segment activity for the three and nine months ended September 30, 2017 and 2016 are as follows:



(In thousands)	Nigeria			Kenya			The Gambia			Ghana			Corporate and Other			Total
Three months ended September 30,
2017
Revenues	$	33,643		$	—		$	—		$	—		$	—		$	33,643
Operating loss	$	(6,861	)	$	(109	)	$	(207	)	$	(807	)	$	(2,046	)	$	(10,030	)
2016
Revenues	$	28,619		$	—		$	—		$	—		$	—		$	28,619
Operating loss	$	(17,323	)	$	(434	)	$	(728	)	$	(210	)	$	(3,122	)	$	(21,817	)

Nine months ended September 30,
2017
Revenues	$	79,509		$	—		$	—		$	—		$	—		$	79,509
Operating loss	$	(114,576	)	$	(1,404	)	$	1,591		$	(1,820	)	$	(8,046	)	$	(124,255	)
2016
Revenues	$	56,699		$	—		$	—		$	—		$	—		$	56,699
Operating loss	$	(63,777	)	$	(1,485	)	$	(1,251	)	$	(1,328	)	$	(9,468	)	$	(77,309	)

Total assets by segment as of September 30, 2017 and December 31, 2016, are as follows:



(In thousands)	Nigeria		Kenya		The Gambia		Ghana		Corporate and Other		Total
Total Assets
As of September 30, 2017	$	218,827	$	61	$	4,069	$	5,230	$	1,304	$	229,491
As of December 31, 2016	$	281,050	$	698	$	3,034	$	3,648	$	771	$	289,201

12. Subsequent Events

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

On October 27, 2017 the Company, through its wholly-owned subsidiary, EPNL, entered into a loan agreement, (the "2017 Loan Agreement"), with James Street Capital Partners Limited, ("JSC") as the lender, allowing the Company to borrow up to $20.0 million to be used for capital expenditures in relation to the drilling of an exploration well in the Miocene formation of the OMLs.

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

In consideration for this undertaking, the Company issued a stock purchase warrant to JSC to purchase up to 7,017,544 shares of the Company's common stock at $2.85 per share. The warrants include a repurchase right such that upon repayment in full of the amounts borrowed under the 2017 Loan Agreement the Company may repurchase the warrants at their fair market value (as defined in the warrant agreement). The warrants expire on September 30, 2020 and include cashless exercise rights in the event the shares of common stock issuable upon exercise thereof are not registered under the Securities Act of 1933, as amended.

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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


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


•	our current and future indebtedness;


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


•	our ability to develop oil and gas reserves;


•	competition from other companies in the energy market;


•	political instability and foreign government regulations over international operations;


•	our lack of diversification of production and reserves;


•	compliance and enforcement of 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, 2016, 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. You should consider carefully the statements under the “Risk Factors” section of this report and other sections of this report which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, and the following factors:


•	the possibility that our future acquisitions may involve unexpected costs;


•	the volatility in commodity prices for oil and gas;


•	the accuracy of internally estimated proved reserves;


•	the presence or recoverability of estimated oil and gas reserves;


•	the ability to replace oil and gas reserves;


•	the availability and costs of drilling rigs and other oilfield services;


•	risks inherent in natural gas and oil drilling and production activities, including risks of fire, explosion, blowouts, pipe failure, casing collapse, unusual or unexpected formation pressures, environmental hazards, and other operating and production risks;


•	delays in receipt of drilling permits;


•	risks relating to the availability of capital to fund drilling operations that can be adversely affected by adverse drilling results, production declines and declines in natural gas and oil prices;


•	risks relating to unexpected adverse developments in the status of properties;


•	risks relating to the absence or delay in receipt of government approvals or other third party consents;


•	environmental risks;


•	exploration and development risks;


•	competition;


•	the inability to realize expected value from acquisitions;


•	the availability and cost of alternative fuel sources;


•	our ability to maintain the listing of our common stock on the NYSE American;


•	our ability to meet the covenants in our loan agreements and the consequences of not meeting such covenants;


•	the ability of our management team to execute its plans to meet its goals; and


•	other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations and pricing.

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.

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 period ended June 30, 2017 and March 31, 2017, and in our Annual Report on Form 10-K for the year ended December 31, 2016.

Review of Information and Definitions

This information should be read in conjunction with the interim unaudited financial statements and the notes thereto included in this Quarterly Report on Form 10-Q, and the consolidated financial statements and notes thereto and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2016.

Certain capitalized terms used below and otherwise defined below, have the meanings given to such terms in the footnotes to our consolidated financial statements included above under “Part I - Financial Information” - “Item 1. Financial Statements”.

Certain abbreviations and oil and gas industry terms used throughout this Quarterly Report are described and defined in greater detail under “Glossary of Selected Oil and Gas Terms” beginning on page 3 of our Annual Report on Form 10-K for the year ended December 31, 2016, as filed with the Securities and Exchange Commission on March 16, 2017.

Unless the context requires otherwise, references to the “Company,” “we,” “us,” “our,” “Erin”, “Erin Energy” and “Erin Energy Corporation” refer specifically to Erin Energy Corporation and its consolidated subsidiaries.

In addition, unless the context otherwise requires and for the purposes of this report only:


•	“Bbl” means a barrel of oil;


•	“BOPD” refers to barrels of oil per day;


•	“Exchange Act” refers to the Securities Exchange Act of 1934, as amended;


•	“SEC” or the “Commission” refers to the United States Securities and Exchange Commission; and


•	“Securities Act” refers to the Securities Act of 1933, as amended.

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 American and on the Johannesburg Stock Exchange ("JSE") under the symbol “ERN”.

Our asset portfolio consists of five licenses across three countries covering an area of approximately 1.5 million acres (approximately 6,000 square kilometers). We own producing properties offshore Nigeria and conduct exploration activities as an operator offshore Nigeria and conduct exploration activities as an operator offshore Ghana, and as a non-operator offshore The Gambia.

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

On February 16, 2017, Babatunde (Segun) Omidele informed the Company that he would resign from service as a member of the Board and as the Chief Executive Officer of the Company. The Board accepted his resignation effective as of February 22, 2017. The Board appointed Jean-Michel Malek, the Company’s Senior Vice President, General Counsel and Secretary, to serve as Interim Chief Executive Officer effective February 22, 2017 while the Board conducted a search for a permanent replacement for Mr. Omidele. Effective on May 18, 2017, the Board appointed Sakiru Adefemi (Femi) Ayoade as the Company’s Chief Executive Officer to replace the then Interim Chief Executive Officer, Jean-Michel Malek.

Changes in Control during 2017

We were was advised by Oltasho Nigeria Limited (“Oltasho”) and Latmol Investment Limited (“Latmol”) that on (a) April 3, 2017, an aggregate of 116,108,833 shares of the Company’s common stock previously held by Allied Energy Plc. (“Allied”), were transferred to Oltasho; and (b) April 13, 2017, an aggregate of 1,515,927 shares of the Company’s common stock previously held by CAMAC Int’l (Nigeria) Ltd. (“CAMAC International”), were transferred to Latmol. Prior to April 2017, the shares of common stock previously held by Allied and CAMAC International were beneficially owned by Dr. Kase Lawal, our former Chairman and former Chief Executive Officer, due to his ownership of equity interests in such entities and voting and dispositive control over the securities held by such entities.

The shares foreclosed upon represented approximately 54.6% of our outstanding voting shares (53.9% owned by Allied and 0.7% owned by CAMAC International) as of the dates of transfer and as such, represented a change in control of the Company. The Company has been advised that the shares held by Oltasho are beneficially owned by Alhaji Murhi Busari, its Chairman, and the shares held by Latmol are beneficially owned by Alhaji Murhi Busari, its Chairman.

We conduct certain business transactions with CAMAC Energy Holdings Limited (“CEHL”), and its affiliates, which include Allied, which are entities controlled by Dr. Lawal. These entities are deemed to be related parties for financial reporting purposes. See Note 8 - Related Party Transactions to the Notes to Unaudited Consolidated Financial Statements for further information.

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 July 2016, the Oyo-7 well 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 relocating an existing gaslift line to well Oyo-7 to enable continuous gaslift operation. For cost effectiveness, the relocation of the gaslift line to well Oyo-7 is now planned to be combined with the Oyo-9 subsea equipment installation scheduled for the second half of 2018.

Daily production from the Oyo-8 well during the three months ended September 30, 2017 was approximately 5,700 BOPD (approximately 5,000 BOPD net to the Company after royalty, over the number of days production occurred).

In early August 2017, the Pacific Bora drilling rig arrived on the Oyo field and immediately commenced drilling of the Oyo-9 well, In October 2017,the Company successfully completed the drilling phase of the Oyo-9 well. The well results indicate presence of the target channel system and 85.3 feet of net oil sand. The results are in line with predictions and confirm field extension to the western part of the field. Both the engineering and manufacturing of the subsea equipment are at various stages of completion. However, due to chronic delays in the release of the remaining funds and improper interference by the guarantor of the MCB Finance Facility, the Company temporarily suspended the completion and hookup of the development program. On several occasions, the Company has demanded the guarantor cease and desist from interfering in the disbursement of funds for the project. Consequently, the Pacific Bora drilling rig and all drilling services has been demobilized. The Oyo-9 well will be tied in to the field’s current production facility, and is expected to add an additional 6,000 to 7,000 barrels of oil per day from the field.

In October 2017, the Company obtained funding commitment to drill our potential high-impact exploration well in the Miocene formation of the OMLs. Site survey of the drilling location has been completed and the well is planned to be spud during the last quarter of 2017. Following the commitment to fund the drilling of the Miocene exploration well, the first option well of the drilling contract has been exercised with the drilling contractor.

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.

Blocks L1B and L16

The First Additional Exploration Period for both onshore blocks ended in July 2017. In accordance with the Kenya PSCs, the Company was 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.

In June 2017, the Company wrote off the costs related to onshore blocks L1B and L16 that had been capitalized to that date.

Blocks L27 and L28

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 lasted through February 2017. The remaining contractual obligation under the initial exploration period was for the Company to acquire, process and interpret 1,500 square kilometers of 3-D seismic data over both offshore blocks.

In December 2016, the Company wrote off the costs related to offshore blocks L27 and L28 that had been capitalized to that date as the Company no longer intends to renew or extend its leases on these offshore blocks.

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)interpret the approximately 1,500 square kilometers of 3-D seismic data that was acquired and processed in 2015 and 2016 (ii) drill one exploration well on either block A2 or A5 and evaluate the drilling results. The Company is currently interpreting the recently acquired and processed 3-D seismic data.

In March 2017, the Company entered into a Sale Agreement with FAR Ltd. (FAR), an Australian Securities Exchange listed oil and gas company, whereby FAR will acquire an 80% interest and operatorship of Erin Energy’s offshore A2 and A5 blocks, with the Company retaining a 20% working interest in both blocks. Under the terms of the Sale Agreement, which was approved by the Government of the Republic of The Gambia in June 2017, upon closing of the transaction, FAR paid the Company the purchase price of $5.2 million (the remaining $3.6 million was received on July 3, 2017) and will carry $8.0 million of the Company’s share of costs in a planned exploration well to be drilled in late 2018. In addition, if the Company’s share of the exploration well is less than $8.0 million, the balance is to be paid in cash to the Company. Any amount in excess of the $8.0 million representing the Company’s share of the exploration well will be borne by the Company.

The Company and FAR are currently interpreting the recently acquired 3-D seismic data to further mature identified prospects on blocks A2 and A5.

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 affiliated company.

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.

Following the recent decision of the Special Chamber of the International Tribunal of the Law of the Sea (ITLOS) in Hamburg concerning the maritime boundary dispute between Ghana and Côte d’Ivoire, the Company is working with the Ghanian Government and its partners to progress the development activities in its ESWT block, offshore Ghana. The 3D seismic data, which is planned to be acquired during the second quarter of 2018, will be used to improve subsurface definition and optimization of drilling targets.

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, 2016, filed on March 16, 2017 with the SEC.

Three months ended September 30, 2017, compared to three months ended September 30, 2016

Revenues

Revenue is recognized when an oil lifting occurs. Crude oil revenues for the three months ended September 30, 2017 were $33.6 million, as compared to $28.6 million for the same period in 2016. For the three months ended September 30, 2017, the Company sold approximately 600,000 net barrels of oil at an average price of $56.09/Bbl. 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.

During the three months ended September 30, 2017 and 2016, the average daily production from the Oyo field, net of royalty, over the number of days production occurred, was approximately 5,000 BOPD and 6,100 BOPD, respectively.

Operating Costs and Expenses

Production costs for the three months ended September 30, 2017 were $22.4 million, as compared to $24.9 million for the same period in 2016. Production costs include costs directly related to the production of hydrocarbons. 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, 2017, the Company did not incur workover expenses, as compared to expenditures of $0.2 million for the same period in 2016. The workover expenses in 2016 were mainly due to the light intervention of well Oyo-8.

During the three months ended September 30, 2017, the Company incurred $1.3 million of exploration expenses, including $0.1 million spent in Kenya, $0.2 million spent in Nigeria, $0.8 million spent in Ghana, and $0.2 million spent in The Gambia. During the three months ended September 30, 2016, the Company incurred $1.7 million of exploration expenses, including $0.2 million spent in Ghana, $0.4 million spent in Kenya, $0.4 million spent in Nigeria, and $0.7 million spent in The Gambia.

Depreciation, depletion and amortization (“DD&A”) expense for the three months ended September 30, 2017, was $13.1 million, as compared to $18.9 million for the same period in 2016. DD&A expense was lower during the three months ended September 30, 2017 mainly due to the lower depletion rates in 2017 as compared to the same period in 2016. The average depletion rate for the three months ended September 30, 2017 was $21.77/Bbl, as compared to $28.55/Bbl in the same period in 2016. The decrease in the average depletion rate during the three months ended September 30, 2017 as compared to the same period in 2016 was primarily due to the impairment of oil and gas properties recorded in June 2017 which reduced the overall depletion base.

Accretion of asset retirement obligations ("ARO") for the three months ended September 30, 2017 and 2016 was $0.5 million. ARO accretion expense for both 2017 and 2016 relates to the abandonment costs of the Company's developed properties in the Oyo field.

There was no impairment charge during the three months ended September 30, 2017 and 2016.

There was no plug and abandonment ("P&A") activity during the three months ended September 30, 2017 and 2016.

General and administrative ("G&A") expenses for the three months ended September 30, 2017 were $2.4 million, as compared to $3.6 million in the same period in 2016. G&A decreased in 2017 mainly due to the ongoing cost reduction initiatives, primarily related to employee costs and professional and consulting fees.

Other Income (Expense), Net

Other expense for the three months ended September 30, 2017 was $4.4 million, consisting of $6.0 million in interest expense on borrowings, partially offset by a $1.5 million gain on foreign currency transactions. Other expense for the same period in 2016 was $1.8 million, consisting of $5.0 million in interest expense on borrowings, partially offset by a $3.3 million gain on foreign currency transactions.

Income Taxes

The Company had no income taxes for each of the three months ended September 30, 2017 and 2016. The Company did not have any taxable income from its oil and gas activities in Nigeria in these respective periods and as such had no corresponding taxes.

Nine Months Ended September 30, 2017, compared to Nine Months Ended September 30, 2016

Revenues

Revenue is recognized when an oil lifting occurs. Crude oil revenues for the nine months ended September 30, 2017 were $79.5 million, as compared to $56.7 million for the same period in 2016. For the nine months ended September 30, 2017, the Company sold approximately 1,506,000 net barrels of oil at an average price of $52.80/Bbl. 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. The increase in average daily production is mainly attributed to that the current period's production is from the Oyo-8 well as compared to that during the 2016 period, when production was mainly from the Oyo-7 well.

During the nine months ended September 30, 2017 and 2016, the average daily production from the Oyo field, net of royalty, over the number of days production occurred, was approximately 5,200 BOPD and 4,500 BOPD, respectively.

Operating Costs and Expenses

Production costs for the nine months ended September 30, 2017 were $59.5 million, as compared to $69.6 million for the same period in 2016. Production costs include costs directly related to the production of hydrocarbons. 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, 2017, the Company incurred a net credit of $0.7 million of workover expenses, as compared to expenditures of $7.8 million for the same period in 2016. The decrease in workover expenses is due to the light intervention of well Oyo-8 during 2016. Further, during the current period in 2017, the Company reduced certain costs due to vendor settlements of outstanding invoices.

During the nine months ended September 30, 2017, the Company incurred $3.7 million of exploration expenses, including $0.7 million spent in Kenya, $0.5 million spent in Nigeria, $1.8 million spent in Ghana, and $0.7 million spent in The Gambia. 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.

Depreciation, depletion and amortization (“DD&A”) expense for the nine months ended September 30, 2017, was $50.2 million, as compared to $38.6 million for the same period in 2016. DD&A expense was higher during the nine months ended September 30, 2017 mainly due to the higher sales volumes in 2017 as compared to that in 2016. The Company sold approximately 1,506,000 net barrels during the nine months ended September 30, 2017, as compared approximately 1,253,000 net barrels during the same period in 2016.

Accretion of asset retirement obligations ("ARO") for the nine months ended September 30, 2017 and 2016 was $1.4 million. ARO accretion expense for both 2017 and 2016 relates to the abandonment costs of the Company's developed properties in the Oyo field.

During the nine months ended September 30, 2017, the Company recorded an impairment charge of $78.7 million, including a charge of $78.1 million to write down the carrying value of its oil and gas properties to their estimated fair market value and $0.6 million to write-off the carrying value of its onshore leases in Kenya which had expired. There was no impairment charge for the nine months ended September 30, 2016.

There was no P&A activity during the nine months ended September 30, 2017. The Company incurred P&A expenses of $0.2 million during the nine months ended September 30, 2016.

General and administrative ("G&A") expenses for the nine months ended September 30, 2017 were $9.0 million, as compared to $11.0 million in the same period in 2016. G&A decreased in 2017 mainly due to the ongoing cost reduction initiatives, primarily related to employee costs and professional and consulting fees.

During the nine months ended September 30, 2017, the Company recorded a $2.3 million gain on disposal of oil and gas properties arising from the sale of our Gambian blocks and a loss on asset disposal related to office furniture and leasehold improvements of $0.1 million. There were no such transactions during the nine months ended September 30, 2016.

Other Income (Expense), Net

Other expense for the nine months ended September 30, 2017 was $15.8 million, consisting of $20.8 million in interest expense on borrowings, partially offset by a $5.0 million gain on foreign currency transactions. Other expense for the same period in 2016 was $1.8 million consisting of $16.4 million in interest expense on borrowings, partially offset by a $14.6 million gain on foreign currency transactions.

Income Taxes

We had no income taxes for each of the nine months ended September 30, 2017 and 2016. The Company did not have any taxable income from its oil and gas activities in Nigeria in these respective periods and as such had no income taxes.

Headline Earnings

In addition to the Company’s primary listing on the NYSE American, the Company’s common stock is also traded on the Johannesburg Stock Exchange (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.

Basic and diluted HEPS is calculated using net loss adjusted for impairment on oil and gas properties for the three and nine months ended September 30, 2017. For the three and nine months ended September 30, 2016, there were no separately identifiable remeasurements based on the criteria outlined in circular 3/2009 and HEPS was the same as net loss per share as disclosed on the unaudited consolidated statements of operations. The number of shares used to calculate basic and diluted HEPS is the same as basic and diluted loss per share as reported under U.S. GAAP.

Reconciliation of net loss used to calculate basic and diluted loss per share and basic and diluted HEPS are as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
(In thousands, except for per share amounts)	2017			2016			2017			2016
Net loss attributable to Erin Energy Corporation	$	(14,070	)	$	(23,471	)	$	(139,142	)	$	(78,454	)
Adjustments:
Impairment of oil and gas properties	—			—			78,711			—
Loss on disposal of other property and equipment	—			—			149			—
Gain on sale of oil and gas properties	—			—			(2,348		)	—

Net loss used to calculate HEPS	$	(14,070	)	$	(23,471	)	$	(62,630	)	$	(78,454	)

Weighted average number of shares used to calculate basic net loss per share and basic HEPS	213,732			212,524			213,293			212,220

Weighted average number of shares used to calculate dilutive net loss per share and diluted HEPS	213,732			212,524			213,293			212,220

Headline earnings per share:
Basic	$	(0.07	)	$	(0.11	)	$	(0.29	)	$	(0.37	)
Diluted	$	(0.07	)	$	(0.11	)	$	(0.29	)	$	(0.37	)

Liquidity

Cash Flows from Operating Activities

Net cash provided by operating activities was $14.6 million for the nine months ended September 30, 2017, as compared to $10.8 million in the same period in 2016. Cash provided by operating activities in the nine months ended September 30, 2017 increased by $3.7 million as compared to the same period in 2016 primarily due to a combination of higher revenues and higher non-cash adjustments to net loss, offset by a decrease in vendor financing.

Cash Flows from Investing Activities

Cash used in investing activities for the nine months ended September 30, 2017 was $41.7 million, as compared to cash used of $16.5 million for the same period in 2016. 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 $38.1 million in the nine months ended September 30, 2017, consisted of $63.2 million of proceeds from the drawdowns under the MCB Finance Facility and $0.2 million borrowed under a short-term loan agreement with a related party, partially offset by $11.2 million funds restricted for debt service, $8.7 million payment for debt issuance costs, $4.7 million principal repayment of our Term Loan Facility, $0.1 million for principal repayment to our MCB Finance Facility and $0.7 million payment to settle withholding tax obligations upon vesting of restricted stock awards and exercise of stock options. Net cash provided by financing activities of $5.6 million for 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.

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. As of the date of this report, $65.7 million of the MCB Finance Facility has been drawn of which proceeds are restricted to the development of the Oyo field which we are currently drilling the Oyo-9 well. It is expected that the full $100.0 million available under this facility will be drawn by the end of the fourth quarter of 2017.

We incurred losses from operations for the three and nine months ended September 30, 2017. As of September 30, 2017, the Company's total current liabilities of $366.2 million exceeded its total current assets of $55.4 million, resulting in a working capital deficit of $310.8 million. As a result of the current low commodity prices, 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 2016. This has resulted in a loss of approximately 1,400 BOPD from the field. The Company is currently working on relocating an existing gaslift line to well Oyo-7 to enable continuous gaslift operation to assist in restoring lost production. For cost effectiveness, the relocation of the gaslift line to well Oyo-7 is now planned to be combined with the Oyo-9 subsea equipment installation scheduled for the second half of 2018. During an approximately two (2) week period starting from late June 2017 to early July 2017, the owners of the floating, production, storage, and offloading vessel (“FPSO”) Armada Perdana suspended its operations due to an impasse in contract negotiations that led to a temporary shut-in of the Oyo-8 well during this period. The FPSO operation was fully restored and the production from the Oyo-8 well was re-established on July 6, 2017. Contract negotiations have resumed.

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 2017 exploration and development campaign, (vi) farming-out a portion of our rights to certain of our oil and gas properties and (vii) exploring potential business combination transactions. However, sufficient capital may not be raised from one or more of these actions or these actions may not be consummated within the period needed to meet certain obligations.

On February 2017, we, together with our subsidiary, EPNL, entered into the MCB Finance Facility, which provides for a total commitment of USD $100.0 million. The proceeds from the MCB Finance Facility will be used to fund EPNL’s planned drilling of the Oyo-9 well offshore Nigeria.

In February 2017, we lifted and sold approximately 332,000 Bbls of crude oil (approximately 292,000 Bbls net to the Company). Net proceeds to us were approximately $15.9 million.

In March 2017, we lifted and sold approximately 346,000 Bbls of crude oil (approximately 304,000 Bbls net to the Company). Net proceeds to us were approximately $15.4 million.

In June 2017, we lifted and sold approximately 352,000 Bbls of crude oil (approximately 309,000 Bbls net to the Company). Net proceeds to us were approximately $14.6 million.

In September 2017, we lifted and sold approximately 682,000 Bbls of crude oil (approximately 600,000 Bbls net to the Company). Net proceeds to us were approximately $33.6 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, 2017, 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Foreign Currency Exchange Risk

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

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

The weighted average exchange rate between the U.S. dollar and the Nigerian Naira was 218.97 Naira per each U.S. dollar for the nine months ended September 30, 2017. For the nine months ended September 30, 2017, a 10% fluctuation in the weighted average exchange rate between the U.S. dollar and the Nigerian Naira would have had an approximate $4.8 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, 2017, a $10.00 fluctuation in the prices received for our crude oil sales would have had an approximate $15.1 million impact on our revenues based on the volumes lifted through September 30, 2017.

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, 2017, the weighted average interest rate on our variable rate debt was 8.60%. 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 $2.8 million over a twelve month period.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company established and maintains a system of 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 principal executive officer (PEO) and principal financial officer (PFO), as appropriate, to allow timely decisions regarding required disclosure.

Management of the Company, with the participation of its principal executive officer and principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of September 30, 2017. Based on their evaluation, as of the end of the period covered by this Form 10-Q, the Company’s principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed with the Commission pursuant to the Exchange Act, is recorded properly, processed, summarized and reported within the time periods specified in the rules and forms of the Commission and that such information is accumulated and communicated to our management, including our PEO and PFO, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

The following risk factors update the Risk Factors included in our Annual Report on Form 10-K filed with the SEC on March 16, 2017 for the fiscal year ended December 31, 2016 (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, 2017, we had approximately $24.9 million of outstanding principal under the 2011 Promissory Note, $50.0 million of outstanding principal under the 2014 Convertible Subordinated Note, $48.5 million of outstanding principal under the 2015 Convertible Note, $84.0 million outstanding principal under the Term Loan Facility, $6.4 million of outstanding principal under the 2016 Promissory Note and $63.2 million of outstanding principal under the MCB Finance Facility, 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 and the MCB Finance 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 and compliance with certain negative covenants restricting the incurrence of addition indebtedness. 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, the MCB Finance 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 and the MCB Facility could result in a default, which could permit the lenders to accelerate repayments and foreclose on the collateral securing such indebtedness.

Due to our lack of liquidity, we may not be able to make the required principal and interest payments under the Term Loan Facility, the MCB Facility and other indebtedness or to satisfy our obligations under our trade payables.

As a result of the current low commodity prices and a prior history of low oil production volumes due to the shut-in of well Oyo-8 from September 2015 to May 2016 and the currently shut-in well Oyo 7, 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 drawdowns under the MCB Facility and short-term promissory notes, such as the 2016 Promissory Note, with an entity related to the Company’s majority shareholder which notes have been foreclosed on and transferred to an unrelated party to supplement the Company’s liquidity needs, but we may not be able to continue to borrow funds under the MCB Facility in the future or the related party may not 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.

The Company did not pay the installment due and payable on September 30, 2017 and obtained a waiver from MCB to waive any event of default arising from the non-payment until December 31, 2017. The Company is currently in discussions with MCB on a revised principal repayment schedule. Our failure to make the required payments under the MCB Facility or the Term Loan Facility, or to comply with its applicable debt covenants could result in a default under the applicable facility and a cross-default under the other facility and the Related Party Notes (defined and described above under “Note 7 - Debt - Long-Term Debt - Related Party”, from the notes to the unaudited consolidated financial statements set forth above under “Part I Financial Information” - “Item 1 - Financial Statements”), which could result in the acceleration of the payment of such indebtedness, termination of commitments to make further loans to us, prevention of our development drilling on the Oyo field and other operations, 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 or obligations under our trade payables generally, Company may be unable to continue in its current state or continue to operate as a going concern.

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

Unregistered Sales of Equity Securities

In August 2017, the Company entered into a consulting agreement (the “Agreement”) with Somerley Capital Limited (“Somerley”), pursuant to which Somerley has agreed to represent the Company to perform certain financial advisory services. Somerley agreed to communicate with prospective investors with respect to the Company’s current and proposed activities, and to consult with the Company’s management concerning such activities. As partial consideration under the Agreement, in September 2017, the Company issued 33,333 shares of the Company’s restricted common stock.

In September 2017, the Company entered into the September 2017 Settlement Agreement (defined and described above under “Note 9 - Commitments and Contingencies - Contingencies - Legal Contingencies and Proceedings, from the notes to the unaudited consolidated financial statements set forth above under “Part I Financial Information - Item 1 - Financial Statements”) with a vendor. As part of the September 2017 Settlement Agreement, the Company issued 1,282,355 shares of the Company's restricted common stock valued at $3.5 million.

We claim an exemption from registration pursuant to Section 4(a)(2) and/or Rule 506 of Regulation D of the Securities Act, since the transactions above did not involve a public offering, the recipients were “accredited investors”, and acquired the securities for investment only and not with a view towards, or for resale in connection with, the public sale or distribution thereof. The securities are subject to transfer restrictions, and the certificates evidencing the securities contain an appropriate legend stating that such securities have not been registered under the Securities Act and may not be offered or sold absent registration or pursuant to an exemption therefrom and are further subject to the terms of the escrow agreement. The securities were not registered under the Securities Act.

Use of Proceeds From Sale of Registered Securities

None.

Issuer Purchases of Equity Securities

None.

Item 5. Other Information

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	Voting Agreement, dated as of July 5, 2017, by and among Dr. Kase Lawal, Latmol Investment Limited and Oltasho Nigeria Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 7, 2017).
10.2	Separation Agreement, effective as of May 31, 2017, by and between Erin Energy Corporation and Jean-Michel Malek (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 24, 2017).
10.3	Consulting Agreement, effective as of June 1, 2017, by and between Erin Energy Corporation and Jean-Michel Malek (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 24, 2017).
10.4*	Loan Agreement, effective as of October 27, 2017, by and between Erin Energy Corporation or its designated affiliate Erin Petroleum Nigeria Limited and James Street Capital Partners Limited.
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.

* Filed herewith.

** Furnished herewith.

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 8, 2017

/s/ Dippo Bello

Dippo Bello

Vice President, Financial Planning and Treasurer

(Interim Principal Financial Officer)

Erin Energy Corp. - FORM 10-Q - November 8, 2017

Attached files

Erin Energy Corp. Reports