Erin Energy (ERINQ) 10-Q 2015 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2015

OR

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

For the transition period from                      to                     

Commission File Number: 01-34525

ERIN ENERGY CORPORATION

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

(713) 797-2940

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

At November 2, 2015, there were 211,562,664 shares of common stock, par value $0.001 per share, outstanding.

1

PART I	FINANCIAL INFORMATION
Item 1.	Financial Statements:	3
	Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014 (unaudited)	3
	Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014 (unaudited)	4
	Consolidated Statements of Equity for the nine months ended September 30, 2015 (unaudited)	5
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014 (unaudited)	6
	Notes to Unaudited Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	25
Item 4.	Controls and Procedures	25
PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	26
Item 1A.	Risk Factors	26
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 6.	Exhibits	27
Signatures		28

2

PART I. – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ERIN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

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

	September 30,   2015			December 31, 2014
ASSETS
Current Assets:
Cash and cash equivalents	$	4,201		$	25,143
Restricted cash	9,277			1,496
Accounts receivable - partners	145			496
Accounts receivable - related party	624			624
Accounts receivable - other	50			54
Crude oil inventory	36,694			1,089
Prepaids and other current assets	1,815			2,929
Total current assets	52,806			31,831
Property, plant and equipment:
Oil and gas properties (successful efforts method of accounting), net	659,330			595,269
Other property, plant and equipment, net	1,169			1,060
Total property, plant and equipment, net	660,499			596,329
Other non-current assets:
Restricted cash	—			8,909
Debt issuance costs	1,044			1,307
Other non-current assets	67			67
Other assets, net	1,111			10,283
Total assets	$	714,416		$	638,443
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	188,918		$	108,047
Accounts payable and accrued liabilities - related party	26,154			9,391
Accounts payable - partners	35			—
Asset retirement obligations	—			12,703
Current portion of long-term debt	24,609			6,200
Short-term note payable - related party	2,000			—
Short-term borrowings	11,303			—
Total current liabilities	253,019			136,341
Long-term notes payable - related party	119,352			61,185
Term loan facility	73,827			93,000
Asset retirement obligations	24,360			13,830
Other long-term liabilities	—			82
Total liabilities	470,558			304,438
Commitments and contingencies
Equity:
Preferred stock $0.001 par value - 50,000,000 shares    authorized; none issued and outstanding at September 30, 2015 and December 31, 2014	—			—
Common stock $0.001 par value - 416,666,667 shares    authorized; 211,562,664 and 210,307,502 shares    outstanding as of September 30, 2015 and December 31, 2014	212			210
Additional paid-in capital	788,986			778,095
Accumulated deficit	(545,857		)	(444,954		)
Total equity - Erin Energy Corporation	243,341			333,351
Non-controlling interests	517			654
Total equity	243,858			334,005
Total liabilities and equity	$	714,416		$	638,443

See accompanying notes to unaudited consolidated financial statements.

3

ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues:
Crude oil sales, net of royalties	$	28,667		$	19,010		$	28,667		$	53,844
Operating costs and expenses:
Production costs	28,019			34,261			43,731			72,617
Workover expenses	354			—			972			—
Exploratory expenses	5,266			1,148			13,283			3,851
Depreciation, depletion and amortization	43,815			21,720			44,934			32,676
Loss on settlement of asset retirement obligations	779			—			4,233			—
General and administrative expenses	3,857			3,427			12,789			12,200
Total operating costs and expenses	82,090			60,556			119,942			121,344
Operating loss	(53,423		)	(41,546		)	(91,275		)	(67,500		)
Other income (expense):
Currency transaction gain	176			394			2,167			426
Interest expense	(5,650		)	(771		)	(12,485		)	(1,637		)
Other, net	—			(300		)	—			(300		)
Total other income (expense)	(5,474		)	(677		)	(10,318		)	(1,511		)
Loss before income taxes	(58,897		)	(42,223		)	(101,593		)	(69,011		)
Income tax expense	—			—			—			—
Net loss before non-controlling interest	(58,897		)	(42,223		)	(101,593		)	(69,011		)
Net loss attributable to non-controlling interest	215			—			690			—
Net loss attributable to Erin Energy Corporation	$	(58,682	)	$	(42,223	)	$	(100,903	)	$	(69,011	)
Net loss per common share:
Basic	$	(0.28	)	$	(0.20	)	$	(0.48	)	$	(0.40	)
Diluted	$	(0.28	)	$	(0.20	)	$	(0.48	)	$	(0.40	)
Weighted average common shares outstanding:
Basic	211,517			210,274			211,036			174,247
Diluted	211,517			210,274			211,036			174,247

See accompanying notes to unaudited consolidated financial statements.

4

ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited)

(In thousands)

	Common Stock		Additional Paid-in Capital		Accumulated Deficit			Non-controlling Interest			Total Equity
Balance at December 31, 2014	$	210	$	778,095	$	(444,954	)	$	654		$	334,005
Common stock issued	2		1,978		—			—			1,980
Stock based compensation	—		4,002		—			—			4,002
Warrants issued with debt	—		4,911		—			—			4,911
Funding from non-controlling interest	—		—		—			553			553
Net loss	—		—		(100,903		)	(690		)	(101,593		)
Balance at September 30, 2015	$	212	$	788,986	$	(545,857	)	$	517		$	243,858

See accompanying notes to unaudited consolidated financial statements.

5

ERIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2015			2014
Cash flows from operating activities
Net loss, including non-controlling interest	$	(101,593	)	$	(69,011	)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation, depletion and amortization	43,536			31,327
Accretion of asset retirement obligations	1,398			1,349
Amortization of debt discount and debt issuance costs	1,920			—
Loss on settlement of asset retirement obligations	4,233			—
Foreign currency transaction gain	(2,167		)	—
Share-based compensation	4,398			2,216
Related party liability offset	—			(32,880		)
Payments to settle asset retirement obligations	(17,220		)	—
Other	—			21
Change in operating assets and liabilities:
Decrease (increase) in accounts receivable	390			(10		)
Decrease (increase) in inventories	(9,493		)	13,715
Decrease (increase) in prepaids and other current assets	324			(7,103		)
Increase in accounts payable and accrued liabilities	58,126			27,277
Net cash used in operating activities	(16,148		)	(33,099		)
Cash flows from investing activities
Capital expenditures	(83,156		)	(59,481		)
Allied transaction	—			(170,000		)
Net cash used in investing activities	(83,156		)	(229,481		)
Cash flows from financing activities
Proceeds from the issuance of common stock	—			270,000
Proceeds from exercise of stock options and warrants	1,855			415
Proceeds from term loan facility	—			50,000
Proceeds from notes payable - related party, net	63,815			10,649
Proceeds from short-term borrowings, net	11,303			—
Debt issuance costs	—			(1,943		)
Allied transaction adjustments	—			(12,440		)
Funding from non-controlling interest	553			—
Net cash provided by financing activities	77,526			316,681
Effect of exchange rate changes on cash and cash equivalents	836			—
Net increase (decrease) in cash and cash equivalents	(20,942		)	54,101
Cash and cash equivalents at beginning of period	25,143			163
Cash and cash equivalents at end of period	$	4,201		$	54,264
Supplemental cash flow information
Cash paid for:
Interest, net	$	7,886		$	8
Non-cash investing and financing activities:
Issuance of common shares for settlement of liabilities	$	125		$	—
Discount on notes payable pursuant to issuance of warrants	$	4,911		$	—
Related party liability offset	$	—		$	32,880
Reduction in accounts payable from settlement of Northern Offshore contingency	$	24,307		$	—

See accompanying notes to unaudited consolidated financial statements.

6

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Company Description

Erin Energy Corporation (NYSE MKT: ERN; JSE: ERN), formerly CAMAC Energy, Inc., is an independent oil and gas exploration and production company focused on energy resources in Africa. The Company’s asset portfolio consists of nine licenses across four countries covering an area of approximately 40,000 square kilometers (approximately 10 million acres). The Company owns producing properties offshore Nigeria and conducts exploration activities offshore Nigeria, onshore and offshore Kenya, offshore The Gambia, and offshore Ghana.

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

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

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

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

2. Basis of Presentation and Recently Issued Accounting Standards

The accompanying unaudited consolidated financial statements include the accounts of the Company and its wholly owned and majority-owned direct and indirect subsidiaries and have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). All significant intercompany transactions and balances have been eliminated in consolidation. The unaudited consolidated financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial position and results of operations for the indicated periods. All such adjustments are of a normal recurring nature. This Form 10-Q should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on March 16, 2015.

Reverse Stock Split

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

Use of Estimates

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

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

7

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

is obtained and our operating environment changes.

Capitalized Interest

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

During the nine months ended September 30, 2015 and 2014, the Company capitalized $2.2 million and $0.3 million, respectively, in interest cost as additions to property, plant and equipment related to the Oyo field redevelopment campaign.

Net Earnings (Loss) Per Common Share

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

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

	Three Months Ended September 30,		Nine Months Ended September 30,
(In thousands)	2015	2014	2015	2014
Stock options	1,094	1,068	1,110	1,168
Stock warrants	650	2	504	1
Unvested restricted stock awards	1,278	1,023	1,308	993
Convertible subordinated note	12,454	11,844	12,302	10,491
	15,476	13,937	15,224	12,653

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

Fair Value of Financial Instruments

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

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

Recently Issued Accounting Standards

In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-01, Income Statement - Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. ASU No. 2015-01 eliminates from US GAAP the concept of extraordinary items, and is effective for fiscal years beginning after December 15, 2015. The Company will adopt this standards update, as required, beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

8

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. ASU No. 2015-11 simplifies the subsequent measurement of inventory by requiring inventory to be measured at the lower of cost and net realizable value. The FASB defines net realizable value as the “estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.” Under current guidance, an entity subsequently measures inventory at the lower of cost or market, with market defined as the replacement cost, net realizable value or net realizable value less a normal profit margin. An entity uses current replacement cost provided that it is not above net realizable value (i.e. the ceiling) or below net realizable value less an “approximately normal profit margin” (i.e. the floor). ASU No. 2015-11 eliminates this analysis for entities within the scope of the guidance. ASU No. 2015-11 applies to entities that recognize inventory within the scope of ASC 330, except for inventory measured under the LIFO method or the retail inventory method. ASU No. 2015-11 is effective for interim and annual periods beginning after December 15, 2016, and the Company will adopt this standards update, as required, beginning with the first quarter of 2017. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of Effective Date. ASU 2015-14 defers the effective date of revenue standard ASU 2014-09 by one year for all entities. Public business entities, certain not-for-profit entities, and certain employee benefit plans should apply the guidance in ASU No. 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. With the issuance of ASU No. 2015-14, the Company is required to adopt revenue standard ASU No. 2014-09 beginning with the first quarter of 2018. The Company is continuing to evaluate the impact of the adoption of this guidance on its consolidated financial statements.

In August 2015, the FASB issued ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting. ASU 2015-15 addresses line-of-credit arrangements that were omitted from Accounting Standards Update No. 2015-03. Under the guidance, the SEC staff would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred

9

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. ASU No. 2015-15 is effective for interim and annual periods beginning after December 15, 2015; early adoption is permitted for financial statements that have not been previously issued. The Company will adopt this standards update beginning with the first quarter of 2016. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. Under ASU NO. 2015-16, an acquirer must recognize adjustments to provisional amounts in business combinations that are identified during the measurement period in the reporting period in which the adjustment amounts are determined, including the cumulative effect of the change in provisional amount as if the accounting had been completed at the acquisition date. The adjustments related to previous reporting periods since the acquisition date must be disclosed by income statement line item either on the face of the income statement or in the notes. ASU No. 2015-16 is effective for interim and annual periods beginning after December 15, 2016, and the Company will adopt this standards update, as required, beginning with the first quarter of 2017. The adoption of this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

3. Liquidity Matters

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

Crude oil production is a primary source of operating cash for the Company. The Company commenced production from the Oyo-8 well in early May 2015 and from the Oyo-7 well in mid-June 2015. Combined daily production from both wells in the three months ended September 30, 2015 was approximately 11,600 barrels of oil per day ("BOPD") (approximately 10,200 BOPD net to the Company after royalty), and the Company lifted and sold approximately 649,000 Bbls of crude oil (approximately 571,000 Bbls net to the Company). In October 2015, the Company lifted and sold approximately 845,000 Bbls of crude oil (approximately 744,000 Bbls net to the Company). Net proceeds to the Company were approximately $35.1 million.

The Government of Nigeria has implemented certain control measures with regards to the exportation and sale of crude oil products from Nigeria. Accordingly, petroleum producers are required to obtain export permits for each crude oil lifting. In arriving at determining the quantity of crude oil to grant each oil producer, the Government considers factors, such as the overall strategic volume of crude oil to be sold for the whole country, current fiscal needs, and each producer’s pro-rata share of total country production. During the period from May to September 2015, the Company produced approximately 1.5 million Bbls of crude oil but was only able to sell approximately 0.6 million Bbls due to export permit limitations. The resulting crude oil inventory of approximately 0.9 million Bbls, as of September 30, 2015, was approaching the Company’s maximum crude oil storage capacity on its Floating Production Storage and Offloading vessel (“FPSO”). As a result, the Company had to curtail production from its producing wells.

The Company subsequently received a permit to export approximately 1.3 million Bbls for the period from October to December 2015. This would allow for re-establishing production at previous levels. Accordingly, the Company lifted and sold approximately 0.8 million Bbls in October, and is expecting to lift and sell approximately 0.5 million additional Bbls by December 31, 2015.

The Company is currently in the process of re-establishing production from its producing wells that were affected by the FPSO storage capacity issue, and expects to resume full production at previous rates. If actual production rates decline substantially below anticipated rates, or if oil prices decline significantly from current levels, the Company may need to seek additional sources of capital.

In March 2015, the Company entered into a borrowing facility with Allied in the form of a Convertible Note (the "2015 Convertible Note"), separate from the existing $25.0 million Promissory Note and the $50.0 million Convertible Subordinated Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. As of September 30, 2015, the outstanding principal under the 2015 Convertible Note was $48.0 million. See Note 7 - Debt for additional information.

In July 2015, the Company received $13.0 million as an advance under a stand-alone spot sales contract with Glencore Energy UK (the “July Advance”). Interest accrued on the July Advance at the rate of the 30-day LIBOR plus 6.5% per annum. Repayment of the July Advance was made from the July crude oil lifting.

10

ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

In August 2015, the Company received a $26.5 million advance under a stand-alone spot sales contract with Glencore Energy UK Ltd. (the “August Advance”). Interest accrues on the August Advance at the rate of 30-day LIBOR plus 6.5% per annum. Partial repayment of the August Advance was made from the September crude oil lifting. The outstanding principal and interest under the August Advance of $11.3 million and $0.2 million, respectively, as of September 30, 2015, were fully repaid in October 2015.

In September 2015, the Company borrowed $2.0 million under a 30-day Promissory Note agreement entered into with an entity related to the Company's majority shareholder (the “2015 Short-Term Note”). The 2015 Short-Term Note accrued interest at a rate of the 30-day LIBOR plus 3% per annum, and was fully repaid in October 2015.

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

4. Property, Plant and Equipment

Property, plant and equipment were comprised of the following:

(In thousands)	September 30,   2015			December 31, 2014
Wells and production facilities	$	327,893		$	33,690
Proved properties	386,196			386,196
Work in progress and other	99,454			261,346
Oilfield assets	813,543			681,232
Accumulated depletion	(164,653		)	(95,403		)
Oilfield assets, net	648,890			585,829
Unevaluated leaseholds	10,440			9,440
Oil and gas properties, net	659,330			595,269
Other property and equipment	2,831			2,324
Accumulated depreciation	(1,662		)	(1,264		)
Other property and equipment, net	1,169			1,060
Total property, plant and equipment, net	$	660,499		$	596,329

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

5. Suspended Exploratory Well Costs

In November 2013, the Company achieved both its primary and secondary drilling objectives for the Oyo-7 well. The primary drilling objective was to establish production from the existing Pliocene reservoir. The secondary drilling objective was to confirm the presence of hydrocarbons in the deeper Miocene formation. Hydrocarbons were encountered in three intervals totaling approximately 65 feet, as interpreted by logging-while-drilling (“LWD”) data. Management is making plans to further explore the Miocene formation in future wells. Suspended exploratory well costs were $26.5 million at both September 30, 2015 and December 31, 2014 for the costs related to the Miocene exploratory drilling activities.

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

6. Asset Retirement Obligations

The Company’s asset retirement obligations primarily represent the estimated fair value of the amounts that will be incurred to plug, abandon and remediate certain oil and gas properties at the end of their productive lives. Significant inputs used in determining

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

such obligations include, but are not limited to, estimates of plugging and abandonment costs, estimated future inflation rates and changes in property lives. The inputs are calculated based on historical data as well as current estimated costs.

On a quarterly basis, the Company reviews the assumptions used to estimate the expected cash flows required to settle the asset retirement obligations, including changes in estimated probabilities, amounts and timing of the settlement of the asset retirement obligations, as well as changes in the legal obligation for each of its properties. Changes in any one or more of these assumptions may cause revisions in the estimated liabilities for the corresponding assets. The following summarizes changes in the Company’s asset retirement obligations during the nine months ended September 30, 2015 (in thousands):

Balance at January 1, 2015	$	26,533
Accretion expense	1,398
Additions	9,416
Loss on settlement of asset retirement obligations	4,233
Payments to settle asset retirement obligations	(17,220		)
Balance at September 30, 2015	$	24,360

In April 2015, the Company completed plug and abandonment ("P&A") activities for well Oyo-6 that was previously shut-in. Actual P&A expenditures exceeded estimated P&A liabilities by $4.2 million. Accordingly, the Company recorded a $4.2 million loss on settlement of asset retirement obligations.

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

(In thousands)	September 30,   2015		December 31, 2014
Asset retirement obligations, current portion	—		12,703
Asset retirement obligations, long-term portion	24,360		13,830
	$	24,360	$	26,533

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

7. Debt

Short-Term Debt:

Promissory Note - Short-Term (Related Party)

In September 2015, the Company borrowed $2.0 million under a 30-day Promissory Note agreement entered into with an entity related to the Company's majority shareholder (the “2015 Short-Term Note”). The 2015 Short-Term Note accrued interest at a rate of the 30-day LIBOR plus 3% per annum, and was fully repaid in October 2015.

Short-Term Borrowing - Glencore Advances

In July 2015, the Company received $13.0 million as an advance under a stand-alone spot sales contract with Glencore Energy UK (the “July Advance”). Interest accrued on the July Advance at the rate of the 30-day LIBOR plus 6.5% per annum. Repayment of the July Advance was made from the July crude oil lifting.

In August 2015, the Company received a $26.5 million advance under a stand-alone spot sales contract with Glencore Energy UK Ltd. (the “August Advance”). Interest accrues on the August Advance at the rate of 30-day LIBOR plus 6.5% per annum. Partial repayment of the August Advance was made from the September crude oil lifting. The outstanding principal and interest under the August Advance of $11.3 million and $0.2 million, respectively, as of September 30, 2015, were fully repaid in October 2015.

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt:

Promissory Note - Related Party

The Company has a $25.0 million borrowing facility under a Promissory Note (the “Promissory Note”) with Allied. Interest accrues on the outstanding principal under the Promissory Note at a rate of the 30-day LIBOR plus 2% per annum, payable quarterly. In October 2015, the Promissory Note was amended to extend the maturity date to July 30, 2017. The entire $25.0 million facility amount can be utilized for general corporate purposes. As of September 30, 2015, the outstanding principal and interest under the Promissory Note was $25.0 million and $0.7 million, respectively.

Convertible Subordinated Note – Related Party

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

At the election of the holder, the Convertible Subordinated Note is convertible into shares of the Company’s common stock at an initial conversion price of $4.2984 per share, subject to anti-dilution adjustments. The Convertible Subordinated Note is subordinated to the Company’s existing and future senior indebtedness and is subject to acceleration upon an Event of Default (as defined in the Convertible Subordinated Note). The Company may, at its option, prepay the Convertible Subordinated Note in whole or in part, at any time, without premium or penalty, and is subject to mandatory prepayment upon (i) the Company’s issuance of capital stock or incurrence of indebtedness, the proceeds of which the Company does not apply to repayment of senior indebtedness or (ii) any capital markets debt issuance to the extent the net proceeds of such issuance exceed $250.0 million. Allied may assign all or any part of its rights and obligations under the Convertible Subordinated Note to any person upon written notice to the Company. As of September 30, 2015, the outstanding principal and accrued interest under the Convertible Subordinated Note was $50.0 million and $4.4 million, respectively.

2015 Convertible Note – Related Party

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

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

As of September 30, 2015, the Company had borrowed $48.0 million under the note and issued to Allied warrants to purchase approximately 2.6 million shares of the Company’s common stock at prices ranging from $2.46 to $7.85 per share. The total fair market value of the warrants amounting to $4.9 million based on the Black-Scholes option pricing model was recorded as a discount from the note, and is being amortized using the effective interest method over the life of the note. As of September 30, 2015, the unamortized balance of the note discount was $3.6 million.

Additional warrants are issuable in connection with future borrowings, with the per share price for those warrants determined based on the market price of the Company’s common stock at the time of such future borrowings. As of September 30, 2015, the Company owed $44.4 million under the 2015 Convertible Note, net of discount. Accrued interest on the 2015 Convertible Note was $1.3 million as of September 30, 2015.

Term Loan Facility

In September 2014, the Company, through its wholly owned subsidiary CPL, entered into a credit facility with a Nigerian bank for a five-year senior secured term loan providing initial borrowing capacity of up to $100.0 million (the “Term Loan Facility”). 90% of the Term Loan Facility is available in U.S. dollar, while the remaining 10% is available in Nigerian Naira. U.S. dollar borrowings under the Term Loan Facility currently bear interest at the rate of LIBOR plus 10.5%. The obligations under the Term

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Loan Facility include a legal charge over OMLs 120 and 121 and an assignment of proceeds from oil sales. The obligations of CPL have been guaranteed by the Company and rank in priority with all its other obligations. Proceeds from the Term Loan Facility were used for the further expansion and development of the Oyo field offshore Nigeria.

Under the Term Loan Facility, the following events, among others, constitute events of default: CPL failing to pay any amounts due within thirty days of the due date; bankruptcy, insolvency, liquidation or dissolution of CPL; a material breach of the Loan Agreement by CPL that remains unremedied within thirty days of written notice by CPL; or a representation or warranty of CPL proves to have been incorrect or materially inaccurate when made. Upon any event of default, all outstanding principal and interest under any loans will become immediately due and payable.

The Term Loan Facility contains normal and customary covenants including the delivery of the Company’s annual audited financial information each year, and a provision of priority of interest, in which the Company is to procure that its obligations under the Term Loan Facility do and will rank in priority with all its other current and future unsecured and unsubordinated obligations. The Company is also to provide a production and lifting schedule each month displaying the daily production totals and quantities lifted respectively from OMLs 120 and 121. The Company was in compliance with all loan covenants as of September 30, 2015.

Upon executing the Term Loan Facility, the Company paid fees totaling $2.6 million, which 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, 2015, $1.8 million of the debt issuance cost remain unamortized. As of September 30, 2015, the Company recognized an unrealized foreign currency gain of $1.6 million on the Naira portion of the loan, reducing the net balance under the Term Loan Facility to $98.4 million. Of this amount, $73.8 million was classified as long-term and $24.6 million as short-term. Accrued interest for the Term Loan Facility was $2.5 million as of September 30, 2015.

8. Related Party Transactions

Assets and Liabilities

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

(In thousands)	September 30,   2015		December 31, 2014
Accounts receivable, CEHL	$	624	$	624
Accounts payable and accrued liabilities, CEHL	$	26,154	$	9,391
Short-term notes payable - related party, CEHL	$	2,000	$	—
Long-term notes payable - related party, CEHL	$	119,352	$	61,185

As of September 30, 2015 and December 31, 2014, the Company owed $26.2 million and $9.4 million, respectively, to an affiliate primarily for logistical and support services in relation to the Company's oilfield operations in Nigeria, as well as accrued interest on the various related party notes payable. As of September 30, 2015 and December 31, 2014, accrued and unpaid interest on the various related party notes payable were $6.7 million and $2.8 million, respectively.

In September 2015, the Company borrowed $2.0 million from an entity related to CEHL under a 30-day Promissory Note. See Note 7 – Debt for further information.

As of September 30, 2015, the Company had a long-term note payable balance of $119.4 million owed to an affiliate, consisting of the $50.0 million Convertible Subordinated Note, $25.0 million borrowings under the Promissory Note, and $44.4 million borrowings under the 2015 Convertible Note, net of discount. As of December 31, 2014, the Company had a long-term note payable balance of $61.2 million owed to an affiliate, consisting of the $50.0 million Convertible Subordinated Note and $11.2 million borrowings under the Promissory Note. See Note 7 – Debt for further information relating to the notes payable transactions.

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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, 2015 and 2014:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands)	2015		2014		2015		2014
Total operating expenses, CEHL	$	4,316	$	5,939	$	9,239	$	10,185
Interest expense, CEHL	$	1,591	$	773	$	3,868	$	1,629

An affiliate of the Company provides procurement and logistical support services to the Company’s Nigerian operations. In connection therewith, during the three months ended September 30, 2015 and 2014, the Company incurred operating costs amounting to approximately $4.3 million and $5.9 million, respectively, and during the nine months ended September 30, 2015 and 2014, the Company incurred operating costs amounting to approximately $9.2 million and $10.2 million, respectively.

During the three months ended September 30, 2015 and 2014, the Company incurred interest expense, excluding debt discount amortization, totaling approximately $1.6 million and $0.8 million, respectively, in relation to related party notes payable. During the nine months ended September 30, 2015 and 2014, the Company incurred interest expense, excluding debt discount amortization, totaling approximately $3.9 million and $1.6 million, respectively.

9. Commitments and Contingencies

Commitments

In February 2014, a long-term contract was signed for the floating, production, storage, and offloading vessel (“FPSO”) Armada Perdana, which is the vessel currently connected to the Company’s producing wells Oyo-8 and Oyo-7 in Nigeria. The contract provides for an initial term of seven years beginning January 1, 2014, with an automatic extension for an additional term of two years unless terminated by the Company with prior notice. The FPSO can process up to 40,000 barrels of liquid per day, with a storage capacity of approximately one million barrels. In June 2015, the operator of the FPSO agreed to a price reduction for the operating day rates incurred by the Company for the period from July 2014 to April 2015. This resulted in a $26.0 million reduction in previously accrued production costs. The remaining annual minimum commitment per the terms of the agreement is approximately $48.4 million through 2020.

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

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

In July 2015, having satisfied all material contractual obligations under the initial exploration period on its onshore blocks L1B and L16 in Kenya, the Company received approval from the Kenya Ministry of Energy and Petroleum to enter into the First Additional Exploration Period for both blocks, which will last two contract years, through July 2017. In accordance with the Kenya PSCs, during the First Additional Exploration Period, the Company is obligated, for each block, to (i) acquire, process, and interpret high density 300 square kilometer 3-D seismic 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.

Contingencies

Legal Contingencies

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. As of September 30, 2015, and through the filing date of this report, the Company does not believe the ultimate resolution of such

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ERIN ENERGY CORPORATION

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

actions or potential actions of which the Company is currently aware will have a material effect on its consolidated financial position or results of operations.

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

Contingency under the Allied Transfer Agreement

As provided for under the Transfer Agreement with Allied, the Company is required to make the following additional payments upon the occurrence of certain future events: (i) $25.0 million cash or the equivalent in shares of the Company’s common stock within fifteen days following the approval of a development plan by the Nigerian Department of Petroleum Resources ("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.

10. Stock-Based Compensation

Stock Options

During the nine months ended September 30, 2015, the Company granted to certain employees options to purchase a total of 266,668 shares of common stock with a three-year vesting period. During the same period, options to purchase 152,844 shares of common stock were forfeited.

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

Stock Warrants

During the nine months ended September 30, 2015, in connection with the execution of the 2015 Convertible Note, the Company issued to Allied warrants to purchase approximately 2.6 million shares of the Company’s common stock at exercise prices ranging from$2.46 to $7.85 per share. The warrants are exercisable at any time starting from the date of issuance and have a five-year term.

During the nine months ended September 30, 2015, 0.2 million previously issued warrants were forfeited.

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

Restricted Stock Awards

During the nine months ended September 30, 2015, the Company granted officers, directors, and employees a total of approximately 1.2 million shares of restricted common stock with vesting periods varying from immediate vesting to 36 months. During the same period, 39,397 shares of restricted common stock were forfeited.

In February 2015, the Company granted performance-based restricted stock awards (PBRSA) to certain officers totaling 0.4 million shares. Each grant will vest if the individuals remain employed three years from the date of grant and the Company achieves specific performance objectives at the end of the designated performance period. Up to 50% additional shares may be awarded if performance objectives are exceeded. None of the PBRSAs will vest if certain minimum performance goals are not met. The

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

performance conditions are based on the Company’s total shareholder return over the performance period compared to an industry peer group of companies. Total estimated compensation expense is $0.4 million over three years.

11. Segment Information

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

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

(In thousands)	Nigeria			Kenya			The Gambia			Ghana			Corporate and Other			Total
Three months ended September 30,
2015
Revenues	$	28,667		$	—		$	—		$	—		$	—		$	28,667
Operating income (loss)	$	(44,858	)	$	(1,056	)	$	(3,985	)	$	(444	)	$	(3,080	)	$	(53,423	)
2014
Revenues	$	19,010		$	—		$	—		$	—		$	—		$	19,010
Operating income (loss)	$	(37,040	)	$	(614	)	$	(341	)	$	(43	)	$	(3,508	)	$	(41,546	)
Nine months ended September 30,
2015
Revenues	$	28,667		$	—		$	—		$	—		$	—		$	28,667
Operating loss	$	(65,883	)	$	(7,162	)	$	(4,647	)	$	(1,393	)	$	(12,190	)	$	(91,275	)
2014
Revenues	$	53,844		$	—		$	—		$	—		$	—		$	53,844
Operating loss	$	(51,349	)	$	(2,689	)	$	(983	)	$	(49	)	$	(12,430	)	$	(67,500	)

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

(In thousands)	Nigeria		Kenya		The Gambia		Ghana		Corporate and Other		Total
Total Assets
As of September 30, 2015	$	705,697	$	1,383	$	3,028	$	1,937	$	2,371	$	714,416
As of December 31, 2014	$	609,243	$	8,527	$	2,739	$	1,413	$	16,521	$	638,443

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

Our Business

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

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

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

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

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

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

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

Nigeria

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

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

In March 2015, the Company finished completion operations for well Oyo-8, and successfully hooked it up to the FPSO. Production commenced in May 2015. In April 2015, the Company completed plug and abandonment activities for well Oyo-6, a well that was previously shut-in in 2014. The semi-submersible rig Sedco Express was then mobilized to the Oyo-7 well location to initiate horizontal completion activities for well Oyo-7. The Company commenced production from well Oyo-7 in mid-June 2015.

Cumulative production from wells Oyo-7 and Oyo-8 from May 2015 to September 2015 was approximately 1.5 million Bbls (approximately 1.3 million Bbls net to the Company after royalty). Combined daily production from both wells in the three months ended September 30, 2015, was approximately 11,600 BOPD (approximately 10,200 BOPD net to the Company after royalty).

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

Kenya

The Company, through a wholly owned subsidiary, entered into four production sharing contracts with the Government of the Republic of Kenya, covering onshore exploration blocks L1B and L16, and offshore exploration blocks L27 and L28 (the “Kenya PSCs”). Each block requires specific work commitments to be completed by the end of the respective license periods. The Company

18

is the operator of all blocks with the Government having the right to participate up to 20%, either directly or through an appointee, in any area subsequent to declaration of a commercial discovery. The Company is responsible for all exploration expenditures.

The initial exploration period for onshore blocks L1B and L16 ended in June 2015. Having satisfied all material contractual obligations under the initial exploration period, the Company received approval from the Kenya Ministry of Energy and Petroleum to enter into the First Additional Exploration Period for both blocks. The First Additional Exploration Period for both blocks will last two contract years, through July 2017. In accordance with certain provisions of the Kenya PSCs, the Company relinquished 25% of its original acreage on block L1B; however, the Company was allowed to retain the totality of its original acreage in block L16. Further, in accordance with the Kenya PSCs, during the First Additional Exploration Period, the Company is obligated, for each block, to (i) acquire, process, and interpret high density 300 square kilometer 3-D seismic 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 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 blocks L27 and L28, which will now last through February 2017. The remaining contractual obligation under the initial exploration period is for the Company to acquire, process, and interpret 3-D seismic data over both offshore blocks. The Company plans to pursue completion of the work program, and is also considering the possibility of farming-out a portion of its rights to both offshore blocks to potential partners. Upon completion of the work program, the Company has the right to apply for up to two additional two-year exploration periods, with specified additional minimum work obligations, including the acquisition of seismic data and the drilling of one exploratory well on each block during each additional period.

The Gambia

The Company, through a wholly owned subsidiary, entered into two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia, for offshore exploration blocks A2 and A5 (the “Gambia Licenses”). Each block requires specific work commitments to be completed by the end of the respective license periods. For both blocks, the Company is the operator, with the Gambian National Petroleum Company (“GNPCo”) having the right to elect to participate up to a 15% interest, following approval of a development and production plan. The Company is responsible for all expenditures prior to such approval even if the GNPCo elects to participate.

The term of the initial exploration period for both blocks A2 and A5 was extended by two years through December 2018 following an amendment agreement (the "Amendment") entered into with The Republic of the Gambia in May 2015. As of September 30, 2015, the remaining contractual obligations, pursuant to the Amendment under the Gambia Licenses for both blocks, is for the Company to (i) complete the interpretation of approximately 1,600 square kilometer 3-D seismic data that was acquired in September 2015 and (ii) drill one exploration well on either block A2 or A5 and evaluate the drilling results. As consideration for the Amendment, the Company agreed to (i) pay a $1.0 million extension fee, (ii) provide a full well guarantee on either block at such time that the Company enters into a farm-in agreement with a partner, and (iii) pay the annual contractual Training and Resources Expenses into a Government of Gambia bank account in The Gambia. The Company intends to pursue completion of the work program, and is also considering the possibility of farming-out a portion of its rights to both blocks to potential partners.

Ghana

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

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

In October 2015, the Company completed its economic and commercial evaluation of the three previously discovered fields. The Company is currently working with its joint venture partners and relevant government entities on further optimization studies towards declaration of commercial viability.

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Results of Operations

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

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

Revenues

Revenue is recognized when a lifting (sale) occurs. Crude oil revenues for the three months ended September 30, 2015, were $28.7 million, as compared to $19.0 million for the same period in 2014. For the three months ended September 30, 2015, the Company sold approximately 571,000 net barrels of oil at an average price of $50.2/Bbl as compared to approximately 189,000 net barrels of oil at an average price of $100.9/Bbl for the same period in 2014.

During the three months ended September 30, 2015 and 2014, the average net daily production from the Oyo field was approximately 10,200 and 800 BOPD, respectively.

Operating Costs and Expenses

Production costs for the three months ended September 30, 2015, were $28.0 million, as compared to expenditures of $34.3 million for the same period in 2014. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized, and are subsequently expensed when crude oil is sold. The $6.2 million decrease in production costs in the three months ended September 30, 2015, as compared to the same period in 2014 was principally due to $9.2 million lower production expenditures associated with unsold crude oil inventory, partially offset by $2.1 million higher lifting costs and $1.2 million higher fuel costs.

During the three months ended September 30, 2015, the Company spent $0.4 million as additional repair costs for a control module associated with its well Oyo-4 that is currently operating as a gas injection well. The expenditure was recorded as a workover expense. There were no workover expenses incurred for the three months ended September 30, 2014.

During the three months ended September 30, 2015, the Company incurred $5.3 million of exploration expenses, including $3.9 million spent in The Gambia primarily for 3-D seismic acquisition, $0.8 million spent in Kenya for exploration activities, and $0.4 million spent in Ghana for exploration activities. During the three months ended September 30, 2014, the Company incurred $1.1 million of exploration expenses, including $0.3 million in The Gambia for exploration activities, $0.6 million in Kenya for exploration activities, and $0.2 million spent in Nigeria for exploration activities.

Depreciation, depletion and amortization (“DD&A”) expenses, including asset retirement obligation ("ARO") accretion, for the three months ended September 30, 2015, were $43.8 million, as compared to $21.7 million for the same period in 2014. During the three months ended September 30, 2015, DD&A expenses increased as compared to the same period in 2014 primarily due to higher sales volumes. The average depletion rate, for the three months ended September 30, 2015, including ARO accretion, was $76.7/Bbl, as compared to $115.2/Bbl in the same period in 2014.

In April 2015, the Company completed plug and abandonment (P&A) activities for well Oyo-6 that was previously shut-in. Additional P&A expenditures paid in the three months ended September 30, 2015, in relation to well Oyo-6 were $0.8 million. Accordingly, the Company recognized this cost as a loss on settlement of its ARO. No P&A activity occurred during the same period in 2014.

General and administrative (G&A) expenses for the three months ended September 30, 2015 were $3.9 million, as compared to $3.4 million in the same period in 2014. The increase in 2015 is primarily due to increased overhead costs incurred to support the Company's foreign operations.

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Other Income (Expense)

Other expense for the three months ended September 30, 2015 was $5.5 million, consisting of $5.7 million interest expense on borrowings, partially offset by a $0.2 million gain on foreign currency transactions. Other expense for the same period in 2014 was $0.7 million, primarily for interest accrued on the related party note payable.

Income Taxes

Income taxes were nil for each of the three months ended September 30, 2015 and 2014. The Company is projecting negative taxable earnings for its Nigerian operations for the fiscal year ended December 31, 2015, and thus is not subject to petroleum profit taxes in Nigeria. The Company had negative taxable earnings in its Nigerian operations in 2014 and thus was not subject to petroleum profit taxes in Nigeria.

Nine months ended September 30, 2015, compared to nine months ended September 30, 2014

Revenues

Revenue is recognized when a lifting (sale) occurs. Crude oil revenues for the nine months ended September 30, 2015, were $28.7 million, as compared to $53.8 million for the same period in 2014. For the nine months ended September 30, 2015, the Company sold approximately 571,000 net barrels of oil at an average price of $50.2/Bbl as compared to approximately 506,000 net barrels of oil at an average price of $106.4/Bbl for the same period in 2014.

During the nine months ended September 30, 2015 and 2014, the average net daily production from the Oyo field, over the days production actually occurred, was approximately 8,700 and 1,300 BOPD, respectively.

Operating Costs and Expenses

Production costs for the nine months ended September 30, 2015, were $43.7 million, as compared to $72.6 million for the same period in 2014. The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized and are subsequently expensed when crude oil is sold. The $28.9 million decrease in production costs year-over-year was primarily due to $23.2 million lower production expenses associated with unsold crude oil inventory and $26.0 million agreed-upon retroactive FPSO operating day rate cost reductions, and $4.1 million reduction in certain other production costs, partially offset by $22.2 million higher FPSO costs and $2.1 million higher lifting costs in 2015.

During the nine months ended September 30, 2015, the Company spent $1.0 million to repair a control module associated with its well Oyo-4 that is currently operating as a gas injection well. The expenditure was recorded as a workover expense. There were no workover expenses incurred for the nine months ended September 30, 2014.

During the nine months ended September 30, 2015, the Company incurred $13.3 million exploration expenses, including $6.9 million spent in Kenya primarily for 2-D seismic acquisition and processing, $4.6 million spent in The Gambia primarily for 3-D seismic acquisition, $1.3 million spent in Ghana for exploration activities, and $0.4 million spent in Nigeria for exploration activities. During the nine months ended September 30, 2014, the Company incurred $3.9 million of exploration expenses, including $2.7 million spent in Kenya, $1.0 million in The Gambia, and $0.2 million in Nigeria.

DD&A expenses, including ARO accretion, for the nine months ended September 30, 2015, were $44.9 million, as compared to $32.7 million for the same period in 2014. During the nine months ended September 30, 2015, DD&A expenses increased as compared to the same period in 2014 primarily due to higher production volumes. The average depletion rate for the nine months ended September 30, 2015, including ARO accretion expense, was $78.7/Bbl, as compared to $64.6/Bbl in the same period in 2014.

In April 2015, the Company completed P&A activities for well Oyo-6 that was previously shut-in. Actual P&A expenditures exceeded estimated P&A liabilities by $4.2 million. Accordingly, the Company recognized a $4.2 million loss on settlement of its asset retirement obligations during the nine months ended September 30, 2015. No P&A activity occurred during the same period in 2014.

G&A expenses for the nine months ended September 30, 2015 were $12.8 million, as compared to $12.2 million in the same period in 2014. The increase in 2015 is primarily due to increased overhead costs incurred to support the Company's foreign operations

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and certain higher severance costs recognized in May 2015, partially offset by lower charges for consulting services incurred as compared to the same period in 2014 in relation to a consulting agreement for investor relations services.

Other Income (Expense)

Other expense for the nine months ended September 30, 2015, was $10.3 million, consisting of $12.5 million in interest expense on borrowings, net of $2.2 million capitalized interest, partially offset by a $2.2 million gain on foreign currency transactions. Other expense for the same period in 2014 was $1.5 million, primarily for interest accrued on the related party note payable.

Income Taxes

Income taxes were nil for each of the nine months ended September 30, 2015 and 2014. The Company is projecting negative taxable earnings for its Nigerian operations for the fiscal year ended December 31, 2015, and thus is not subject to petroleum profit taxes in Nigeria. The Company had negative taxable earnings in its Nigerian operations in 2014 and thus was not subject to petroleum profit taxes in Nigeria.

Headline Earnings 

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

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

The number of shares used to calculate basic and diluted HEPS is the same as basic and diluted EPS. During the three and nine months ended September 30, 2015 and 2014, there were no separate identifiable re-measurements required and headline earnings was the same as net loss per share as disclosed on the unaudited consolidated statements of operations. Therefore, HEPS for the three months ended September 30, 2015 and 2014, were $(0.28) and $(0.20), respectively, and for the nine months ended September 30, 2015 and 2014, were $(0.48) and $(0.40), respectively.

Liquidity

Cash Flows from Operating Activities

Cash used in operating activities in the nine months ended September 30, 2015, decreased by $17.0 million as compared to the same period in 2014 primarily because the period in 2015 does not include a $32.9 million payment made in 2014 to offset certain related party liabilities, while the period in 2015 includes $17.2 million in costs incurred to settle certain asset retirement obligations.

Cash Flows from Investing Activities

Cash used in investing activities during the nine months ended September 30, 2015, consists of $83.2 million payments for additions to property, plant and equipment primarily for the ongoing Oyo field redevelopment campaign in the OMLs. The cash used in investing activities for the nine months ended September 30, 2014 included $170.0 million paid to Allied as partial consideration for the acquisition of the remaining economic interest in the OMLs and $59.5 million additions to property, plant, and equipment.

Cash Flows from Financing Activities

Net cash provided by financing activities of $77.5 million in the nine months ended September 30, 2015, consisted of $63.8 million borrowings from related parties, $11.3 million advance from Glencore, $1.9 million proceeds from the exercise of stock options and warrants, and $0.6 million in funding from an entity owning a non-controlling interest in the Company's Ghana subsidiary. Net cash provided by financing activities of $316.7 million for the nine months ended September 30, 2014, consisted of a $270.0 million investment from the sale of equity in conjunction with the acquisition of the Allied Assets, $50.0 million borrowings under the Term Loan Facility, a $10.6 million borrowing from a related party, $0.4 million of proceeds from the issuance of stock pursuant to employee stock option exercises, partially offset by a $12.4 million adjustment to the net assets of Allied in connection with the Allied Transaction and $1.9 million of fees paid to secure the Term Loan Facility.

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Capital Resources

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

Crude oil production is a primary source of operating cash for the Company. The Company commenced production from the Oyo-8 well in early May 2015 and from the Oyo-7 well in mid-June 2015. Combined daily production from both wells in the three months ended September 30, 2015, was approximately 11,600 barrels of oil per day ("BOPD") (approximately 10,200 BOPD net to the Company after royalty), and the Company lifted and sold approximately 649,000 Bbls of crude oil (approximately 571,000 Bbls net to the Company). In October 2015, the Company lifted and sold approximately 845,000 Bbls of crude oil (approximately 744,000 Bbls net to the Company). Net proceeds to the Company were approximately $35.1 million.

The Government of Nigeria has implemented certain control measures with regards to the exportation and sale of crude oil products from Nigeria. Accordingly, petroleum producers are required to obtain export permits for each crude oil lifting. In arriving at determining the quantity of crude oil to grant each oil producer, the Government considers factors, such as the overall strategic volume of crude oil to be sold for the whole country, current fiscal needs, and each producer’s pro-rata share of total country production. During the period from May to September 2015, the Company produced approximately 1.5 million Bbls of crude oil and was only able to sell approximately 0.6 million Bbls due to export permit limitations. The resulting crude oil inventory of approximately 0.9 million Bbls as of September 30, 2015, was approaching the Company’s maximum crude oil storage capacity on its Floating Production Storage and Offloading vessel (“FPSO”). As a result, the Company had to curtail production from its producing wells.

The Company subsequently received a permit to export approximately 1.3 million Bbls for the period from October to December 2015. This would allow for re-establishing production at previous levels. Accordingly, the Company lifted and sold approximately 0.8 million Bbls in October, and is expecting to lift and sell approximately 0.5 million additional Bbls by December 31, 2015.

The Company is currently in the process of re-establishing production from its producing wells that were affected by the FPSO storage capacity issue, and expects to resume full production at previous rates. If actual production rates decline substantially below anticipated rates, or if oil prices decline significantly from current levels, the Company may need to seek additional sources of capital.

In March 2015, the Company entered into a borrowing facility with Allied for a Convertible Note (the "2015 Convertible Note"), separate from the existing $25.0 million Promissory Note and the $50.0 million Convertible Subordinated Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. As of September 30, 2015, the outstanding principal under the 2015 Convertible Note was $48.0 million. See Note 7 - Debt for additional information.

In July 2015, the Company received a $13.0 million advance under a stand-alone spot sales contract with Glencore Energy UK (the “July Advance”). Interest accrued on the July Advance at the rate of the 30-day LIBOR plus 6.5% per annum. Repayment of the July Advance was made from the July crude oil lifting.

In August 2015, the Company received a $26.5 million advance under a stand-alone spot sales contract with Glencore Energy UK Ltd. (the “August Advance”). Interest accrues on the August Advance at the rate of 30-day LIBOR plus 6.5% per annum. Partial repayment of the August Advance was made from the September crude oil lifting. The outstanding principal and interest under the August Advance of $11.3 million and $0.2 million, respectively, as of September 30, 2015, were fully repaid in October 2015. See Note 7 - Debt in the Notes to Unaudited Consolidated Financial Statements for additional information.

In September 2015, the Company borrowed $2.0 million under a 30-day Promissory Note agreement entered into with an entity related to the Company's majority shareholder (the “2015 Short-Term Note”). The 2015 Short-Term Note accrued interest at a rate of the 30-day LIBOR plus 3% per annum, and was fully repaid in October 2015.

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

Although there are no assurances that the Company’s plans will be realized, management believes that the Company will have sufficient capital resources to meet projected cash flow requirements for the next twelve months from the date of filing this report.

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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, 2015, material off-balance sheet obligations include operating leases for the FPSO and certain employment contracts. Other than the material off-balance sheet arrangements discussed above, no other arrangements are likely to have a current or future material effect on our financial condition, results from operations, liquidity, capital expenditures or capital resources.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

• our current and future indebtedness;

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

• our ability to develop oil and gas reserves;

• competition from other companies in the energy market;

• political instability and foreign government regulations over international operations;

• our lack of diversification of production and reserves;

• compliance and enforcement of environmental laws and regulations;

• our ability to achieve profitability;

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

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

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

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Foreign Currency Exchange Risk

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

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

The weighted average exchange rate between the U.S. dollar and the Nigerian Naira was 196.20 Naira per each U.S. dollar for the nine months ended September 30, 2015. For the nine months ended September 30, 2015, a 10% fluctuation in the weighted average exchange rate between the U.S. dollar and the Nigerian Naira would have had an approximate $0.5 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, 2015, a $10.00 fluctuation in the prices received for our crude oil sales would have had an approximate $5.7 million impact on our revenues.

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

Interest Rate Risk

We are exposed to changes in interest rates, primarily from possible fluctuations in the London Interbank Borrowing Rate (“LIBOR”). The interest rates on our debt obligations are stated at floating rates tied to the LIBOR. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes. For the nine months ended September 30, 2015, the weighted average interest rate on our variable rate debt was 8.6%. 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 $2.3 million over a twelve month period.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Management of the Company, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2015. Based on their evaluation, as of the

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end of the period covered by this Form 10-Q, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

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

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

In March 2015, the Company entered into a borrowing facility with Allied for the 2015 Convertible Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. As of September 30, 2015, the Company has drawn $48.0 million under the note and issued to Allied warrants to purchase approximately 2.6 million shares of the Company’s common stock at prices ranging from $2.46 to $7.85 per share. For further information, see Note 7 - Debt to the Unaudited Consolidated Financial Statements.

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Item 6. Exhibits

The following exhibits are filed with this report:

Exhibit Number	Description
3.1	Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 10-SB filed on August 16, 2007).
3.2	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 13, 2010).
3.3	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 19, 2014).
3.4	Certificate of Amendment to Amended and Restated Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 23, 2015).
3.5	Amended and Restated Bylaws of the Company as of April 11, 2011 (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed on May 3, 2011).
10.1	Offer of Employment as Senior Vice President and Chief Financial Officer, dated September 10, 2015, by and between the Company and Daniel Ogbonna (incorporated by reference to Exhibit 10.1 on Form 8-K filed on September 15, 2015).
10.2	Amended and Extended Maturity Date of the Promissory Note dated June 6, 2011, amended October XX, 2015, by and among CAMAC Petroleum Limited and Allied Energy Plc.
31.1	Certification of Chief Executive Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer Pursuant to 15 U.S.C. § 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101. INS	XBRL Instance Document.
101. SCH	XBRL Schema Document.
101. CAL	XBRL Calculation Linkbase Document.
101. DEF	XBRL Taxonomy Extension Definition Linkbase Document
101. LAB	XBRL Label Linkbase Document.
101. PRE	XBRL Presentation Linkbase Document.

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SIGNATURES

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

Erin Energy Corporation

Date: November 9, 2015

/s/ Daniel Ogbonna

Daniel Ogbonna

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

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