UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________________________________________________
FORM 10-K
____________________________________________________________________________________________

		
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the fiscal year ended December 31, 2017
OR

		
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the transition period from:    to   
001-34525
(Commission File Number)
____________________________________________________________________________________________
ERIN ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
____________________________________________________________________________________________

		
Delaware	30-0349798	
(State or Other Jurisdiction
of Incorporation or Organization)	(I.R.S. Employer
Identification No.)	
1330 Post Oak Blvd., Suite 2250, Houston, TX 77056
(Address of Principal Executive Office) (Zip Code)
(713) 797-2940
(Registrant’s telephone number, including area code)
____________________________________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.001 par value
Securities registered pursuant to Section 12(g) of the Act:
None
____________________________________________________________________________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ
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 þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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

										
Large accelerated filer	¨	Accelerated filer	þ	Non-accelerated filer	¨	Smaller reporting company	¨	Emerging growth company
	¨
	
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $132,949,914 based on a share price of $1.45. All executive officers and directors of the registrant have been deemed, solely for the purpose of the forgoing calculation, to be “affiliates” of the registrant.
As of March 1, 2018 , there were  215,337,614 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement relating to its 2018 annual meeting of shareholders (the “2018 Proxy Statement”) are incorporated by reference into Part III of this Annual Report on Form 10-K where indicated. The 2018 Proxy Statement will be filed with the U.S. Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates.

	

Erin Energy Corporation
FORM 10-K
TABLE OF CONTENTS

	
			
 	 	Page	
Glossary of Oil and Gas Terms	 	
 	PART I	 	
Item 1.	Description of Business	5	
Item 1A.	Risk Factors	12	
Item 1B.	Unresolved Staff Comments	32	
Item 2.	Properties	32	
Item 3.	Legal Proceedings	38	
Item 4.	Mine Safety Disclosures	38	
 	PART II	 	
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38	
Item 6.	Selected Financial Data	43	
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43	
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	53	
Item 8.	Financial Statements and Supplemental Data	54	
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55	
Item 9A.	Controls and Procedures	55	
Item 9B.	Other Information	58	
 	PART III	 	
Item 10.	Directors, Executive Officers and Corporate Governance	58	
Item 11.	Executive Compensation	58	
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	58	
Item 13.	Certain Relationships and Related Transactions, and Director Independence	58	
Item 14.	Principal Accountant Fees and Services	58	
 	PART IV	 	
Item 15.	Exhibits, Financial Statements and Schedules	59	
Signatures	65	

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GLOSSARY OF SELECTED OIL AND GAS TERMS
 
The following is a description of the meanings of certain oil and gas industry terms and acronyms used in this report:
 
2-D seismic data - 2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of subsurface data.
 
3-D seismic data - 3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D seismic survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data provide more reliable information than 2-D seismic data.

Bbl - One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons.
 
BOPD - One barrel of oil per day.
 
MBbl - One thousand Bbls.
 
Development well -  A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
 
Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or crude oil in another reservoir.
 
Field -  An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Gross oil and gas wells or acres - The Company’s gross wells or gross acres represent the total number of wells or acres in which the Company owns a working interest.

LWD - Abbreviation for logging while drilling. The measurement of formation properties during the excavation of the hole, or shortly thereafter, through the use of tools integrated into the bottomhole assembly.
 
Net oil and gas wells or acres - Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that the Company owns in such wells or acres represented by the underlying properties.
 
Productive well - A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
 
Prospect - A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
 
Proved developed reserves -  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
 
Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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Proved undeveloped reserves - Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
 
Standardized measure of proved reserves - The present value, discounted at 10%, of the future net cash flows attributable to estimated net proved reserves, as estimated in the Company’s independent engineer’s reserve report.
 
Unproved properties or unevaluated leasehold - Properties with no proved reserves.
 
PART I
 
ITEM 1.    BUSINESS
 
This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions, and are influenced by various factors. As a consequence, actual results may differ materially from those in the forward-looking statements. See Item 1A Risk Factors of this Form 10-K for a discussion of risk factors.
 
Unless the context otherwise requires, the terms “we,” “us,” “our,” “Company” and “the Company” refer to Erin Energy Corporation, a Delaware corporation originally organized in 1979, and its subsidiaries and, unless the context otherwise requires and for the purposes of this report only:

•	"Exchange Act" refers to the Securities Exchange Act of 1934, as amended;	
		
•	"SEC" or the "Commission" refers to the United State Securities and Exchange Commission; and	
		
•	"Securities Act" refers to the Securities Act of 1933, as amended.	

The Company’s corporate headquarters is located in Houston, Texas. For more information about Erin Energy Corporation, visit www.erinenergy.com, which website contains information we do not desire to incorporate by reference in this report.
 
GENERAL
 
Erin Energy Corporation is an independent oil and gas exploration and production company focused on energy resources in Africa. Our strategy is to acquire and develop high-potential exploration and production assets in Africa, and to explore and develop those assets through strategic partnerships with national oil companies, indigenous local partners and other independent oil companies. We seek to build and operate a strategic portfolio of high-impact exploration and near-term development projects with significant production, reserves and resources growth potential.
 
We actively manage investments and on-going operations by limiting capital exposure through farm-outs at various stages of exploration and development to share risks and costs. We prioritize on building a strong technical and operational team and place an emphasis on the utilization of modern oil field technologies that mature our assets, reduce the cost of our projects and improve the efficiency of our operations.
 
Our shares are traded on both the NYSE American and on the Johannesburg Stock Exchange under the symbol “ERN.”
 
Our asset portfolio consists of five licenses across three countries covering an area of approximately 1.5 million acres (approximately 6,000 square kilometers). We own producing properties offshore Nigeria and conduct exploration activities as an operator offshore Nigeria and conduct exploration activities as an operator offshore Ghana, and as a non-operator offshore The Gambia.

Our operating subsidiaries include Erin Petroleum Nigeria Limited (“EPNL”), Erin Energy Kenya Limited ("EEKL"), Erin Energy Gambia Ltd., and Erin Energy Ghana Limited.

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

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

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

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

OIL AND GAS ACTIVITIES
 
Nigeria

In June 2012, Allied acquired all of Nigerian Agip Exploration Limited ("NAE")’s participating interest in Oil Mining Leases 120 and 121 (the "OMLs") offshore Nigeria, and all of NAE’s interest in the Production Sharing Contract ("the PSC") relating to the Oyo field. As a result of this transaction, Allied became the operator of the OMLs and the holder of the interests in the PSC, apart from the interests previously acquired by the Company in 2010 and 2011.

In September 2013, drilling operations commenced on the development well Oyo-7. Based on logging-while-drilling (“LWD”) data, the well encountered gross oil pay of 133 feet (net oil pay of 115 feet) and gross gas pay of 103 feet (net gas pay of 93 feet) in the gas cap from the then producing Pliocene reservoir, with excellent reservoir quality. The well was temporarily suspended. As a secondary objective, the well Oyo-7 confirmed the presence of hydrocarbons in the deeper Miocene formation. This marked the first time a well had been successfully drilled into the Miocene formation in OML 120. Hydrocarbons were encountered in three intervals totaling approximately 65 feet, as interpreted from the LWD data. The Company is currently making plans for further exploratory activities in the Miocene formation.

In February 2014, an affiliate of the Company entered into a long-term contract for the Floating Production, Storage and Offloading vessel ("FPSO") Armada Perdana . 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.

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In February 2014, the Company acquired all remaining economic interests in the PSC and related assets, contracts and rights pertaining to the OMLs located offshore Nigeria, including the producing Oyo field (the “Allied Assets”), from Allied (the “Allied Transaction”) pursuant to a Transfer Agreement entered into in November 2013 by the Company and its affiliates, and Allied (the “Transfer Agreement”). In consideration for the Allied Assets, the Company issued 82.9 million shares of the Company’s common stock, delivered to Allied a $50.0 million convertible subordinated promissory note (the “2014 Convertible Subordinated Note”) and paid $170.0 million in cash. As a result of the Allied Transaction, the Company now owns 100% of the economic interest in the OMLs. The Allied Assets included two producing wells as of the transaction date: wells Oyo-5 and Oyo-6.

In August 2014, the Company drilled well Oyo-8 to a total vertical depth of approximately 6,059 feet (approximately 1,847 meters) and successfully encountered four new oil and gas reservoirs with total gross hydrocarbon thickness of 112 feet in the eastern fault block, based on results from the LWD data, reservoir pressure measurement, and reservoir fluid sampling. The well was temporarily suspended.
 
In September 2014, the Company shut-in both wells Oyo-5 and Oyo-6 and successfully removed their flow lines and other subsea equipment for relocation to wells Oyo-7 and Oyo-8 as planned. The Company also initiated temporary plug and abandonment activities for well Oyo-5.
 
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 and subsequently initiated well Oyo-7's horizontal completion activities. The Company commenced production from well Oyo-7 in June 2015.

The enforcement of certain control measures implemented by the Nigerian government with regards to the quarterly exportation and sale of crude oil products from Nigeria has had an impact on the Company’s operations. Petroleum producers are required to obtain export permits quarterly for crude oil liftings. During the period from May to September 2015, the Company produced approximately 1.5 million Bbls of crude oil but only sold approximately 0.6 million Bbls due to unexpected delays in the issuance of export permits for the quarter ending September 30, 2015. The resulting crude oil inventory of approximately 0.9 million Bbls, as of September 30, 2015, was approaching the Company’s crude oil storage capacity on its FPSO. As a result, the Company had to curtail production by temporarily shutting-in well Oyo-8 in September 2015. The Company subsequently received a permit to export approximately 1.3 million Bbls from October to December 2015.

In early May 2016, with the help of a light intervention vessel, the Company successfully completed well repair operations to resolve the mechanical problem related to well Oyo-8 and successfully resumed production from the well.
 
In early July 2016, well Oyo-7 was shut-in as a result of an emergency shut-in of the Oyo field production. This has resulted in a loss of approximately 1,400 BOPD from the field. The Company is currently working on relocating an existing gaslift line to well Oyo-7 to enable continuous gaslift operation. For cost effectiveness, the relocation of the gaslift line to well Oyo-7 is now planned to be combined with the Oyo-9 subsea equipment installation scheduled for the second half of 2018, subject to fund availability.

During the three months ended December 31, 2017, the average daily production was approximately 4,600 BOPD (approximately 4,000 BOPD net to the Company).

In early August 2017, the Pacific Bora drilling rig arrived on the Oyo field and immediately commenced drilling of the Oyo-9 well, In October 2017, the Company successfully completed the drilling phase of the Oyo-9 well. The well results indicate presence of the target channel system and 85.3 feet of net oil sand. The results are in line with predictions and confirm field extension to the western part of the field. Both the engineering and manufacturing of the subsea equipment are at various stages of completion. However, due to chronic delays in the release of the remaining funds and improper interference by the guarantor of the MCB Finance Facility (described and defined below under Note 8. - Debt -“Long-Term Debt - MCB Finance Facility and Related Agreements, to the Notes to Unaudited Consolidated Financial Statements), the Company temporarily suspended the completion and hookup of the development program. On several occasions, the Company has demanded the guarantor cease and desist from interfering in the disbursement of funds for the project. Consequently, the Pacific Bora drilling rig and all drilling services has been demobilized. The Oyo-9 well will be tied in to the field’s current production facility, and is expected to add an additional 6,000 to 7,000 barrels of oil per day from the field.

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In October 2017, the Company obtained a funding commitment to drill our potential high-impact exploration well ("Oyo-NW"), in the Miocene formation of the OMLs. The Company completed the drilling of the Oyo-NW well and, based on preliminary evaluation; it has discovered hydrocarbons in the Miocene Formation. Preliminary evaluation of the well data shows that the two main sand units, the Miocene U7.0 and U8.0, with a gross thickness of approximately 115.2 feet are hydrocarbon-bearing. Work has commenced to estimate the discovered volumes and to determine the relevant appraisal and development program.

Kenya
 
In May 2012, the Company, through a wholly-owned subsidiary, entered into four production sharing contracts with the Government of the Republic of Kenya, covering onshore exploration blocks L1B and L16, and offshore exploration blocks L27 and L28 (the “Kenya PSCs”). The Company is the operator of all of the blocks with the Government having the right to participate up to 20%, either directly or through an appointee, in any area subsequent to declaration of a commercial discovery. The Company is responsible for all exploration expenditures.
 
Blocks L1B and L16
 
The Kenya PSCs for onshore blocks L1B and L16 each provided for an initial exploration period with specified minimum work obligations during that period. Prior to the end of the initial exploration period, the Company was required, for each block, to i) conduct a gravity and magnetic survey and ii) acquire, process and interpret 2-D seismic data.

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 onshore blocks ended in July 2017. In accordance with the Kenya PSCs, the Company was obligated, for each block, to (i) acquire, process and interpret high density 300 square kilometer 3-D seismic data at a minimum expenditure of $12.0 million and (ii) drill one exploration well to a minimum depth of 3,000 meters at a minimum expenditure of $20.0 million.

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

The Company no longer intends to renew or extend its leases on these onshore blocks.

Blocks L27 and L28
The Kenya PSCs for offshore blocks L27 and L28 each provided for an initial exploration period of three years, through August 2015, with specified minimum work obligations during that period. Prior to the end of the initial exploration period, the Company is required to, for each block, i) conduct a regional geological and geophysical study, ii) reprocess and re-interpret previous 2-D seismic data and iii) acquire, process and interpret 1,500 square kilometers of 3-D seismic data.
In March 2014, the Company, through its participation in a multi-client combined gravity/magnetic and 2-D seismic survey, completed its required gravity/magnetic and 2-D seismic data acquisition for both blocks.
In April 2015, the Company completed a regional geological and geophysical study.
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 lasted through February 2017. The remaining contractual obligation under the initial exploration period was for the Company to acquire, process and interpret 1,500 square kilometers of 3-D seismic data over both offshore blocks and wrote off the cost that had been capitalized to that date in 2016.

The Company no longer intends to renew or extend its leases on these offshore blocks.

The Gambia
 
In May 2012, the Company, through a wholly-owned subsidiary, signed two Petroleum Exploration, Development & Production Licenses with The Republic of The Gambia, for offshore exploration blocks A2 and A5 (the “Gambia Licenses”). For both

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blocks, the Company is the operator, with the Gambian National Petroleum Company (“GNPCo”) having the right to elect to participate up to a 15% interest, following approval of a development and production plan. The Company is responsible for all expenditures prior to such approval even if the GNPCo elects to participate.

The term of the initial exploration period for both blocks A2 and A5, now extended through December 2018, require for the Company to (i) interpret the approximately 1,500 square kilometers of 3-D seismic data that was acquired and processed in 2015 and 2016 and (ii) drill one exploration well on either block A2 or A5 and evaluate the drilling results. The Company is currently interpreting the recently acquired and processed 3-D seismic data.

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

The Company and FAR are currently working together to progress our plans to drill the Samo-1 prospect exploratory well in late 2018.

Ghana
 
In April 2014, the Company, through an indirect 50%-owned subsidiary, signed a Petroleum Agreement with the Republic of Ghana (the “Petroleum Agreement”) relating to the Expanded Shallow Water Tano block offshore Ghana ("ESWT"). The contracting parties, which hold 90% of the participating interest in the block, are Erin Energy Ghana Limited as the operator, GNPC Exploration and Production Company Limited, and Base Energy (collectively the “Contracting Parties”), holding 60%, 25%, and 15% of the participating interest of the Contracting Parties, respectively. The Ghana National Petroleum Corporation initially has a 10% carried interest through the exploration phase, and will have the option to acquire an additional paying interest of up to 10% following a declaration of commercial discovery. The Company owns 50% of its subsidiary Erin Energy Ghana Limited. The remaining 50% interest is owned by an affiliated company.
 
The ESWT block contains three previously discovered fields (the "Fields") and the work program required the Contracting Parties to determine, within nine months of the effective date of the Petroleum Agreement, the economic viability of developing the Fields. In addition, the Petroleum Agreement provided for an initial exploration period of two years from the effective date of the Petroleum Agreement, with specified work obligations during that period, including the reprocessing of existing 2-D and 3-D seismic data and the drilling of one exploration well on the ESWT block. The Contracting Parties have the right to apply for a first extension period of one and one-half years and a second extension period of up to two and one-half years. Each extension period has specified additional minimum work obligations, including (i) conducting geological and geophysical studies during the first extension period and (ii) drilling one exploration well during the first extension period and, depending on the length of the extension, one or two wells during the second extension period.
 
In January 2015, the Petroleum Agreement became effective, following the signing of a Joint Operating Agreement between the Contracting Parties.
 
In October 2015, at the completion of the initial technical and commercial evaluation of the Fields, the Contracting Parties concluded that certain fiscal terms in the Petroleum Agreement had to be adjusted in order to achieve commerciality of the Fields under current economic conditions. The Contracting Parties have presented this conclusion to the relevant government entities. The Ghanaian Government is currently reviewing the requests for adjustment of the fiscal terms, and has granted the Company an extension of the Initial Exploration Period for eighteen months until the end of July 2018. The Company has submitted an application to the Ghanaian government for an additional extension of the initial exploration period beyond the current date of July 2018.
Following the recent decision of the Special Chamber of the International Tribunal of the Law of the Sea (ITLOS) in Hamburg, Germany, concerning the maritime boundary dispute between Ghana and Côte d’Ivoire, the Company is working with the Ghanaian Government and its partners to progress the development activities in its ESWT block, offshore Ghana. The 3D seismic

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data, which is planned to be acquired during the second half of 2018, will be used to improve subsurface definition and optimization of drilling targets.
 
Segment Information
 
For information related to our financial performance by segment, see Note 13. — Segment Information to the Notes to Consolidated Financial Statements.
 
REGULATION
 
General
 
Our operations and our ability to finance and fund our growth strategy are affected by political developments and laws and regulations in the areas in which we operate. In particular, oil and natural gas production operations and economics are affected by:

•	changes in governments;	
		
•	civil unrest;	
		
•	price and currency controls;	
		
•	limitations on oil and natural gas production and exports;	
		
•	tax, environmental, safety and other laws relating to the petroleum industry;	
		
•	changes in laws relating to the petroleum industry;	
		
•	changes in administrative regulations and the interpretation and application of such rules and regulations; and	
		
•	changes in contract interpretation and policies of contract adherence.	
 
In any country in which we may do business, the oil and natural gas industry legislation and agency regulation are periodically changed, sometimes retroactively, for a variety of political, economic, environmental and other reasons. Numerous governmental departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and our potential for economic loss.
 
Environmental and Government Regulation
 
Various federal, state, local and international laws and regulations relating to the discharge of materials into the environment, the disposal of oil and natural gas wastes, or otherwise relating to the protection of the environment may affect our operations and costs. We are committed to the protection of the environment and believe we are in material compliance with the applicable laws and regulations. However, regulatory requirements may, and often do, change and become more stringent, and there can be no assurance that future regulations will not have a material adverse effect on our financial position, results of operations and cash flows. During the years ended December 31, 2017 , 2016 and 2015 , other than the plug and abandonment ("P&A") expenditures for well Oyo-6, we did not have any significant expenditures relating to environmental and government regulation.
 
MARKETING AND PRICING
 
We currently derive the totality of our revenue from the sale of crude oil in Nigeria. As a result, our revenues and ultimate profitability, the value of our reserves, our access to capital and our growth are substantially subject to the prevailing prices of crude oil. Prevailing prices for such commodities are subject to wide fluctuations for macro-economic reasons beyond our control. Historically, prices received for crude oil sales have been volatile and unpredictable, and such volatility and unpredictability is expected to continue.
 
COMPETITION

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We compete with numerous large international oil companies and smaller oil companies that target opportunities in markets similar to ours, including the natural gas and petroleum markets. Many of these companies have far greater economic, political and material resources at their disposal. Our management team has prior experience in the fields of petroleum engineering, geology, field development, production, operations, international business development, and finance and experience in management and executive positions with international energy companies. Nevertheless, the markets in which we operate and plan to operate are highly competitive and the Company may not be able to compete successfully against its current and future competitors. See Item 1A. Risk Factors for risk factors associated with competition in the oil and gas industry.
 
RISK MANAGEMENT AND INSURANCE PROGRAM
 
Insurance Program
In accordance with industry practice, the Company maintains insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from significant losses resulting from damages to, or the loss of, physical assets or loss of human life and liability claims of third parties, including such occurrences as well blow-outs and weather events that result in oil spills and damage to our wells and/or platforms. Our goal is to balance the cost of insurance with our assessment of the potential risk of an adverse event. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and statutory regulations and we regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.
 
We continuously monitor regulatory changes and regulatory responses and their impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection at optimum levels, weighing the cost of insurance against the potential and magnitude of disruption to our operations and cash flows. 
 
Currently, the Company has operator’s extra expense insurance coverage up to $250.0 million per occurrence with respect to drilling and $75.0 million per occurrence with respect to all other wells. This includes coverage for re-drilling and restoration of wells as well as coverage for resultant environmental damage, including voluntary clean-up. The Company also carries physical damage coverage on offshore assets that is subject to full replacement cost limits. Both of these coverages, operator’s extra expense and physical damage, are subject to certain customary exclusions and limitations and to deductibles generally ranging from approximately $0.3 million to $2.0 million per occurrence, which must be met prior to recovery. In addition, the Company carries third party liability insurance, which includes pollution insurance, up to a limit of $50 million. This program includes coverage for bodily injury and property damage to third parties, including sudden and accidental pollution liability coverage.
 
Health, Safety and Environmental Program
 
Our Health, Safety and Environmental (“HSE”) Program is supervised by an HSE officer who reports to senior management to ensure compliance with all applicable state and federal regulations. Its implementation and execution is the direct responsibility of the respective country managers in all the countries in which we operate. We have in place an HSE policy that mandates compliance with all relevant HSE regulations and industry standards in the various countries in which we operate. The policy is designed with the joint goals of zero injuries and accidents, no risk to occupational health, and no damage to the environment.
 
EMPLOYEES
 
At December 31, 2017 , the Company had a total of 61 full-time employees and 3 part-time employees, of which 26 were employed in the United States, and 35 in Africa. We have been successful in attracting a talented team of industry professionals that has been instrumental in achieving significant growth and success for the Company. In addition to our employees, we utilize the services of various independent contractors and service providers to perform certain professional services, as needed.
 
During 2018, the Company may need to hire additional personnel in certain operational positions as needed. The number and skill sets of individual employees will be primarily dependent on the relative rates of growth of the Company’s different projects and the extent to which operations and development activities are executed internally or contracted to outside parties. In order for us to attract and retain qualified personnel, we will have to offer competitive salaries to present and future employees.
 
AVAILABLE INFORMATION

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The Company files or furnishes Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registrations statements and other items with the Securities and Exchange Commission (“SEC”). We also make available, free of charge on our Internet website (http://www.erinenergy.com), our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Exchange Act are also available on our website. We will also make available to any shareholder, without charge, copies of our Annual Report on Form 10-K as filed with the SEC. Individuals wishing to obtain this report, or any other filing, should submit a request to Erin Energy Corporation, 1330 Post Oak Boulevard, Suite 2250, Houston, TX 77056, Attention: Investor Relations.
 
The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street NE, Washington, DC 20549-0213. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.
 
ITEM 1A. RISK FACTORS

CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K 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, such expectations may not prove to be correct. We caution you not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Important factors that could affect our financial performance and that could cause actual results for future periods to differ materially from our expectations include, but are not limited to:

•	the supply, demand and market prices of oil and natural gas;	
		
•	our current and future indebtedness;	
		
•	our ability to raise capital to fund our current and future operations;	
		
•	our ability to develop oil and gas reserves;	
		
•	competition from other companies in the energy market;	
		
•	political instability and foreign government regulations over international operations;	
		
•	our lack of diversification of production and reserves;	
		
•	compliance and enforcement of restriction on production and exports;	
		
•	compliance and enforcement of environmental laws and regulations;	
		
•	our ability to achieve profitability;	
		
•	our dependency on third parties to enable us to produce and deliver oil and gas; and	
		
•	other factors disclosed under Item 1. Description of Business , Item 1A. Risk Factors , Item 2. Properties , Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk 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, actual results may differ materially from those expressed or implied by our forward-looking statements. You should consider carefully the statements under the

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“Risk Factors” section of this report and other sections of this report which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, and the following factors:

•	the possibility that our future acquisitions may involve unexpected costs;	
		
•	the volatility in commodity prices for oil and gas;	
		
•	the accuracy of internally estimated proved reserves;	
		
•	the presence or recoverability of estimated oil and gas reserves;	
		
•	the ability to replace oil and gas reserves;	
		
•	the availability and costs of drilling rigs and other oilfield services;	
		
•	risks inherent in natural gas and oil drilling and production activities, including risks of fire, explosion, blowouts, pipe failure, casing collapse, unusual or unexpected formation pressures, environmental hazards, and other operating and production risks;	
		
•	delays in receipt of drilling permits;	
		
•	risks relating to the availability of capital to fund drilling operations that can be adversely affected by adverse drilling results, production declines and declines in natural gas and oil prices;	
		
•	risks relating to unexpected adverse developments in the status of properties;	
		
•	risks relating to the absence or delay in receipt of government approvals or other third party consents;	
		
•	environmental risks;	
		
•	exploration and development risks;	
		
•	competition;	
		
•	the inability to realize expected value from acquisitions;	
		
•	the availability and cost of alternative fuel sources;	
		
•	our ability to maintain the listing of our common stock on the NYSE American;	
		
•	our ability to meet the covenants in our loan agreements and the consequences of not meeting such covenants;	
		
•	the ability of our management team to execute its plans to meet its goals; and	
		
•	other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations and pricing.	

Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, please see “Risk Factors” in Item 1A of Part I of this report and in other sections of this Annual Report on Form 10-K.

Risks Related to the Company’s Business

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

As of December 31, 2017 , we had approximately $65.6 million outstanding under the Mauritius Commercial Bank Limited ("MCB") Finance Facility, $11.7 million outstanding under the James Street Capital Partners Limited, ("JSC") Note, $50.0 million outstanding in aggregate principal under the 2014 Convertible Subordinated Note, $48.5 million , net of discount, under our borrowing facility with Allied in the form of a convertible note (the "2015 Convertible Note"), $78.0 million , net of discount, under our credit facility (the "Term Loan Facility") with Zenith Bank PLC ("Zenith"), $24.9 million under our borrowing facility with Allied in the form of a promissory note (the "2011 Promissory Note"), and $6.4 million  under a Promissory Note agreement entered into with an entity related to the Company's majority shareholder (the "2016 Promissory Note") and we may incur additional indebtedness in the future. Our level of indebtedness has, or could have, important consequences to our business because:

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

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•	it may impair our ability to obtain additional financing in the future for acquisitions, capital expenditures or general corporate purposes;	
		
•	it may limit our flexibility in planning for, or reacting to, changes in our business and industry; and	
		
•	we may be substantially more leveraged than some of our competitors, which may place us at a relative competitive disadvantage and make us more vulnerable to downturns in our business, our industry or the economy in general.	

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

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

Events of default may occur under our outstanding promissory notes, credit agreements and financing agreements. If events of default occur or such holders of our indebtedness accelerate the repayment obligations thereunder as to matters not covered or no longer covered by the waivers, we may be forced to repay the obligations that become immediately due, which funds may not be available on commercially reasonable terms, if at all.

Allied, a related party, was the holder of each of the 2011 Promissory Note, the 2014 Convertible Subordinated Note, and the 2015 Convertible Note (collectively the "Related Party Notes"). In April 2017, Oltasho became the holder of each of the Related Party Notes. Each of the Related Party Notes contain certain default and cross-default provisions, including failure to pay interest and principal amounts when due and default under other indebtedness. As of December 31, 2017, the Company was not in compliance with certain default provisions of the Related Party Notes with respect to the payment of quarterly interest. Further, the risk of cross-default exists for each of the Related Party Notes if the holder of the Term Loan Facility exercises its right to terminate the Term Loan Facility and accelerate its maturity. In July 2017, Oltasho agreed to waive through their respective maturity dates its rights under all default provisions of each of the Related Party Notes.

For additional information regarding defaults, cross-defaults and potential cross-defaults, please see the discussion regarding each debt instrument in Note 8 - Debt to the Notes to Consolidated Financial Statements included herein. If any of our debt obligations are accelerated due to the events of default or future events of default or cross-defaults, we may not be able to repay the obligations that become immediately due and will have severe liquidity restraints.

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

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

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

The Company did not make the principal payment due and a portion of interest due on December 31, 2017. Also, on June 27, 2017, a vendor filed a suit against a wholly-owned subsidiary of the Company seeking an amount in excess of $10.0 million (see Note 10 - Commitments and Contingencies for further information). These constitute events of default under the MCB Finance Facility. The Company is currently in discussions with MCB on a revised principal repayment schedule. Our failure to make the required payments under the MCB Facility or the Term Loan Facility, or to comply with its applicable debt covenants could result in a default under the applicable facility and a cross-default under the other facility and the Related Party Notes

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(defined and described above under “ Note 8 - Debt - Long-Term Debt - Related Party ”, from the notes to the unaudited consolidated financial statements set forth under “ Part IV Exhibits, Financial Statements and Schedules” - “Item 15 - Notes to Consolidated Financial Statements ”), which could result in the acceleration of the payment of such indebtedness, termination of commitments to make further loans to us, prevention of our development drilling on the Oyo field and other operations, loss of our ownership interests in the secured properties or otherwise materially adversely affect our business, financial condition and results of operations. Also, if we are unable to service our debt obligations or obligations under our trade payables generally, Company may be unable to continue in its current state or continue to operate as a going concern.

We have potential significant liability associated with penalty and interest related to outstanding transactional tax obligations in Nigeria, which we have not accrued as of the date of this report.

Our operations and assets in Nigeria subject us to various Nigerian tax obligations, including the obligation to withhold taxes and pay value-added taxes, Nigerian Oil and Gas Industry Content Development Act (NCD) taxes, Cabotage (transportation) taxes, and Niger Delta Development Corporation taxes (NDDC). As of the date of this report, we have not accrued penalty and interest thereon; however, we believe that, based on our experience with local practices in Nigeria, the likelihood of being assessed penalty and interest is reasonably possible, with an estimated liability up to $27.4 million. As described above, this amount has not been accrued and is not included as a liability in the attached consolidated financial statements and in the event we are required to pay that amount, a significant portion thereof, or an amount greater than our estimates, it could have a material adverse effect on our cash flows, results of operations and liquidity and could cause the value of our securities to decline in value. Furthermore, the amount of assets and liabilities shown in the attached consolidated financial statements and our working capital associated therewith, would be materially different if such attached consolidated financial statements included an accrual for the amounts described above.

We owe certain obligations which are secured by a security interest in substantially all of our assets.
 
The stock of the Company’s subsidiary that holds the exploration licenses in The Gambia were pledged as collateral to secure the 2011 Promissory Note, pursuant to an Equitable Share Mortgage arrangement. Our senior lenders and note holders also hold security interests over certain other of our material assets. If an event of default occurs under our secured indebtedness, the holders of such indebtedness may enforce their security interests over our assets which secure the repayment of such obligations, and we could be forced to curtail or abandon our current business plans and operations. If that were to happen, any investment in us could become worthless.

We may be unable to continue as a going concern.

The Company has incurred losses from operations in each of the years ended December 31, 2017, 2016 and 2015. As of December 31, 2017, the Company's total current liabilities of $398.3 million exceeded its total current assets of $51.3 million , resulting in a working capital deficit of $347.0 million . Additionally, as mentioned in the risk factors above, we have substantial debt obligations and may not be able to maintain adequate liquidity throughout 2018. As a result, the Company’s consolidated financial statements included in this Annual Report on Form 10-K have been prepared under the assumption that it will continue as a going concern, which assumes the continuity of operations, the realization of assets and the satisfaction of liabilities as they come due in the normal course of business. Our consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Although the Company believes that it will be able to generate sufficient liquidity, its current circumstances raise substantial doubt about its ability to continue to operate as a going concern. If we become unable to continue as a going concern, we may have to liquidate our assets, and the values we receive for our assets in liquidation or dissolution could be significantly lower than the values reflected in our financial statements.

We may not be able to generate or obtain sufficient cash to service all of our indebtedness or trade payables, and we may be forced to take other actions to satisfy our obligations under our indebtedness and trade payables, which may not be successful.

We may be unable to generate sufficient cash flow from operations or to obtain alternative sources of financing in an amount sufficient to fund our liquidity needs or on favorable terms. Our operating cash inflows are typically used for capital expenditures, operating expenses, debt service costs and working capital needs.

As a result of the current low commodity prices and the Company’s low oil production volumes due to the shut-in of well Oyo-8 from September 2015 to May 2016 and the currently shut-in well Oyo 7, we have experienced a reduction in our available liquidity and we may not have the ability to generate sufficient cash flows from operations and, therefore, sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. As of December 31, 2017, we had available

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unrestricted cash of approximately $22.1 million and total current assets of approximately $51.3 million . Conversely, we had total current liabilities of $398.3 million , of which $277.4 million is accounts payable and accrued liabilities. Based upon the current commodity prices, we do not expect our cash flow from operations to be sufficient to repay our indebtedness or trade payables in the near term. We are currently evaluating strategic alternatives to address our liquidity issues and high debt levels. These efforts include, among others, i) obtaining additional funds from public or private financing sources, ii) restructuring existing debts from lenders, iii) obtaining forbearance of debt from trade creditors, iv) reducing ongoing operating costs, v) minimizing projected capital costs for the 2018 exploration and development campaign, vi) farming-out a portion of our rights to certain of our oil and gas properties, and vii) exploring potential business combination transactions. Sufficient liquidity may not be able to be raised from one or more of these actions and these actions may not be consummated within the period needed to meet future obligations.

We will continue to evaluate our ability to make debt payments in light of our liquidity constraints as we continue to explore various strategic initiatives. Any failure to make future principal or interest payments on our indebtedness or to cure any payment default within any applicable grace period may result in an event of default under the applicable debt agreement or instrument. As a result, if we are unable to service our debt obligations generally, and if we are unable to successfully refinance our debt obligations or effect a similar alternative transaction, the Company may not be able to continue in its current state and any investment in the Company may not retain any value.

Our business operations require substantial additional capital. If we are unable to raise additional capital on acceptable terms in the future, our ability to execute our business plan may be impaired.

The Company’s business operations require substantial capital from outside sources as well as from internally-generated sources. Although our majority shareholder has historically provided the Company with additional funding in the past, our majority shareholder may not provide any funds in the future or, if the funds are provided, the terms under which the funds are provided may not be favorable or acceptable to us. The Company’s ability to finance a portion of its working capital and capital expenditure requirements with cash flow from operations will be subject to a number of variables, such as:

•	the level of production from existing and new wells;	
		
•	the prices of oil and natural gas;	
		
•	the success and timing of the development of proved undeveloped reserves;	
		
•	remedial work undertaken to improve our well’s producing capability;	
		
•	the direct costs and general and administrative expenses of operations;	
		
•	reserves, including a reserve for the estimated costs of eventually plugging and abandoning our wells;	
		
•	indemnification obligations of the Company for losses or liabilities incurred in connection with the Company’s activities;	
		
•	general economic, financial, competitive, legislative, regulatory and other factors beyond the Company’s control; and	
		
•	our ability to farm-out portions of the Company’s rights under its various petroleum licenses.	

The significant decline in oil and natural gas prices as well as our substantial indebtedness and general lack of liquidity may make it more difficult for us to obtain additional financing. The Company might not generate or sustain cash flows at sufficient levels to finance its business activities. When and if the Company generates significant revenues, if such revenues were to decrease due to lower oil prices, decreased production or other factors, and if the Company were unable to obtain capital through reasonable financing arrangements, its ability to execute its business plan would be limited, and it could be required to discontinue operations.

The Company may continue to incur losses for a significant period of time and may not be able to achieve profitability.

In addition to our interests in the OMLs, including the Oyo field, we have signed production sharing contracts in Kenya, two exploration licenses in The Gambia and a petroleum agreement in Ghana. As we are still in the early stages of exploration and have yet to drill on our Gambian, and Ghanaian blocks, we expect to continue to incur significant expenses relating to our identification of drilling prospects and investment costs relating to exploration activities in the foreseeable future. Additionally, fixed commitments, including salaries and fees for employees and consultants, rent and other contractual commitments may be substantial and are likely to increase as exploration drilling is scheduled and personnel are retained. Drilling projects generally require a significant period of time before they produce resources and generate profits. Our production in the Oyo field may or may not result in net earnings in excess of our losses on other ventures under development or in the start-up phase. We may not achieve or sustain profitability on a quarterly or annual basis, or at all.

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The geographic concentration of our properties offshore Nigeria, The Gambia and Ghana subjects us to an increased risk of loss of revenue or curtailment of production from factors specifically affecting offshore Nigeria, The Gambia and Ghana.

Our properties are concentrated in three countries: Nigeria, The Gambia and Ghana, and all of the value of our production and reserves is concentrated in a single oilfield offshore Nigeria. Any failure to sustain production, production problems or reduction in reserve estimates related to the Oyo field would adversely impact our business.  In addition, some or all of these properties could be affected should such regions experience:

•	severe weather or natural disasters;	
		
•	moratoria on drilling or permitting delays;	
		
•	delays in or the inability to obtain regulatory approvals;	
		
•	delays or decreases in production;	
		
•	delays or decreases in the availability of drilling rigs and related equipment, facilities, personnel or services;	
		
•	delays or decreases in the availability of the capacity to transport, gather or process production; and/or	
		
•	changes in the regulatory, political and fiscal environments.	

We maintain insurance coverage for only a portion of these risks. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. We do not carry business interruption insurance.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

The loss of key employees could adversely affect the Company’s ability to operate.

The Company believes that its success depends on the continued service of its key employees, as well as the Company’s ability to hire additional key employees, as needed. Each of the Company’s key employees has the right to terminate his/her employment at any time without penalty under his/her employment agreement. The unexpected loss of the services of any of these key employees, or the Company’s failure to find suitable replacements within a reasonable period of time thereafter, could have a material adverse effect on the Company’s ability to execute its business plan and, therefore, on its financial condition and results of operations.

Our failure to effectively execute our exploration and development projects could result in significant delays and/or cost over-runs, including the delay of any future production, which could negatively impact our operating results, liquidity and financial position.

We currently have a number of exploration projects, all of which are in the early stages of the project development life-cycle, in addition to our Oyo field development project. Our exploration projects will require substantial additional evaluation and analysis, including drilling and, in the event a commercial discovery occurs, the expenditure of substantial amounts of capital, prior to preparing a development plan and seeking formal project sanction. First production from these exploration projects, in the event a discovery is made, is not expected for several years. Our Oyo field development project and some of our exploration projects are located in challenging deepwater environments and may entail significant technical challenges, including subsea tiebacks to a floating, production, storage and offloading vessel or production platform, pressure maintenance systems, gas re-injection systems, and other specialized infrastructure.

This level of development activity and complexity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. In addition, we have increased dependency on third-party technology and service providers and other supply chain participants for these complex projects. We may not be able to fully execute these projects due to:

•	our inability to obtain sufficient and timely financing;	
		
•	our inability to attract and/or retain a sufficient quantity of personnel with the skills required to bring these complex projects to production on schedule and on budget;	
		
•	significant delays in the delivery of essential items or performance of services, cost overruns, supplier insolvency, or other critical supply failure could adversely affect project development;	
		
•	lack of partner or government approval for projects;	

17

		
•	civil disturbances, anti-development activities, legal challenges or other interruptions which could prevent access; and	
		
•	drilling hazards or accidents or natural disasters.	

We may not be able to compensate for, or fully mitigate, these risks.

The Company’s failure to capitalize on existing petroleum agreements could result in an inability by the Company to generate sufficient revenues and continue operations.

The Company has a 100% economic interest in, and operatorship of, the OMLs in Nigeria, including the Oyo field. The Company has also entered into definitive petroleum agreements with Kenya, The Gambia, and Ghana. The Company’s business strategy includes spreading the risk of oil and natural gas exploration, development and drilling, and ownership of interests in oil and natural gas properties by participating in multiple projects and joint ventures. Failure by the Company to capitalize on its existing contracts could have a material adverse effect on the Company’s business and results of operations.

Under the terms of our various petroleum agreements and leases, we are required to drill wells, declare any discoveries, conduct certain development activities and make certain payments in order to retain exploration and production rights, and our failure to do so may result in substantial license renewal costs or penalties or loss of our interests in the undeveloped parts of our license areas.

In order to protect our exploration and production rights in our license areas, we must meet various drilling, declaration and payment requirements. In general, unless we make and declare discoveries within certain time periods specified in our various petroleum agreements and leases, our interests in the undeveloped parts of our license areas may lapse and we may be subject to significant penalties or be required to make additional payments in order to maintain such licenses. We may not receive an extension of the relevant exploration periods for any of our prospects and the terms of the extensions may be on unfavorable terms. Additionally, these agreements require us to make certain payments, including royalty payments, training fee payments and other payments, to our counterparties. A failure to make such payments, even if subject to dispute, may result in significant penalties being imposed on us and the possible loss of exploration and production rights under the applicable agreement. Such penalties and losses of rights could have a material adverse effect on our business and results of operations.

Our proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves . Of our total estimated proved reserves at December 31, 2017 , 7.1 million Bbls may ultimately be less than currently estimated.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities. In the case of production sharing contracts, the quantities allocable to a part-interest owner’s share are affected by the assumptions of that owner’s future participation in funding of operating and capital costs. Actual future production, prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from estimates. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed. In addition, estimates of proved reserves reflect production history, results of exploration and development, prevailing prices and other factors, many of which are beyond our control. Due to the limited production history, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

Our exploration projects remain subject to varying degrees of additional evaluation, analysis and partner and regulatory approvals prior to official project sanction and production.

A discovery made by the initial exploration well on a prospect does not ensure that we will ultimately develop or produce hydrocarbons from such prospect or that a development project will be economically viable or successful. Following a discovery by an initial exploration well, substantial additional evaluation, analysis, expenditure of capital and partner and regulatory approvals will need to be performed and obtained prior to official project sanction and development, which may include (i) the drilling of appraisal wells, (ii) the evaluation and analysis of well logs, reservoir core samples, fluid samples and the results of production tests from both exploration and appraisal wells, and (iii) the preparation of a development plan which includes economic assumptions on future oil and gas prices, the costs of drilling development wells, and the construction or leasing of offshore production facilities and transportation infrastructure. Regulatory approvals are also required to proceed with certain development plans.

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Any of the foregoing steps of evaluation and analysis may render a particular development project uneconomic, and we may ultimately decide to abandon the project, despite the fact that the initial exploration well, or subsequent appraisal or development wells, discovered hydrocarbons. We may also decide to abandon a project based on forecasted oil and gas prices or the inability to obtain sufficient financing. We may not be successful in obtaining partner or regulatory approvals to develop a particular discovery, which could prevent us from proceeding with development and ultimately producing hydrocarbons from such discovery, even if we believe a development would be economically successful.

Our current operations are subject to, and our future operations will be subject to, climate change and greenhouse gas restrictions.

Due to concern over the risk of climate change, a number of countries have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These include adoption of cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon sources such as natural gas. Current and pending greenhouse gas regulations may also increase our compliance costs, such as for monitoring or sequestering emissions.

The Company’s oil and gas operations are subject to various risks beyond the Company’s control.

The Company expects to produce, transport and market potentially toxic materials and purchase, handle and dispose of other potentially toxic materials in the course of its business. The Company’s operations will produce byproducts, which may be considered pollutants. Any of these activities could result in liability, either as a result of an accidental, unlawful discharge or as a result of new findings on the effects of the Company’s operations on human health or the environment. Additionally, the Company’s oil and gas operations may also involve one or more of the following risks:

•	fires and explosions;	
		
•	blow-outs and oil spills;	
		
•	pipe or cement failures and casing collapses;	
		
•	uncontrollable flows of oil, gas, formation water, or drilling fluids;	
		
•	embedded oilfield drilling and services tools;	
		
•	abnormally pressured formations;	
		
•	natural disaster;	
		
•	vandalism and terrorism; and	
		
•	environmental hazards.	

In the event that any of the foregoing events occur, the Company could incur substantial losses that may not be covered by insurance or that may exceed our insurable limits as a result of (i) injury or loss of life; (ii) severe damage or destruction of property, natural resources or equipment; (iii) pollution and other environmental damage; (iv) investigatory and clean-up responsibilities; (v) regulatory investigation and penalties; (vi) suspension of its operations; or (vii) repairs to resume operations. If the Company experiences any of these problems, its ability to conduct operations could be adversely affected. Additionally, offshore operations are subject to a variety of risks, such as capsizing, collisions and damage or loss from typhoons or other adverse weather conditions. These conditions could cause substantial damage to facilities and interrupt production.

The Company is dependent on others for the storage and transportation of all of its oil and gas which could result in significant operational costs to the Company and depletion of capital and may expose us to financial loss and reputation harm.

The Company does not own any storage or transportation facilities and, therefore, will depend upon third parties to store and transport all of its oil and gas resources when and if produced. The Company will likely be subject to price changes and termination provisions in any contracts it may enter into with these third-party service providers. The Company may not be able to identify such third parties for any particular project. Even if such sources are initially identified, the Company may not be able to identify alternative storage and transportation providers in the event of contract price increases or termination. In the event the Company is unable to find acceptable third-party service providers, it would be required to contract for its own storage facilities and employees to transport the Company’s resources. The Company may not have sufficient capital available to assume these obligations, and its inability to do so could result in the cessation of its business.

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Additionally, our oil and gas transportation involve marine, land and pipeline transportation, which are subject to hazards such as capsizing, collision, acts of piracy and damage or loss from severe weather conditions, explosions, oil and gas spills and leakages. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations, risk of financial loss and reputation harm. We may not be insured against all of these risks and uninsured losses and liabilities arising from these hazards could reduce the funds available to us for financing, exploration and investment, which may have a material adverse effect on our business, financial condition and results of operations.

Drilling wells is speculative, often involving significant costs that may be greater than our estimates and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

Exploring for and developing oil reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating exploration, appraisal and development wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploration wells bear a much greater risk of financial loss than development wells. In the past, we have experienced unsuccessful drilling efforts. Moreover, the successful drilling of an oil well does not necessarily result in a profit on investment. A variety of factors, both geological and market-related, can cause a well or an entire development project to become uneconomic or only marginally economic. Our initial drilling sites, and any potential additional sites that may be developed, require significant additional exploration and appraisal, regulatory approval and commitments of resources prior to commercial development. We face additional risks due to i) a general lack of infrastructure in areas in which we operate, ii) underdeveloped oil and gas industries in areas in which we operate, and iii) increased transportation expenses due to geographic remoteness. Thus, this may require either a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development of a commercially viable field and/or for our exploration activities to be profitable. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

We contract with third parties to conduct drilling and related services on our development and exploration prospects for us. Such third parties may not perform the services they provide us on schedule or within budget. The decline in oil and gas prices may have an adverse impact on certain third parties from which we contract drilling, development and related oilfield services, which in turn could affect such companies' ability to perform such services for us and result in delays to our exploration, appraisal and development activities. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with are highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and may result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business, financial position and results of operations.

An interruption in the supply of materials, resources or services, including storage and transportation of oil and gas, could limit the Company’s operations and cause unprofitability.

The Company obtains, and will need to obtain in the future, materials, resources and services, including, but not limited to, specialized chemicals, specialty muds, drilling fluids, pipe, drill-string and geological and geophysical mapping and interpretation services to carry out its operations. There may be only a limited number of manufacturers and suppliers of these materials, resources and services. Additionally, these manufacturers and suppliers may experience difficulty in supplying such materials, resources and services to the Company sufficient to meet its needs or may terminate or fail to renew contracts for supplying these materials, resources or services on terms the Company finds acceptable including, without limitation, acceptable pricing terms.

The Company does not presently carry business interruption insurance policies in Africa and will be at risk of incurring business interruption loss due to political unrest, theft, accidents or natural disasters.

The Company does not presently carry any policies of insurance in Africa to help protect itself from interruptions to its business. In the event that the Company were to incur business interruption losses with respect to one or more incidents, this could adversely affect its operations, and it may not have the necessary capital to maintain business operations.

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Our business partner, CEHL, is a related party, and our former executive chairman and former CEO is a principal owner and one of the directors of CEHL, which may result in real or perceived conflicts of interest.

Dr. Lawal, the Company’s former Executive Chairman of the Board of Directors and former Chief Executive Officer, who retired from the Company in May 2016, is a director of each of CEHL and Allied, entities constituting the CEHL Group. Further, Dr. Lawal owns 27.7% of CAMAC International Limited, which indirectly owns 100% of CEHL. Allied is a wholly-owned subsidiary of CEHL. The holder of our 2016 Promissory Note is a subsidiary of CAMAC International Limited. As a result, Dr. Lawal may be deemed to have an indirect material interest in any transactions with CEHL including the agreements entered into with CEHL in April 2010, the OMLs transaction, the 2011 Promissory Note, the 2014 Convertible Subordinated Note, the 2015 Convertible Note, each of which promissory notes were subsequently assigned to Oltasho, and the 2016 Promissory Note (see Note 8. - Debt to the Notes to Consolidated Financial Statements for further information regarding the 2011 Promissory Note, the 2014 Convertible Subordinated Note and the 2015 Convertible Note, and the 2016 Promissory Note) and the Transfer Agreement with Allied. These relationships may result in conflicts of interest. Although processes and procedures are in place within the Company to guard against such potential conflicts of interest, we may not be able to prove that these agreements are equivalent to arm’s length transactions. Should our transactions not provide the value equivalent of arm’s length transactions or there is a perception in the market place that conflicts of interest exist, our results of operations may suffer, our stock price may decline in value and we may be subject to costly shareholder litigation.

If CEHL, our former majority shareholder, is unable to retain and hold rights to a production sharing contract, which we have previously been provided the rights to, it could have a material adverse effect on our results of operations and financial condition and the value of our securities.

In November 2013, we entered into a Transfer Agreement with certain parties including CEHL, our former majority shareholder, pursuant to which, among other things, we agreed to acquire Allied’s remaining economic interests in a production sharing contract (the “PSC”) pertaining to the OMLs located offshore Nigeria (which were later assigned from Allied to CEHL). The Transfer Agreement provided that if Allied/CEHL could not assign any of its rights, title or interest in the PSC and/or certain other contracts agreed to be transferred to the Company pursuant to the Transfer Agreement, to the Company, that Allied/CEHL, would retain and hold such right, title and interest for the benefit of the Company. To date, the PSC and various agreements associated therewith, have not been formally assigned to the Company and are held by CEHL for the Company’s benefit. Because the Company has no control over CEHL’s compliance with the terms of such agreements, and/or its ability to retain the rights thereunder, CEHL, and therefore the Company, may lose the rights to such agreements and/or the benefits therefrom. The loss of the rights or benefits of the PSC and related agreements would have a material adverse effect on the Company’s results of operations and financial condition and could cause the value of the Company’s securities to decline in value or become worthless.

Applicable Nigerian income tax rates could adversely affect the value of the OMLs, including the Oyo field.

Income derived from our contractual interests in the Oyo field, and EPNL, as acquiring subsidiary in the transactions through which we obtained these contractual interests, are subject to the jurisdiction of the Nigerian taxing authorities. The Nigerian government applies different petroleum profit tax rates upon income derived from Nigerian oil operations ranging from 50% to 85% based on a number of factors. The final determination of the tax liabilities with respect to the OMLs involves the interpretation of local tax laws and related authorities. In addition, changes in the operating environment, including changes in tax law and currency/repatriation controls, could impact the determination of tax liabilities with respect to the OMLs for a tax year. While we believe the petroleum profit tax rate applicable to the OMLs is 50%, the actual applicable rate could be higher, which could result in a material decrease in the profits allocable to the Company under the OMLs.

The passage into law of the Nigerian Petroleum Industry Bill could create additional fiscal and regulatory burdens on the parties to the OMLs, which could have a material adverse effect on the profitability of the production.

A Petroleum Industry Bill (“PIB”) is currently undergoing legislative review at the Nigerian National Assembly. The draft PIB seeks to introduce significant changes to legislation governing the oil and gas sector in Nigeria, including new fiscal regulatory and tax obligations and expanded fiscal and regulatory oversight that may impose additional operational and regulatory burdens on the Company and impact the economic benefits anticipated by the Company. Any such fiscal and regulatory changes could have a negative impact on the profits allocable to the Company under the OMLs.

The Oyo field is subject to the volatility of the Nigerian Government.

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The government of Nigeria has historically experienced volatility, which is out of management’s control. The Company’s ability to exploit its interests in Nigeria may be adversely impacted by unanticipated governmental action. The future success of the Company’s Oyo field interest may also be adversely affected by risks associated with international activities, including economic and labor conditions, political instability, risk of war, expropriation, repatriation, termination, renegotiation or modification of existing contracts, tax laws (including host-country import-export, excise and income taxes and United States taxes on foreign subsidiaries) and changes in the value of the U.S. dollar versus the local currencies in which future oil and gas producing activities may be denominated. Changes in exchange rates may also adversely affect the Company’s future results of operations and financial condition.  Realization of any of these factors could materially and adversely affect our financial position, results of operations and cash flows.

The OMLs are located in an area where there are high security risks which could result in harm to the Oyo field operations, our employees and contractors and our interest in the Oyo field and the remainder of the OMLs.

There are risks inherent to oil production in Nigeria. The Oyo field is located approximately 75 kilometers (46 miles) off the Nigerian coast in deep water. Despite undertaking various security measures and being situated 75 kilometers offshore the Nigerian coast, the FPSO vessel currently being used for storing petroleum production in the Oyo field may become subject to terrorist acts and other acts of hostility like piracy. Such actions could adversely impact our overall business, financial condition and operations. Our facilities, employees and contractors are subject to these substantial security risks and our financial condition and results of operations may materially suffer as a result. Terrorist acts and regional hostilities around the world in recent years have led to increases in insurance premium rates and the implementation of special “war risk” premiums for certain areas. Such increases in insurance rates may adversely affect our profitability with respect to the Oyo field asset. Moreover, we operate in a sector of the economy that is likely to be adversely impacted by the effects of political instability, terrorist or other attacks, war or international hostilities.

Maritime disasters and other operational risks may adversely impact our financial condition and results of operations.

The operation of the FPSO vessel has an inherent risk of maritime disaster, environmental mishaps, cargo and property losses or damage and business interruptions caused by, among others:

•	mechanical failure and dry dock repairs;	
		
•	vessel off-hire periods and labor strikes;	
		
•	human error and adverse weather; and	
		
•	political action, civil conflict, terrorism and piracy on the way to the operation site, in the vessel's home country or operation site or to the vessel's supply.	

Any of these circumstances could adversely affect the operation of the FPSO vessel and result in loss of revenues or increased costs and adversely affect our revenues and prospects.

The threat and impact of terrorist attacks, cyber attacks or similar hostilities may adversely impact our operations.

We cannot assess the extent of either the threat or the potential impact of future terrorist attacks on the energy industry in general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such hostilities may affect our operations in unpredictable ways, including the possibility that infrastructure facilities, including pipelines and gathering systems, production facilities, drilling rigs, processing plants and refineries, could be targets of, or indirect casualties of, an act of terror, a cyber attack or electronic security breach, or an act of war.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

The rate of production from our oil and natural gas properties will decline as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in (a) efficiently developing and exploiting our current reserves on properties owned by us or by other persons or entities, and (b) economically finding or acquiring additional oil and natural gas producing properties. In the future, we may have difficulty acquiring new properties. During periods of low oil and/or natural gas prices, it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our production, our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

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We may purchase oil and natural gas properties with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every property, and we may not be able to observe environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our business, financial condition and results of operations could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.

We may incur losses or costs as a result of title deficiencies in the properties in which we invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the property, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our business, financial condition and results of operations.

The calculated present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net cash flows as included in our public filings is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:

	
			
 	•	actual prices we receive for oil and natural gas;	
 	 	 	
 	•	actual cost and timing of development and production expenditures;	
 	 	 	
 	•	the amount and timing of actual production; and	
 	 	 	
 	•	changes in governmental regulations or taxation.	

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.

Competition in the oil and natural gas industry is intense, making it difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial

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or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition and results of operations.

Our competitors may use superior technology and data resources that we may be unable to afford or that would require a costly investment by us in order to compete with them more effectively.

Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.

SEC rules could limit our ability to book additional proved undeveloped reserves (“ PUDs ”) in the future.

SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.

Risks Related to the Company’s Industry

The decline in oil and natural gas prices may adversely affect our business, financial condition and results of operations.

Oil and gas prices are in the midst of a severe and prolonged downturn although a limited recovery in prices has occurred since late 2016. The significant decline in oil and gas prices since mid-2014 has had, and will continue to have, a significant adverse effect on our business, results of operations, liquidity and the market price of our common stock. The prices received for the Oyo field production will heavily influence our revenue, net income or loss, access to capital and future rate of growth. Oil is a commodity, and its price is subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil has been volatile. The oil market will likely continue to be volatile in the future. The prices received and the levels of production depend on numerous factors beyond our control. These factors include:

•	global economic conditions;	
		
•	changes in global supply of and demand for oil or natural gas;	
		
•	actions of the Organization of Petroleum Exporting Countries (OPEC) with respect to production levels and pricing;	
		
•	price and quantity of imports of foreign oil;	
		
•	local and international political, economic and weather conditions;	
		
•	political and military conflicts in oil producing regions or other geographical areas or acts of terrorism in the U.S. or elsewhere;	
		
•	domestic and international relations, regulations and tax policies;	
		
•	effects from the actions of other oil producing countries;	
		
•	global oil exploration and production levels;	
		
•	global oil inventory levels;	
		
•	the development, exploitation, price and availability of alternative fuels;	
		
•	reduction in energy consumption due to technological advances;	
		
•	speculation by investors in oil and gas; and	
		
•	proximity and capacity of transportation pipelines and facilities.	

Significant and prolonged declines in crude oil and natural gas prices, such as the decline we are currently experiencing, may have the following effects on our business:

•	limiting our financial condition, liquidity and/or ability to fund planned capital expenditures and operations;	
		
•	reducing the amount of crude oil and natural gas that we can produce economically;	

24

		
•	causing us to delay or postpone some of our capital projects;	
		
•	reducing our revenues, operating income and cash flows;	
		
•	limiting our access to sources of capital, such as equity and long-term debt;	
		
•	reducing the carrying value of our crude oil and natural gas properties; and/or	
		
•	reducing the market price of our common stock.	

The Company may not be successful in finding, acquiring, or developing sufficient petroleum reserves, and a failure to do so could materially adversely affect our financial position, liquidity and ability to continue operations.

The Company operates solely in the petroleum extraction business; therefore, if it is not successful in finding crude oil and natural gas sources with good prospects for future production, and exploiting such sources, its business will not be profitable and it may be forced to terminate its operations. Exploring and exploiting oil and gas or other sources of energy entails significant risks, which risks can only be partially mitigated by technology and experienced personnel. The Company or any venture it acquires or participates in may not be successful in finding petroleum or other energy sources, or if it is successful in doing so, the Company may not be successful in developing such resources and producing quantities sufficient to permit the Company to conduct profitable operations. The Company’s future success will depend in large part on the success of its drilling programs and creating and maintaining an inventory of projects. Creating and maintaining an inventory of projects depends on many factors, including, among other things, obtaining rights to explore, develop and produce hydrocarbons in promising areas, drilling success, an ability to bring long lead-time, capital intensive projects to completion on budget and schedule and efficient and profitable operation of mature properties. The Company’s inability to successfully identify and exploit crude oil and natural gas sources would have a material adverse effect on its business and results of operations and could result in the cessation of its business operations.

In addition to the numerous operating risks described in more detail in this report and our other filings with the SEC, exploration and exploitation of energy sources involve the risk that no commercially productive oil or gas reservoirs will be discovered or, if discovered, that the cost or timing of drilling, completing and producing wells will not result in profitable operations. The Company’s drilling operations may be curtailed, delayed or abandoned as a result of a variety of factors, including:

•	adverse weather conditions;	
		
•	unexpected drilling conditions;	
		
•	irregularities in formations;	
		
•	pressure irregularities;	
		
•	equipment failures or accidents;	
		
•	inability to comply with governmental requirements;	
		
•	shortages or delays in the availability of drillings rigs;	
		
•	shortages or delays in the availability of other oilfield equipment and services; and	
		
•	shortages or unavailability of qualified labor to complete the drilling programs according to our business plan schedule.	

Our offshore production and exploration activities will involve special risks that could adversely affect operations.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt our operations. As a result, we could incur substantial expenses that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in the loss of equipment and properties.

Deepwater exploration and production generally involves greater operational and financial risks than drilling on the continental shelf or onshore. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Such risks are particularly applicable to our deepwater operations in the Oyo field. In addition, there may be production risks of which we are currently unaware. Whether we use existing pipeline infrastructure, participate in the development of new subsea infrastructure or use floating production systems to transport oil from producing wells, if any, these operations may require substantial time for installation, or encounter mechanical difficulties and equipment failures that could result in significant cost overruns and delays. Furthermore, operations in frontier areas generally lack the physical and oilfield service infrastructure present in more mature basins. As a result, a significant amount of time may elapse between a discovery and the marketing of the associated hydrocarbons, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of this infrastructure, oil and gas discoveries we make in the deepwater, if any, may never be economically producible.

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In addition, in the event of a well control incident, containment and, potentially, cleanup activities for offshore drilling are costly. The resulting regulatory costs or penalties, and the results of third party lawsuits, as well as associated legal and support expenses, including costs to address negative publicity, could well exceed the actual costs of containment and cleanup. As a result, a well control incident could result in substantial liabilities for us, and have a significant negative impact on our earnings, cash flows, liquidity, financial position, and stock price, the result of which could force us to seek bankruptcy protection.

The energy market in which the Company operates is highly competitive.

Competition in the oil and gas industry is intense, particularly with respect to access to drilling rigs and other services, the acquisition of properties and the hiring and retention of technical personnel. The Company expects competition in the market to remain intense because of the increasing global demand for energy, and that competition will increase significantly as new companies enter the market and current competitors continue to seek new sources of energy and leverage existing sources. Many of the Company’s competitors, including large oil companies, have an established presence in the areas that we do business and have longer operating histories, significantly greater financial, technical, marketing, development, extraction and other resources and greater name recognition than the Company does. As a result, they may be able to respond more quickly to new or emerging technologies, changes in regulations affecting the industry, newly discovered resources and exploration opportunities, as well as to large swings in oil and natural gas prices. In addition, increased competition could result in lower energy prices, reduced margins and loss of market share, any of which could harm the Company’s business. Furthermore, increased competition may harm the Company’s ability to secure ventures on terms favorable to it and may lead to higher costs and reduced profitability, which may seriously harm its business.

Hedging transactions may limit the Company’s potential gains and increase the Company’s potential losses.

To date, the Company has not entered into any hedging transactions but may do so in the future. In the event that the Company chooses not to hedge its exposure to reductions in oil and gas prices, it could be subject to significant reduction in prices which could have a material adverse impact on its results of operations and profitability. Alternatively, the Company may elect to enter into hedging transactions with respect to a portion of its production to achieve more predictable cash flow and to reduce its exposure to price fluctuations. The use of hedging transactions could limit future revenues from price increases and could expose the Company to adverse changes in basis risk, the relationship between the price of the specific oil or gas being hedged and the price of the commodity underlying the futures contracts or other instruments used in the hedging transaction. Hedging transactions also involve the risk that the counterparty does not satisfy its obligations.

The Company may be required to take non-cash asset write-downs.

Under applicable accounting rules, during 2017, 2016 and 2015, the Company recorded an impairment charge of $78.7 million , $0.6 million and $261.2 million, respectively. The 2017 and 2015 write offs were mainly due to the carrying value of the oilfield assets not being recoverable under the then current market conditions. The 2016 write-off is related to the carrying value of its offshore leases in Kenya because the Company no longer intends to renew or extend its leases on these offshore blocks. The Company may record additional impairment charges in future periods if oil and natural gas prices do not recover or if there are substantial downward adjustments to its estimated proved reserves, increases in its estimates of development costs or deterioration in its exploration results. Accounting standards require the Company to review its long-lived assets for possible impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable over time. In such cases, if the asset’s estimated undiscounted future net cash flows are less than its carrying amount, impairment exists. Any impairment write-down, which would equal the excess of the carrying amount of the assets being written down over their estimated fair value, would have a negative impact on the Company’s earnings, which could be material.

Cyber incidents may adversely impact our operations.

We have become increasingly dependent upon digital technologies to operate our exploration, development and production business. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and communicate with our employees and third-party partners. Unauthorized access to our non-public seismic data, reserves information or other proprietary information could lead to a decrease in our competitiveness, data corruption, communication interruption or other operational disruptions in our exploration or production operations. Also, nearly all of the oil and gas distribution systems in the world are dependent on digital technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure or the systems or infrastructure of third parties could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery

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of oil or natural gas, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. We have not suffered any material losses relating to such attacks to date; however, we may suffer material losses in the future. Although historically we have not incurred material expenditures for protective measures related to potential cyber-attacks, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities we have to cyber-attacks.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation and the availability and cost of credit have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the global economic climate continues to deteriorate, demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

Risks Related to International Operations

The Company’s international operations subject it to certain risks inherent in conducting business in Sub-Saharan Africa, including political instability and foreign government regulation, which could significantly impact the Company’s ability to operate in such countries and materially impact the Company’s results of operations.

The Company conducts substantially all of its business in Sub-Saharan Africa. The Company’s present and future international operations in foreign countries are, and will be, subject to risks generally associated with conducting businesses in foreign countries, such as:

•	laws and regulations that may be materially different from those of the United States;	
		
•	changes in applicable laws and regulations;	
		
•	challenges to or failure of title;	
		
•	labor and political unrest;	
		
•	currency fluctuations;	
		
•	changes in economic and political conditions;	
		
•	export and import restrictions;	
		
•	tariffs, customs, duties and other trade barriers;	
		
•	difficulties in staffing and managing operations;	
		
•	longer time period and difficulties in collecting accounts receivable and enforcing agreements;	
		
•	possible loss of properties due to nationalization or expropriation; and	
		
•	limitations on repatriation of income or capital.	

Specifically, foreign governments may enact and enforce laws and regulations requiring increased ownership by businesses and/or state agencies in energy producing businesses and the facilities used by these businesses, which could adversely affect the Company’s ownership interests in its then existing ventures. The Company’s ownership structure may not be adequate to accomplish the Company’s business objectives in Nigeria or in any other foreign jurisdiction where the Company may operate. Foreign governments also may impose additional taxes and/or royalties on the Company’s business, which would adversely affect the Company’s profitability and value of its foreign assets, including its interests in the OMLs. In certain locations, governments have imposed restrictions, controls and taxes, and in others, political conditions exist that may threaten the safety of employees and the Company’s continued presence in those countries. Internal unrest, acts of violence or strained relations between a foreign government and the Company or other governments may adversely affect its operations. These developments may, at times, significantly affect the Company’s results of operations and must be carefully considered by its management when evaluating the level of current and future activity in such countries.

The future success of the Company’s operations may also be adversely affected by risks associated with international activities, including economic and labor conditions, political instability, risk of war, nationalization or other expropriation of private enterprises, repatriation, termination, renegotiation or modification of existing contracts, tax laws (including host-country import-

27

export, excise and income taxes and United States taxes on foreign subsidiaries), restrictions on currency conversion, devaluations of currency, restrictions or prohibitions on dividend payments to stockholders or changes in government policies, laws or regulations. For example, the Nigerian government has implemented certain control measures with regards to the quarterly exportation and sale of crude oil products from Nigeria. Accordingly, petroleum producers are required to obtain export permits quarterly for crude oil liftings. During the period from May to September 2015, the Company produced approximately 1.5 million Bbls of crude oil but only sold approximately 0.6 million Bbls due to unexpected delays in the issuance of export permits for the quarter ending September 30, 2015. Realization of any of these factors could materially and adversely affect our financial position, results of operations and cash flows and result in the loss of all or substantially all of the Company’s assets or in a total loss of your investment in the Company.

We are subject to extensive environmental regulations.

Our operations are subject to extensive national, state and local environmental regulations. Environmental rules and regulations cover oil exploration and development activities as well as transportation, refining and production activities. These regulations establish, among others, quality standards for hydrocarbon products, air emissions, water discharges and waste disposal, environmental standards for abandoned crude oil wells, remedies for soil, water pollution and the general storage, handling, transportation and treatment of hydrocarbons. Non-compliance with environmental laws may result in fines, restrictions on operations or other sanctions. We are also subject to state and local environmental regulations issued by the regional environmental authorities, which oversee compliance with each state’s environmental laws and regulations by oil and gas companies. If we fail to comply with any of these national or local environmental regulations we could be subject to administrative and criminal penalties, including warnings, fines and facilities closure orders.

In Nigeria, where we are currently producing, environmental regulations will substantially impact our operations and business results as a result of the creation of the Federal Ministry of Environment (“FME”) in 1999 and the enactment of more rigorous laws, such as the Environmental Guidelines and Standards for the Petroleum Industry in Nigeria (EGASPIN) 2002. Under the Environmental Impact Assessment Act of 1992, all exploratory project drilling must have an environmental impact assessment approved by the FME and must receive an environmental permit from the local authorities. We are required to prevent the escape of petroleum into any water, well, spring, stream river, lake reservoir, estuary or harbor, and government inspectors may examine our premises to ensure that we comply with the regulations. The Department of Petroleum Resources also regulates environmental issues by requiring operators in the oil and gas industry to obtain permits for oil-related effluent discharges from point sources and oil-related project development.

Compliance and enforcement of environmental laws and regulations, including those related to climate change, may affect operations and cause the Company to incur significant expenditures.

Extensive national, regional and local environmental laws and regulations in Africa are expected to have a significant impact on the Company’s operations. These laws and regulations set various standards regulating certain aspects of health and environmental quality, which provide for user fees, penalties and other liabilities for the violation of these standards. As new environmental laws and regulations are enacted and existing laws are repealed, interpretation, application and enforcement of the laws may become inconsistent. Compliance with applicable local laws in the future could require significant expenditures, which may adversely affect the Company’s operations. The enactment of any such laws, rules or regulations in the future may have a negative impact on the Company’s projected growth, which could decrease projected revenues or increase costs. In addition, non-governmental organizations concerned with the environment may take an interest in the Company’s operations and attempt to disrupt or halt operations in areas deemed environmentally sensitive. The Company’s response to these efforts could require unforeseen expenditures, cause delays in execution, and affect operations.

We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act, which could have a material adverse effect on our business, and the continued existence of official corruption and bribery in Africa, and the inability or unwillingness of authorities to combat such corruption, may negatively impact our ability to fairly and effectively compete.

We are subject to the U.S. Foreign Corrupt Practices Act (“FCPA”) and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business. We do business and may do additional business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, or private entities. Thus, we face the risk of unauthorized payments or offers of payments by one of our employees or consultants, given that these parties may not always be subject to our control. Our existing safeguards and any future improvements may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible. In the future, we may be partnered with other companies with

28

whom we are unfamiliar. Violations of the FCPA may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition.

Official corruption and bribery remains a serious concern in Sub-Saharan Africa. For example, the 2016 Transparency International report ranked Nigeria 136 out of 176 countries in terms of corruption perceptions. In an attempt to combat corruption in the oil and gas sector, the National Assembly passed the Nigeria Extractive Industries Transparency Initiative Act 2007. This action permitted Nigeria to become a candidate country under the Extractive Industries Transparency Initiative (“EITI”), the first step in bringing transparency to all material oil, gas and mining payments to the Nigerian government. In addition, Nigeria has amended its banking laws to permit the government to bring corrupt bank officials to justice. Several notable cases have been brought, but, to date, few significant cases have been successful and bank regulatory oversight remains a concern. Thus, increased diligence may be required in working with or through Nigerian banks or with Nigerian governmental authorities, and interactions with government officials may need to be monitored. To the extent that such efforts to increase transparency are unsuccessful, and competitors utilize the existence of corruptive practices in order to secure an unfair advantage, our financial condition and results of operations may suffer.

A deterioration of relations between the United States and Nigeria or other African governments could have a material adverse effect on the Company, the market price of the Company’s common stock and the value of the Company’s investments.

At various times during recent years, the United States has had significant disagreements over political, economic and security issues with governments in Sub-Saharan Africa. Additional controversies may arise in the future. Any political or trade controversies, whether or not directly related to the Company’s business, could have a material adverse effect on the Company, the market price of the Company’s common stock and the value of the Company’s investments in Sub-Saharan Africa.

Risks Related to the Company’s Stock

Dr. Lawal is our controlling stockholder, and he may take actions that conflict with the interests of other stockholders.

The Company has been advised that on July 5, 2017, Oltasho and Latmol entered into a Voting Agreement with Dr. Lawal, the Company’s former Executive Chairman of the Board of Directors and former Chief Executive Officer, who retired from the Company in May 2016 (the “Voting Agreement”). Pursuant to the Voting Agreement, Oltasho and Latmol provided complete authority to Dr. Lawal to vote the 117,624,760 shares held by such entities (and any other securities of the Company obtained by Oltasho and/or Latmol in the future) at any and all meetings of stockholders of the Company and via any written consents. Those 117,624,760 shares represent 54.7%of the Company’s outstanding common stock as of December 31, 2017. The Voting Agreement has a term of approximately 10 years, through July 31, 2027, but can be terminated at any time with the mutual consent of the parties. In connection with their entry into the Voting Agreement, Oltasho and Latmol each provided Dr. Lawal an irrevocable voting proxy to vote the shares covered by the Voting Agreement. Additionally, during the term of such agreement, Oltasho and Latmol agreed not to transfer the shares covered by the Voting Agreement except pursuant to certain limited exceptions

Due to the Voting Agreement, Dr. Lawal controls the power to elect our directors, to appoint members of management (through control of the board) and to approve all actions requiring the approval of the holders of our common stock, including adopting amendments to our Certificate of Incorporation and approving mergers, acquisitions or sales of all or substantially all of our assets, subject to certain restrictive covenants. The interests of Dr. Lawal as our controlling stockholder could conflict with your interests as a holder of Company common stock. For example, Dr. Lawal as our controlling stockholder may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in his judgment, could enhance his equity investment even though such transactions might involve risks to you, as minority holders of the Company.

The Company’s stockholders may not be able to enforce United States civil liabilities claims.

Many of the Company’s assets are and are expected to continue to be located outside the United States and held through one or more subsidiaries incorporated under the laws of foreign jurisdictions. Substantially all of the Company’s operations are and are expected to continue to be conducted in Africa. In addition, some of the Company’s directors and officers, including directors and officers of its subsidiaries, may be residents of countries other than the United States. All or a substantial portion of the assets of these persons may be located outside the United States. As a result, it may be difficult for shareholders to effect service of process within the United States upon these persons. In addition, there is uncertainty as to whether the foreign courts would recognize or enforce judgments of United States courts obtained against the Company or such persons predicated upon the civil liability provisions of the securities laws of the United States or any state thereof or be competent to hear original actions brought

29

in these countries against the Company or such persons predicated upon the securities laws of the United States or any state thereof.

The market price of the Company’s common stock may be adversely affected by a number of factors related to the Company’s performance, the performance of other energy-related companies and the stock market in general.

The market prices of securities of energy companies are extremely volatile and sometimes reach unsustainable levels that bear no relationship to the past or present operating performance of such companies.

Factors that may contribute to the volatility of the trading price of the Company’s common stock include, among others:

•	financial predictions and recommendations by stock analysts concerning energy companies and companies competing in the Company’s market in general, and concerning the Company in particular;	
		
•	the Company’s quarterly results of operations or variances between the Company’s actual quarterly results of operations and predictions by stock analysts;	
		
•	public announcements of regulatory changes or new ventures relating to the Company’s business or its competitors, or acquisitions, joint ventures or strategic alliances by the Company or its competitors;	
		
•	investor perception of the Company’s business prospects or those of the oil and gas industry in general;	
		
•	the timing of commencement of production of new wells;	
		
•	the operating and stock price performance of other companies that investors or stock analysts may deem comparable to the Company;	
		
•	large purchases or sales of the Company’s common stock; and	
		
•	general economic and financial conditions.	

In addition to the foregoing factors, the trading prices for equity securities in the stock market in general, and of energy-related companies in particular, have historically been subject to wide fluctuations that may be unrelated to the operating performance of the particular company affected by such fluctuations. Consequently, broad market fluctuations may have an adverse effect on the trading price of our common stock regardless of the Company’s results of operations.

The limited market for the Company’s common stock may adversely affect trading prices or the ability of a shareholder to sell the Company’s shares in the public market at or near asking prices or at all if a shareholder needs to liquidate its shares.

The market price for shares of the Company’s common stock has been, and is expected to continue to be, volatile. Numerous factors beyond the Company’s control may have a significant effect on the market price for shares of the Company’s common stock, including the fact that the Company is a small company that is relatively unknown to stock analysts, stock brokers, institutional investors and others in the investment community that generate or influence sales volumes. There may be periods of several days or more when trading activity in the Company’s shares is minimal as compared to a seasoned issuer which has a large and steady volume of trading activity that will generally support continuous sales without an adverse effect on share price. Due to these conditions, investors may not be able to sell their shares at or near ask prices or at all if investors desire to liquidate their shares.

Our common stock is listed on the Johannesburg Stock Exchange (“JSE”). However, a trading market may not successfully develop on the JSE.

There is a limited trading market for our common stock on the JSE. An active trading market may not successfully develop on the JSE, or if it does, it may not be sustained. In addition, our listing on the JSE may have a negative effect on our trading market on the NYSE American. In 2014, we issued an aggregate of 62.8 million shares of our common stock to the Public Investment Corporation (SOC) Limited (“PIC”) of South Africa in a private placement. If PIC chooses to sell those shares on the JSE, sales of a large number of shares could have a negative effect on the market price of our shares on the JSE, which could have a negative effect on the market price of our shares on the NYSE American.

Substantial sales of the Company’s common stock could cause the Company’s stock price to fall.

The potential for substantial amounts of our common stock to be sold in the public market may adversely affect prevailing market prices for our common stock and could impair the Company’s ability to raise capital through the sale of its equity securities. Additionally, we may issue and register a greater number of shares of common stock in order to meet our obligations

30

to pay up to $50.0 million in oil and gas milestone payments under the Transfer Agreement or upon conversion of the 2014 Convertible Subordinated Note or the 2015 Convertible Note.

Conversion of the 2014 Convertible Subordinated Note or the 2015 Convertible Note, in the event of a default thereunder, may dilute the ownership interest of existing stockholders.

The conversion of some or all of the 2014 Convertible Subordinated Note or the 2015 Convertible Note, in the event of a default thereunder, may dilute the ownership interests of existing stockholders. The 2014 Convertible Subordinated Note is convertible into 14.0 million shares of our common stock, which represents approximately 6.51% of our currently outstanding shares. The 2014 Convertible Subordinated Note is subject to anti-dilution adjustment provisions, including provisions that make it convertible into the same percentage of our outstanding shares if we issue shares of common stock or any convertible security at a price per share less than the conversion price. The 2015 Convertible Note is convertible into shares of the Company’s common stock upon the occurrence and continuation of an event of default thereunder, at the sole option of the holder. The number of shares issuable upon conversion is equal to the sum of the principal amount and the accrued and unpaid interest divided by the conversion price, defined as the volume weighted average of the closing sales prices on the NYSE American for a share of common stock for the five complete trading days immediately preceding the conversion date. Any sales in the public market of the shares of our common stock issuable upon such conversions could adversely affect prevailing market prices of our common stock. In addition, the anticipated conversion of the 2014 Convertible Subordinated Note or the 2015 Convertible Note into shares of our common stock could depress the price of our common stock.

The Company’s issuance of preferred stock could adversely affect the value of the Company’s common stock.

The Company’s Amended and Restated Certificate of Incorporation authorizes the issuance of up to 50.0 million shares of preferred stock, which shares constitute what is commonly referred to as “blank check” preferred stock. This preferred stock may be issued by the Board of Directors from time to time on any number of occasions, without stockholder approval, (subject where applicable to the rules of the NYSE American, which generally prohibit the issuance of securities convertible into more than 20% of an issuer’s common stock without shareholder approval), as one or more separate series of shares comprised of any number of the authorized but unissued shares of preferred stock, designated by resolution of the Board of Directors, stating the name and number of shares of each series and setting forth separately for such series the relative rights, privileges and preferences thereof, including, if any, the: (i) rate of dividends payable thereon; (ii) price, terms and conditions of redemption; (iii) voluntary and involuntary liquidation preferences; (iv) provisions of a sinking fund for redemption or repurchase; (v) terms of conversion to common stock, including conversion price; and (vi) voting rights. The designation of such shares could be dilutive of the interest of the holders of our common stock. The ability to issue such preferred stock could also give the Company’s Board of Directors the ability to hinder or discourage any attempt to gain control of the Company by a merger, tender offer at a control premium price, proxy contest or otherwise.

We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock.

We do not presently intend to pay any cash dividends on our common stock or to repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of the Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price paid by you.

Shareholders may be diluted significantly through our efforts to obtain financing and satisfy obligations through the issuance of securities.

Wherever possible, our Board of Directors will attempt to use non-cash consideration to satisfy obligations. In many instances, we believe that the non-cash consideration will consist of shares of our common stock, preferred stock or warrants to purchase shares of our common stock. Our Board of Directors has authority, without action or vote of the shareholders, subject to the requirements of the NYSE American (which generally require shareholder approval for any transactions which would result in the issuance of more than 20% of our then outstanding shares of common stock or voting rights representing over 20% of our then outstanding shares of stock), to issue all or part of the authorized but unissued shares of common stock, preferred stock or warrants to purchase such shares of common stock. In addition, we may attempt to raise capital by selling shares of our common

31

stock, possibly at a discount to market in the future. These actions will result in dilution of the ownership interests of existing shareholders and may further dilute common stock book value, and that dilution may be material. Such issuances may also serve to enhance existing management’s ability to maintain control of us, because the shares may be issued to parties or entities committed to supporting existing management.

We are subject to the Continued Listing Criteria of the NYSE American and our failure to satisfy these criteria may result in delisting of our common stock.

Our common stock is currently listed on the NYSE American. In order to maintain this listing, we must maintain certain share prices, financial and share distribution targets, including maintaining a minimum amount of shareholders’ equity and a minimum number of public shareholders. In addition to these objective standards, the NYSE American may delist the securities of any issuer if, in its opinion, the issuer’s financial condition and/or operating results appear unsatisfactory; if it appears that the extent of public distribution or the aggregate market value of the security has become so reduced as to make continued listing on the NYSE American inadvisable; if the issuer sells or disposes of principal operating assets or ceases to be an operating company; if an issuer fails to comply with the NYSE American’s listing requirements; if an issuer’s common stock sells at what the NYSE American considers a “low selling price” (generally trading below $0.20 per share for an extended period of time) and the issuer fails to correct this via a reverse split of shares after notification by the NYSE American (provided that issuers can also be delisted if any shares of the issuer trade below $0.06 per share); or if any other event occurs or any condition exists which makes continued listing on the NYSE American, in its opinion, inadvisable.

If the NYSE American delists our common stock, investors may face material adverse consequences, including, but not limited to, a lack of trading market for our securities, reduced liquidity, decreased analyst coverage of our securities, and an inability for us to obtain additional financing to fund our operations.

ITEM 1B.    UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 2.    PROPERTIES
 
EXECUTIVE OFFICES AND INTERNATIONAL FACILITIES
 
We have four leased office facilities located in Houston, Texas (the “Houston Facility”), Lagos, Nigeria (the “Lagos Facility”), Nairobi, Kenya (the “Kenya Facility”), and Accra, Ghana (the "Ghana Facility").
 
Our corporate headquarters is located at our Houston Facility at 1330 Post Oak Boulevard, Houston, Texas, 77056. The Houston Facility covers approximately 13,200 square feet of office space and is under a lease which commenced on July 1, 2012, and ends on October 31, 2019. Current base rental expense is approximately $29,000 per month plus an allocated share of operating expenses.
 
The Nigeria Facility covers approximately 7,500 square feet of office space and is under short-term arrangements with a related party. Current base rental expense is approximately $9,500 a month.
 
The Kenya Facility covers approximately 3,300 square feet of office space and is under lease which commenced on July 1, 2016, and ends July 31, 2021. Current base rental expense is approximately $4,800 per month, plus service charges.
 
We previously leased a facility in Banjul, The Gambia, which covered approximately 2,700 square feet of office space under a short-term lease arrangement, which commenced on January 1, 2016, and ended October 2017.
 
The Ghana Facility covers approximately 1,722 square feet of office space under a lease which commenced on May 1, 2015, and ends on April 30, 2019. Current base rental expense is approximately $6,300 per month.

We previously leased a facility in Johannesburg, South Africa, which covered approximately 3,300 square feet of office space under a lease which commenced on February 1, 2015, and ended on June 27, 2017.
 
We do not foresee significant difficulty in renewing or replacing the remaining leases under current market conditions, or in adding additional space when required.

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OIL AND GAS LEASEHOLDS

The map below sets forth a visual representation of the geographical locations of our oil and gas properties on the continent of Africa.
 Nigeria
 
In February 2014, the Company acquired, from a related party, the outstanding economic interests not already owned by the Company in the OMLs offshore Nigeria. Pursuant to this transaction, the Company now owns 100% of the development and exploration rights over approximately 0.4 million acres offshore Nigeria. The OMLs contain the Oyo field which has been in production since December 2009.  

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Kenya
 
In May 2012, the Company entered into the Kenya PSCs. During the Initial Exploration Period, the Company's exploration rights over blocks L1B and L16 covered an area of 3.1 million acres and 0.9 million acres, respectively. After successfully completing its required work commitments, the Company entered the First Additional Exploration Period for blocks L1B and L16. 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 on block L16. As a result, the Company had 2.3 million acres for block L1B and 0.9 million acres for block L16, respectively. Exploration rights over approximately 2.6 million acres were awarded for each of the offshore blocks L27 and L28, which the Company opted not to renew or extend as it expired in February 2017. The Company also opted not to renew or extend its exploration rights over its onshore blocks L1B and L16, which expired in July 2017.
 
Gambia
 
In May 2012, the Company signed the Gambia Licenses. The Gambia Licenses awarded to the Company cover exploration rights over approximately 0.3 million acres each for blocks A2 and A5. The Company became the operator for both blocks at that time, with the 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.

In June 2017, FAR became the operator of both blocks upon the approval by the Gambian government of a sale agreement (the "Sale Agreement"), whereby FAR agreed to acquire an 80% interest and operatorship of the Company’s offshore A2 and A5 blocks in The Gambia. The Company will retain a 20% working interest in both blocks.

Under the terms of the Sale Agreement, which was approved by the Government of the Republic of The Gambia in June 2017, upon closing of the transaction, FAR paid the Company the purchase price of $5.2 million and will carry $8.0 million of the Company’s share of costs in a planned exploration well to be drilled in late 2018. In addition, if the Company’s share of the exploration well is less than $8.0 million, the balance is to be paid in cash to the Company. Any amount in excess of the $8.0 million representing the Company’s share of the exploration well will be borne by the Company.
 
Ghana
 
In April 2014, the Company, through a 50% owned Ghanaian subsidiary, signed the Petroleum Agreement. The Company, which is a member of a contracting party who is a signatory to the Petroleum Agreement, has been named technical operator and holds an indirect 30% participating interest in the block. The block contains three discovered fields, and the work program requires the consortium to determine the economic viability of developing the discovered fields. The Ghana Petroleum Agreement awarded the Company exploration rights over approximately 0.4 million gross acres (0.1 million net acres).
 
RESERVES
 
The information included in this Annual Report on Form 10-K about our rights to our proved reserves as of December 31, 2017 , represents evaluations prepared by DeGolyer and MacNaughton (“D&M”), an independent petroleum engineering and geoscience advisory firm. D&M has prepared evaluations on 100 percent of our rights to our proved reserves and the estimates of proved crude oil reserves attributable to our net interests in oil and gas properties as of December 31, 2017 . The scope and results of D&M’s procedures are summarized in a letter that is included as an exhibit to this Annual Report on Form 10-K. For further information on reserves, including information on future net cash flows and the standardized measure of discounted future net cash flows, please refer to the Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited) within Item 8 of this report. The totality of our proved reserves are located offshore Nigeria in the OMLs.
 
Internal Controls over Reserve Estimation
 
Our policies regarding internal controls over the recording of reserve estimation require reserves to be in compliance with the SEC definitions and guidance and that they are prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry.
 
We obtain services of contracted reservoir engineers with extensive industry experience who meet the professional qualifications of reserves estimators and reserves auditors as defined by the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” approved by the Board of the Society of Petroleum Engineers in 2001 and revised in 2007.

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The Report was prepared under the responsible supervision of Mr. Lloyd W. Cade. Mr. Cade is a Senior Vice President with DeGolyer and MacNaughton, Manager of the firm’s Europe Africa Division, a registered Professional Engineer in the State of Texas, number 74615. He has over 35 years of oil and gas industry experience with over 32 years at DeGolyer and MacNaughton performing reserves evaluations.

We have on staff reservoir engineers with extensive industry experience, who meet professional qualifications of reserves estimators and reserves auditors as defined by the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” approved by the Board of the Society of Petroleum Engineers in 2001 and revised in 2007.
 
Our engineering staff with the primary responsibility to coordinate and review third-party reserves reports provided by D&M are Mr. Okwudiri Uzoh and Ms. Toyin Badru. Mr. Uzoh, our Technical Vice-President, has over 25 years of experience in the oil and gas industry mainly in reservoir engineering and engineering management. He holds a Master’s degree in Petroleum Engineering from University of Houston. Mr. Uzoh is also a registered professional engineer of Alberta, License no. 113154 and a member of the Society of Petroleum Engineers. Ms. Toyin Badru, our Senior Reservoir Engineer, has over 12 years of experience in the oil and gas industry and holds a Bachelor's degree in Petroleum engineering from the University of Ibadan, Nigeria and an MS in Petroleum engineering from Stanford University, California. She has worked in reservoir simulation consulting groups as well as multi-disciplinary asset teams in both Nigeria and the United states. She is a member of the Society of Petroleum Engineers.
 
Compliance with reserve bookings is the responsibility of the Company. The reserves estimates prepared by D&M were reviewed and approved by our management. The process performed by D&M to prepare reserve amounts includes the estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue, before income tax. In the conduct of their preparation of the reserve estimates, D&M did not independently verify the accuracy and completeness of certain information and data furnished by us with respect to ownership interests, oil production data, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production and various other information and data that were accepted as presented. Furthermore, D&M did not perform a field examination of the properties, as this was not deemed necessary for the preparation of their report. However, if in the course of their evaluation something came to their attention which brought into question the validity or sufficiency of any such information or data, D&M did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.
 
Technologies Used in Reserves Estimates
 
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

Estimates of original oil in-place were obtained from a detailed and properly constructed proved case static and dynamic model for the Oyo field. This model was well history matched and applied to predict the future performance of the field based on existing and approved future developments. Only gas injection which has been proven in the Oyo field as a feasible recovery process was applied in the proved reserves estimation. Results from this analysis was determined to be aligned with performance data from similar reservoirs.
 
Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, the oil reserves estimates obtained for the Oyo field may be different from the quantities of oil that are ultimately recovered.
 
Summary of Crude Oil Reserves
 
Set forth below is a summary of our net oil proved reserves as of December 31, 2017 , 2016 , and 2015 , respectively:

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 	Years Ended December 31,	
 	2017	 	2016	 	2015	
Proved developed reserves ( in MBbls )	—		 	3,256		 	7,594		
Proved undeveloped reserves ( in   MBbls ) (1)	7,107		 	5,994		 	4,390		
Total proved reserves ( in MBbls ) (1)	7,107		 	9,250		 	11,984		
 	 	 	 	 	 	
Standardized measure of proved reserves (in thousands)	$	41,043		 	$	43,585		 	$	161,967		
(1) Total proved volume of 7,107 MBbls as of December 31, 2017 include proved developed volumes of 3,210 MBbls from our existing Oyo-7 and Oyo-8 producer wells.

The Company annually reviews all proved undeveloped reserves (“PUDs”) to ensure an appropriate development plan exists. The Company’s PUDs are generally expected to be converted to proved developed reserves within five years of the date they are first classified as PUDs.

Of the 7.1 million barrels in proved reserves, 3.9 million barrels as of December 31, 2017 represent the estimated recoverable volumes associated with the Company’s Oyo-9 well which is expected to be completed in 2018. The 2.1 million barrel reduction in PUDs in 2017 as compared to 2016 is due to the higher operating costs applied for this evaluation. The 1.6 million barrels increase in PUDs in 2016 as compared to 2015 is due to the further optimization to the well Oyo-9 plan carried out as part of the front-end planning process.

The standardized measure of discounted net future cash flows is the present value of estimated future net cash inflows from proved oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future net cash flows. As of December 31, 2017 , the standardized measure of our proved reserves was approximately $41.0 million , as compared to $43.6 million and $162.0 million as of December 31, 2016 and 2015 , respectively. The decrease in the standardized measure of our proved reserves in 2017 as compared to 2016 is due mainly from depletion and field performance adjustments. The decrease in the standardized measure of our proved reserves in 2016 as compared to 2015 is primarily due to the lower commodity prices in 2016 and the reduction in proved reserves from depletion and field performance adjustments. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s properties.
 
SEC reporting rules require companies to prepare reserve estimates using reserve definitions and pricing based on 12-month historical un-weighted first-day-of-the-month average prices, rather than year-end or forward strip prices. Our estimated net proved reserves and standardized measure were determined using index prices for oil and were held constant throughout the life of the assets. The average first-day-of-the-month commodity prices during the 12-month periods ending on December 31, 2017 , 2016 , and 2015 , were $54.19, $42.21, and $53.51 per barrel of crude oil, respectively, including price differentials.
 
VOLUMES, PRICES, AND PRODUCTION COSTS 
 
Production and sales volumes net to the Company, as well as sales prices and production costs for the years 2017 , 2016 , and 2015 are shown below. The totality of the production and sales volumes for each period presented were originated from the Oyo field offshore Nigeria.

	
												
 	Years Ended December 31,	
 	2017	 	2016	 	2015 (1)	
Aggregate production volumes (MBbls)	1,725		 	1,754		 	1,564		
Average daily production (BOPD)	4,900		 	4,800		 	6,400		
Sales volumes (MBbls)	1,845		 	1,712		 	1,449		
Average sales prices ($ / Bbls)	$	54.84		 	$	45.45		 	$	47.24		
Average production cost per barrel ($ / Bbls)	$	41.29		 	$	48.21		 	$	54.72		
		
(1)	In 2015, average daily production and average production cost per barrel were computed over a period of eight months because production commenced in May 2015.	

36

DRILLING ACTIVITY

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 October 2017, the Company completed the drilling phase of the Oyo-9 well. Both the engineering and manufacturing of the subsea equipment are at various stages of completion. However, the Company temporarily suspended the completion and hookup of the development program.

In October 2017, the Company obtained a funding commitment to drill our potential high-impact exploration well ("Oyo-NW"), in the Miocene formation of the OMLs. In January, 2018, the Company completed the drilling of the Oyo-NW well and, based on preliminary evaluation; it has discovered hydrocarbons in the Miocene Formation. Preliminary evaluation of the well data shows that the two main sand units, the Miocene U7.0 and U8.0, with a gross thickness of approximately 115.2 feet are hydrocarbon-bearing. Work has commenced to estimate the discovered volumes and to determine the relevant appraisal and development program.

ACREAGE AND PRODUCTIVE WELLS
 
The table below sets forth the acreage under lease and the number of productive oil wells for the Company as of the date of this report. Productive oil wells consist of producing wells and wells capable of producing in commercial quantities, including wells awaiting connection to production facilities.

	
																		
 	Developed Acres	 	Undeveloped Acres	 	Productive oil wells	
(In thousands)	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	
Nigeria	10		 	10		 	429		 	429		 	3		 	3		
The Gambia	—		 	—		 	659		 	132		 	—		 	—		
Ghana	—		 	—		 	373		 	112		 	—		 	—		
Total	10		 	10		 	1,461		 	673		 	3		 	3		

In Nigeria, the Company finished completion operations for well Oyo-8 in March 2015, successfully tied it into the FPSO, and commenced production in May 2015. In April 2015, the Company initiated horizontal completion activities for well Oyo-7 and commenced production in June 2015.

In October 2017, the Company successfully completed the drilling phase of the Oyo-9 well. The Oyo-9 well will be tied in to the field’s current production facility.

Remaining lease terms
 
Nigeria
 
The current lease for the Nigeria acreage expires in February 2021.
 
Kenya blocks L1B and L16
 
Total acreage for the Kenya blocks L1B and L16 is approximately 3.1 million, net to the Company. 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, and the Company did not renew or extend its leases on these offshore blocks.
 
Kenya blocks L27 and L28
 
Total acreage for the Kenya blocks L27 and L28 is approximately 5.1 million, net to the Company. The initial exploration period for both blocks ended in August 2015. The Company received approval from the Kenya Ministry of Energy and Petroleum for

37

an 18-month extension of the Initial Exploration Period for blocks L27 and L28, which lasted through February 2017. The Company did not renew or extend its leases on these offshore blocks.
 
The Gambia
 
In accordance with the Gambia Licenses Amendment entered into with The Republic of The Gambia in May 2015, the term of the initial exploration period for both blocks A2 and A5 was extended by two years through December 2018. In March 2017, the Company entered into a Sale Agreement with FAR Ltd., whereby FAR acquired an 80% interest and operatorship of the Company's offshore A2 and A5 blocks, with the Company retaining a 20% working interest in both blocks.
 
Ghana
 
Although the Ghana Petroleum Agreement was signed in April 2014, it only became effective in January 2015 following the signing of a Joint Operating Agreement among the joint venture partners. In October 2015, the Company completed its economic and commercial evaluation of the three previously discovered fields. The Contracting Parties concluded that certain fiscal terms in the Petroleum Agreement had to be adjusted in order to achieve commerciality of the Fields under current economic conditions, and have presented this conclusion to the relevant government entities. The Ghanaian government is currently reviewing the requests for adjustment of the fiscal terms, and has granted the Company an extension of the Initial Exploration Period for eighteen months until the end of July 2018. The Company is working with the Ghanaian Government and its partners to progress the development activities in its ESWT block, offshore Ghana. The Company plans to acquire 3D seismic data in connection with the block during the second quarter of 2018. The Company has submitted an application to the Ghanaian government for an additional extension of the initial exploration period beyond the current date of July 2018.
 
DELIVERY COMMITMENTS
 
As of December 31, 2017 , we had no delivery commitments.
 
ITEM 3.    LEGAL PROCEEDINGS
 
From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. As of December 31, 2017 , and through the filing date of this report, the Company does not believe the ultimate resolution of such actions or potential actions of which the Company is currently aware will have an adverse material effect on its consolidated financial position or results of operations. The disclosures included in Part IV, Item 15. Exhibits, Financial Statements and Schedules , under Note 10. Commitments and Contingencies , address the matters required by this item and are incorporated herein by reference.

ITEM 4.    MINE SAFETY DISCLOSURES
 
Not applicable.
 
PART II  

ITEM 5.	MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	
 
Market Information for Common Stock
 
Our common stock is currently listed on the NYSE American under the symbol “ERN”. It commenced listing on the NYSE American in November 2009 under the symbol “PAP”. In addition to our listing on the NYSE American, since February 2014, our common stock has been listed on the Johannesburg Stock Exchange (“JSE”).
 
The following table sets forth the range of the high and low sales prices per share of our common stock for the periods indicated on the NYSE American, the principal market for the trading of our common stock, under the symbol “ERN”:

38

	
									
Period	 	High	 	Low	
2017	 	 	 	 	
First quarter	 	$	3.95		 	$	2.20		
Second quarter	 	$	2.45		 	$	1.35		
Third quarter	 	$	3.95		 	$	1.25		
Fourth quarter	 	$	3.10		 	$	2.40		
2016	 	 	 	 	
First quarter	 	$	2.90		 	$	1.62		
Second quarter	 	$	2.78		 	$	1.51		
Third quarter	 	$	2.84		 	$	2.07		
Fourth quarter	 	$	3.15		 	$	2.00		
 
Capital Structure
 
Common Stock
 
The Company is authorized to issue up to 416.7 million shares of $0.001 par value common stock. As of December 31, 2017 , there were approximately 215.1 million such shares outstanding.

Preferred Stock
 
The Company is authorized to issue up to 50.0 million shares of $0.001 par value preferred stock and to designate the dividend rate, voting and other rights, restrictions and preferences for each series of preferred stock. No preferred stock was issued and outstanding as of December 31, 2017 .
 
Common Stock Warrants and Options
 
As of March 1, 2018, the Company had warrants outstanding to purchase an aggregate of 10.3 million shares of common stock at prices per share ranging from $2.00 to $7.85.
 
As of March 1, 2018, an aggregate of approximately 0.6 million shares of common stock were issuable upon exercise of outstanding stock options at prices per share ranging from $1.74 to $3.83.
Holders of Common Stock
 
As of March 1, 2018, there were approximately 66 holders of record of our common stock. In many instances, a broker or other entity holds shares in street name for one or more customers who beneficially own the shares.
 
Dividend Policy
 
The Company has not paid any cash dividends in the past, and does not anticipate paying any cash dividends on its common stock in the foreseeable future.

Securities Authorized for Issuance under Equity Compensation Plans
 
Upon adoption of the 2009 Equity Incentive Plan (“2009 Plan”) by our Board of Directors in June 2009, our Board of Directors resolved to (i) discontinue further grants and awards of equity securities under the 2007 Stock Plan (the “2007 Plan”), except the issuance of our stock upon exercise of issued and outstanding options issued pursuant to the 2007 Plan, and (ii) amend the 2007 Plan to reduce the number of shares available for issuance under the 2007 Plan to 0.4 million shares, down from 0.7 million shares, and to further reduce the number of shares available for issuance thereunder by such number of shares that from time to time may be returned for issuance under the 2007 Plan upon expiration or termination of any option issued thereunder or repurchase of any restricted stock issued thereunder, and to return all such shares to the Company’s treasury.

39

On February 13, 2014, our stockholders approved an amendment to the 2009 Plan at a special meeting of stockholders. On February 18, 2014, we executed the amendment to the 2009 Plan, thereby increasing the number of shares that may be granted thereunder to 16.7 million shares.
 
The following table sets forth information with respect to the equity compensation plans available to our directors, officers, and employees at December 31, 2017 :

	
											
Plan Category	 	Number of
Securities to
be Issued
Upon
Exercise of
Outstanding
Options,
Warrants
and Rights
(a)	 	Weighted-
Average
Exercise
Price of
Outstanding
Options,
Warrants
and Rights
(b)	 	Number of
Securities
Available For
Future
Issuance
Under 2009
Equity
Compensation
Plan
(Excluding
Securities
Reflected in
Column (a))
(c)	
Equity compensation plans approved by security holders	 	1,758,244		(1)	$	2.34		 	8,585,897		
Warrants approved by security holders	 	10,256,146		(2)	$	2.99		 	 	
 	 	12,014,390		 	 	 	8,585,897		

(1)	Includes the 2009 Equity Incentive Plan.	
		
(2)	Remaining warrants exercisable for shares of common stock issued in 2014, 2015 and 2017, to service providers, to the holder of the Company's 2015 Convertible Note and to the holder of the Company's 2017 James Street Capital Note, respectively, which issuances were approved by the stockholders of the Company.	
The above outstanding common stock warrants and options reflect the effect of the Company’s payment of the February 2014 stock dividend and the April 2015 reverse stock split.
 
Performance Graph
 
The following graph compares the yearly percentage change in the Company’s cumulative total stockholder return on its common shares with the cumulative total return of the S&P 500 Index and the SPDR Oil and Gas Exploration and Production Index. The selected indices are accessible to our stockholders in newspapers, the internet and other readily available sources. This graph assumes a $100 investment in Erin Energy Corporation, the S&P 500 and the Energy Select Sector SPDR at the close of trading on December 31, 2012, and assumes the reinvestment of all dividends, if any.

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This Performance Graph shall not be deemed to be incorporated by reference into our SEC filings and should not constitute soliciting material or otherwise be considered filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.
 
Recent Sales of Unregistered Securities

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. 

In March 2015, the Company entered into a borrowing facility with Allied pursuant to the 2015 Convertible Note, allowing the Company to borrow up to $50.0 million for general corporate purposes. As of December 31, 2017 , the Company has drawn $48.5 million under the note and issued to Allied warrants to purchase approximately 2.7 million shares of the Company’s common stock at prices ranging from $2.00 to $7.85 per share. For further information, see  Note 8. - Debt to the Notes to Consolidated Financial Statements.
 
In August 2017, the Company entered into a consulting agreement (the “Agreement”) with Somerley Capital Limited (“Somerley”), pursuant to which Somerley has agreed to represent the Company to perform certain financial advisory services. Somerley agreed to communicate with prospective investors with respect to the Company’s current and proposed activities, and to consult with the Company’s management concerning such activities. As partial consideration under the Agreement, in September 2017, the Company issued 33,333 shares of the Company’s restricted common stock to Somerley.

In September 2017, the Company entered into the September 2017 Settlement Agreement (defined and described below under “ Note 10 - Commitments and Contingencies - Contingencies - Legal Contingencies and Proceedings , from the notes to the consolidated financial statements set forth under “ Part IV, Item 15 - Exhibits, Financial Statements and Schedules ”) with a vendor. As part of the September 2017 Settlement Agreement, the Company issued 1,282,355 shares of the Company's restricted common stock valued at $3.5 million.

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On October 27, 2017 the Company, through its wholly-owned subsidiary, EPNL, entered into a loan agreement, (the "2017 Loan Agreement"), with James Street Capital Partners Limited, ("JSC") as the lender, allowing the Company to borrow up to $20.0 million to be used for capital expenditures in relation to the drilling of an exploration well in the Miocene formation of the OMLs. This loan matures on December 31, 2020, and accrues interest at three month Libor plus 5% per annum. In consideration for this undertaking, the Company issued a stock purchase warrant to JSC to purchase up to 7,272,727 shares of the Company's common stock at $2.75 per share. The warrants include a repurchase right such that upon repayment in full of the amounts borrowed under the 2017 Loan Agreement the Company may repurchase the warrants at their fair market value (as defined in the warrant agreement). The warrants expire on December 31, 2019 and include cashless exercise rights in the event the shares of common stock issuable upon exercise thereof are not registered under the Securities Act of 1933, as amended. If exercised in full an aggregate of 7,272,727 shares of common stock would be due to JSC.

We claim an exemption from registration for the issuances and sales of the securities described above pursuant to Section 4(a)(2), Rule 506 of Regulation D of the Securities Act and/or Regulation S of the Securities Act, since the foregoing issuances did not involve a public offering, the recipients were (a) “accredited investors”; (b) had access to similar documentation and information as would be required in a Registration Statement under the Securities Act; and/or (c) were non-U.S. persons, the recipients acquired the securities for investment only and not with a view towards, or for resale in connection with, the public sale or distribution thereof. The securities were offered without any general solicitation by us or our representatives. No underwriters or agents were involved in the foregoing issuances and grants and we paid no underwriting discounts or commissions. The securities sold are subject to transfer restrictions, and the certificates evidencing the securities contain an appropriate legend stating that such securities have not been registered under the Securities Act and may not be offered or sold absent registration or pursuant to an exemption therefrom. The securities were not registered under the Securities Act and such securities may not be offered or sold in the United States absent registration or an exemption from registration under the Securities Act and any applicable state securities laws.

Issuer Purchases of Equity Securities

The following table sets forth monthly information with respect to repurchases of our common stock during the quarter ended December 31, 2017.

													
 	Total Number of
Shares Purchased (1)	 	Average Price
Paid Per Share	 	Total Number of
Shares
Purchased as
Part of Publicly
Announced Plan
or Program	 	Maximum Number 
(or
Approximate Dollar
Value) of Shares that
May be Purchased
Under the Plan or
Program	
December 1 - December 31, 2017	3,362		 	$	2.65		 	—		 	—		
Total	3,362		 	$	2.65		 	 	 	 	

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

42

ITEM 6.    SELECTED FINANCIAL DATA

	
																				
 	Years Ended December 31,	
(In thousands, except per share information)	2017	 	2016	 	2015	 	2014	 	2013	
Statement of Income Data	 	 	 	 	 	 	 	 	 	
Revenues	$	101,173		 	$	77,815		 	$	68,429		 	$	53,844		 	$	63,736		
Net loss attributable to Erin Energy Corporation	$	(151,892	)	 	$	(142,401	)	 	$	(430,937	)	 	$	(96,062	)	 	$	(43,525	)	
Net loss per common share attributable to Erin Energy Corporation	 	 	 	 	 	 	 	 	 	
Basic	$	(0.71	)	 	$	(0.67	)	 	$	(2.04	)	 	$	(0.49	)	 	$	(0.30	)	
Diluted	$	(0.71	)	 	$	(0.67	)	 	$	(2.04	)	 	$	(0.49	)	 	$	(0.30	)	
Cash Flow Data	 	 	 	 	 	 	 	 	 	
Net cash (used in) provided by operating activities	$	26,057		 	$	6,355		 	$	2,145		 	$	(33,547	)	 	$	(36,625	)	
 	As of December 31,	
(In thousands)	2017	 	2016	 	2015	 	2014	 	2013	
Balance Sheet Data	 	 	 	 	 	 	 	 	 	
Property plant and equipment, net	$	199,761		 	$	266,429		 	$	370,065		 	$	596,329		 	$	435,787		
Total assets	$	251,128		 	$	289,201		 	$	395,159		 	$	638,443		 	$	454,224		
Long-term liabilities	$	215,588		 	$	226,718		 	$	140,615		 	$	168,097		 	$	8,189		
 
The above presented earnings per share amounts reflect the effect of the stock dividend paid in February 2014, which was accounted for as a stock split due to its large nature, and the April 2015 6-for-1 reverse stock split.

For more information on results of operations and financial condition, see Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	
 
The following discussion of the Company’s historical performance and financial condition should be read together with Item 6, Selected Financial Data and the consolidated financial statements and related notes in Item 8 of this report. This discussion contains forward-looking statements based on the views and beliefs of our management, as well as assumptions and estimates made by our management. These statements by their nature are subject to risks and uncertainties, and are influenced by various factors. As a consequence, actual results may differ materially from those in the forward-looking statements. See Item 1A. Risk Factors of this report for the discussion of risk factors.
 
The Company’s operating subsidiaries include EPNL, Erin Energy Kenya Limited, Erin Energy Gambia Ltd., and Erin Energy Ghana Limited. The Company also conducts certain business transactions with related parties. See Note 9. — Related Party Transactions to the Notes to Consolidated Financial Statements for further information.

OVERVIEW
 
Nigeria
 
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. In April 2015, the Company initiated horizontal completion activities for well Oyo-7 and commenced production in June 2015.

The enforcement of certain control measures implemented by the Nigerian government with regards to the quarterly exportation and sale of crude oil products from Nigeria has had an impact on the Company’s operations. Petroleum producers are required to obtain export permits quarterly for crude oil liftings. During the period from May to September 2015, the Company produced

43

approximately 1.5 million Bbls of crude oil but only sold approximately 0.6 million Bbls due to the unexpected delays in the issuance of export permits for the quarter ending September 30, 2015. The resulting crude oil inventory of approximately 0.9 million Bbls, as of September 30, 2015 was approaching the Company’s crude oil storage capacity on its FPSO. As a result, the Company had to curtail production by temporarily shutting-in well Oyo-8 in September 2015. The Company subsequently received a permit to export approximately 1.3 million Bbls from October to December 2015.

In early May 2016, with the help of a light intervention vessel, the Company successfully completed well repair operations to resolve the mechanical problem related to well Oyo-8 and successfully resumed production from the well. In early July 2016, well Oyo-7 was shut-in as a result of an emergency shut-in of the Oyo field production. This has resulted in a loss of approximately 1,400 BOPD. The Company is currently working on relocating an existing gaslift line to well Oyo-7 to enable continuous gaslift operation. For cost effectiveness, the relocation of the gaslift line to well Oyo-7 is now planned to be combined with the Oyo-9 subsea equipment installation scheduled for the second half of 2018, subject to fund availability.

During the three months ended December 31, 2017, the average daily production was approximately 4,600 BOPD (approximately 4,000 BOPD net to the Company).

In early August 2017, the Pacific Bora drilling rig arrived on the Oyo field and immediately commenced drilling of the Oyo-9 well. In October 2017, the Company successfully completed the drilling phase of the Oyo-9 well. The well results indicate presence of the target channel system and 85.3 feet of net oil sand. The results are in line with predictions and confirm field extension to the western part of the field. Both the engineering and manufacturing of the subsea equipment are at various stages of completion. However, due to chronic delays in the release of the remaining funds and improper interference by the guarantor of the MCB Finance Facility, the Company temporarily suspended the completion and hookup of the development program. On several occasions, the Company has demanded the guarantor cease and desist from interfering in the disbursement of funds for the project. Consequently, the Pacific Bora drilling rig and all drilling services have been demobilized. The Oyo-9 well will be tied in to the field’s current production facility, and is expected to add an additional 6,000 to 7,000 barrels of oil per day from the field. On January 26, 2018, the Company and its subsidiary, EPNL, filed a complaint against Public Investment Corporation SOC Ltd., (PIC), with the Supreme Court of New York, County of New York, Commercial Division in regards to this matter.

In October 2017, the Company obtained a funding commitment to drill our potential high-impact exploration well ("Oyo-NW"), in the Miocene formation of the OMLs. The Company has completed the drilling of the Oyo-NW well. Based on the preliminary evaluation we have discovered hydrocarbons in the Miocene Formation. Preliminary evaluation of the well data shows that the two main sand units, the Miocene U7.0 and U8.0, with a gross thickness of approximately 115.2 feet are hydrocarbon-bearing. Work has commenced to estimate the discovered volumes and to determine the relevant appraisal and development program.

Kenya
 
Blocks L1B and L16
 
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 lasted two contract years, through July 2017. In accordance with certain provisions of the Kenya PSCs for onshore blocks L1B and L16, 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 which ended July 2017 for both onshore blocks, the Company was obligated, for each block, to (i) acquire, process and interpret high density 300 square kilometer 3-D seismic data at a minimum expenditure of $12.0 million, and (ii) drill one exploration well to a minimum depth of 3,000 meters at a minimum expenditure of $20.0 million.

In June 2017, the Company wrote off the costs related to onshore blocks L1B and L16 that had been capitalized to that date. The Company did not renew or extend its leases on these offshore blocks.

44

Blocks L27 and L28
 
The Kenya PSCs for offshore blocks L27 and L28 each provided for an initial exploration period of three years, through August 2015, with specified minimum work obligations during that period. Prior to the end of the initial exploration period, the Company is required to conduct, for each block, i) a regional geological and geophysical study, ii) reprocess and re-interpret previous 2-D seismic data and iii) acquire, process and interpret 1,500 square kilometers of 3-D seismic data.
 
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 lasted through February 2017. The remaining contractual obligation under the initial exploration period was for the Company to acquire, process and interpret 3-D seismic data over both offshore blocks.

In December 2016, the Company wrote off the costs related to offshore blocks L27 and L28 that had been capitalized to that date as the Company did not renew or extend its leases on these offshore blocks.

The Gambia
 
In May 2015, the term of the initial exploration period for both blocks A2 and A5 was extended by two years through December 2018 as provided for under the Gambia Licenses Amendment entered into with The Republic of the Gambia. As of December 31, 2017 , the remaining contractual obligations, as amended pursuant to The Gambia Licenses Amendment under the Gambia Licenses for both blocks, is for the Company to (i) complete the interpretation of approximately 1,500 square kilometers of 3-D seismic data that was acquired in September 2015 and (ii) drill one exploration well on either block A2 or A5 and evaluate the drilling results. As consideration for the Gambia Licenses 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.

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

The Company and FAR are currently working together to progress our plans to drill the Samo-1 prospect in late 2018.

Ghana
 
In January 2015, the Petroleum Agreement entered into with the Republic of Ghana relating to the ESWT block offshore Ghana became effective, following the signing of a Joint Operating Agreement between the Contracting Parties. In October 2015, at the completion of the initial technical and commercial evaluation of the Fields, the Contracting Parties concluded that certain fiscal terms in the Petroleum Agreement had to be adjusted in order to achieve commerciality of the Fields under current economic conditions. The Contracting Parties presented this conclusion to the relevant government entities. The Ghanaian Government reviewed the requests for adjustment of the fiscal terms, and granted the Company an extension of the Initial Exploration Period for eighteen months until the end of July 2018. The Company has submitted an application to the Ghanaian government for an additional extension of the Initial Exploration Period beyond the current date of July 2018.

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

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RESULTS OF OPERATIONS
 
Oil Revenues
 
Revenue is recognized when an oil lifting occurs. Crude oil revenues for 2017 were $101.2 million , as compared to $77.8 million and $68.4 million for 2016 and 2015 , respectively. In 2017 , the Company sold approximately 1,845,000 net barrels of oil at an average price of $54.84/Bbl. In 2016, the Company sold approximately 1,712,000 net barrels of oil at an average price of $45.45/Bbl. In 2015, the Company sold approximately 1,449,000 net barrels of oil at an average price of $47.24/Bbl. The revenue increase in 2017 as compared to 2016 was primarily due to the increase in oil commodity prices.
 
During 2017 , 2016 and 2015 , the net daily production from the Oyo field, over the days when production occurred, was approximately 4,900 BOPD, 4,800 BOPD and 6,400 BOPD, respectively. During 2017, the Oyo-8 well was the only well that produced. In early July 2016, well Oyo-7 was shut-in as a result of an emergency shut-in of the Oyo field production. In early May 2016, with the help of a light intervention vessel, the Company successfully completed well repair operations to resolve the mechanical problem related to well Oyo-8 and successfully resumed production from the well. During 2015, production for both Oyo-8 and Oyo-7 were for only part of the year.
 
Operating Costs and Expenses
 
Production Costs
 
Production costs were $80.9 million for 2017 , as compared to $94.6 million in 2016 and $90.1 million in 2015 . Production costs include costs directly related to the production of hydrocarbons. The $13.7 million decrease in production costs in 2017 as compared to 2016 was primarily due to settlements with vendors during 2017, reduction in the number of liftings during the 2017 as compared to 2016, and a $1.3 million reduction in logistics base costs.

The $4.5 million increase in production costs in 2016 as compared to 2015 was primarily due to the $26.0 million agreed-upon retroactive FPSO operating day rate cost reduction recognized in June 2015 which was retroactive back to July 2014.

Crude Oil Inventory (Increase) Decrease

The Company matches production expenses with crude oil sales. Any production expenses associated with unsold crude oil inventory are capitalized with a corresponding offset to operating costs. The capitalized crude oil inventory costs are subsequently expensed when crude oil is sold.

Workover Expenses

During 2017 , the Company recovered $0.7 million of workover expenses, as compared to expenditures of $7.9 million for the year 2016 and $1.0 million for the year 2015. The decrease in workover expenses in 2017 as compared to 2016 and the increase in 2016 as compared to 2015 are due to the light intervention of well Oyo-8 during 2016. During 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.

Exploration Expenses
 
Exploration expenses were $4.6 million for 2017 , as compared to $39.3 million for 2016 and $16.4 million in 2015 . Exploration expenses consist of drilling costs for unsuccessful wells, and costs for acquiring and processing seismic data, as well as other geological and geophysical costs as required.
 
The $4.6 million exploration expenditures in 2017 include $0.8 million spent in Kenya, $1.0 million spent in The Gambia, $2.0 million spent in Ghana, and $0.8 million spent in Nigeria.
 
The $39.3 million exploration expenditures in 2016 include $1.8 million spent in Kenya, $1.5 million spent in The Gambia, $1.5 million spent in Ghana, and $1.4 million spent in Nigeria, as well as a $33.0 million write-off of the Company's suspended exploratory well costs related to the Miocene and Pliocene exploration drilling that were drilled during prior years but were waiting for further evaluation by the company.

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The $16.4 million exploration expenditures in 2015 include $7.7 million in Kenya primarily for 2-D seismic acquisition and processing, $5.1 million spent in The Gambia primarily for 3-D seismic acquisition, $1.8 million spent in Ghana for exploration activities, and $1.8 million spent in Nigeria for certain additional exploration studies.
 
Depreciation, Depletion, and Amortization (“DD&A”)
 
DD&A expenses for 2017 were $55.3 million as compared to $58.1 million in 2016 . DD&A expenses decreased in 2017 compared to that in 2016 mainly due to the lower depletion rates in 2017 as compared to that during the same period in 2016. The decrease in the average depletion rate was mainly due to the impairment of oil and gas properties recorded in June 2017 which reduced the overall depletion base for the second half of 2017.

DD&A expenses for 2016 were $58.1 million as compared to $97.2 million in 2015 . DD&A expenses decreased in 2016 primarily due to lower depletion rates in 2016 as compared to that in 2015. The decrease in the average depletion rate was mainly due to the impairment of oil and gas properties recorded at December 31, 2015, which reduced the overall depletion base for 2016.

Average depletion rates were $30.00/Bbl, $33.9/Bbl, and $68.4/Bbl in 2017, 2016, and 2015, respectively.

Accretion of Asset Retirement Obligations ( "ARO" )

Accretion of ARO for the years ended December 31, 2017, 2016 and 2015 was $1.9 million for each year, respectively.

Impairment of Oil and Gas Properties

The Company reviews its long-lived assets for possible impairment whenever facts and circumstances indicate that the carrying value of the said assets may not be recoverable over time under existing market conditions.

During 2017, the Company recorded an impairment charge of $78.7 million, including a charge of $78.1 million to write down the carrying value of its oil and gas properties to their estimated fair market value and $0.6 million to write-off the carrying value of its onshore leases in Kenya which had expired.

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

In December 2015, the Company recorded an impairment charge of $261.2 million for the year ended December 31, 2015 , including a charge of $228.6 million to write down the carrying value of its oil and gas properties to their estimated fair market values, and a charge of $32.6 million to write-off the carrying value of well Oyo-5 from work in progress because the Company no longer intends to recomplete it into a water injection well under current plans.

Loss on Settlement of Asset Retirement Obligations

No plug and abandonment ("P&A") activity occurred during 2017 . The Company recorded P&A expenses of $0.2 million during 2016 . In April 2015, the Company completed P&A activities for well Oyo-6, which was previously shut-in. Actual P&A expenditures exceeded estimated P&A liabilities by $3.7 million in 2015. Accordingly, the Company recognized a $3.7 million loss on settlement of its asset retirement obligations during 2015.

General and Administrative (“G&A”)
 
G&A expenses for 2017 were $11.1 million , as compared to $13.8 million and $15.9 million for 2016 and 2015 , respectively. The decreasing trend in G&A expenses is mainly due to the ongoing cost reduction initiatives, primarily related to employee costs and professional and consulting fees. In addition, the Company incurred non-cash stock-based compensation expenses of $1.9 million , $2.9 million , and $5.0 million for the years 2017 , 2016 , and 2015 , respectively.

Gain or Loss on Sale of Oil and Gas Properties and on Disposal of Other Property and Equipment

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For the year ended December 31, 2017, the Company recorded a $2.3 million gain on the disposal of oil and gas properties arising from the sale of our Gambian blocks and a loss on asset disposal related to office furniture and leasehold improvements of $0.1 million . There were no such activities for the years ended December 31, 2016 and 2015.

Other Income (Expense), Net
 
The Company recorded other expense of $22.4 million in 2017 , as compared to $6.3 million in 2016 and $15.5 million in 2015 . During 2017 , the Company recorded $27.7 million in interest expense on borrowings, partially offset by a $5.2 million gain on foreign currency transactions. In 2016 , the Company recorded $21.9 million in interest expense, net of capitalized interest, on borrowings, partially offset by a $15.7 million gain on foreign currency transactions. In 2015 , the Company recorded $18.0 million in interest expense on borrowings, net of capitalized interest, partially offset by a $2.5 million gain on foreign currency transactions.
 
Income Taxes
 
Income taxes were nil for the years 2017 , 2016 and 2015 . The Company had negative taxable earnings in Nigeria, and therefore was not subject to Petroleum Profit Taxes for each of the years 2017 , 2016 and 2015 .

Headline Earnings
 
In addition to our primary listing on the NYSE American, our common stock is also traded on the JSE. We are required to publish all documents filed with the U.S. Securities and Exchange Commission (“SEC”) on the JSE. The JSE also requires that we calculate and publicly disclose Headline Earnings Per Share (“HEPS”) which, according to 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 separately identifiable remeasurements, net of related tax and related non-controlling interest.
 
Basic and diluted HEPS is calculated using net loss adjusted for impairment on oil and gas properties for the years ended December 31, 2017 , 2016 and 2015 . The number of shares used to calculate basic and diluted HEPS is the same as basic and diluted loss per share as reported under U.S. GAAP.

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

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 	Years Ended December 31,	
(In thousands, except for per share amounts)	2017	 	2016	 	2015	
Net loss attributable to Erin Energy Corporation	$	(151,892	)	 	$	(142,401	)	 	$	(430,937	)	
Adjustments:	 	 	 	 	 	
Loss on disposal of other property and equipment	148		 	—		 	—		
Gain on sale of oil and gas properties	(2,348	)	 	—		 	—		
Impairment of oil and gas properties	78,711		 	645		 	261,208		
 	 	 	 	 	 	
Net loss used to calculate HEPS	$	(75,381	)	 	$	(141,756	)	 	$	(169,729	)	
 	 	 	 	 	 	
Weighted average number of shares used to calculate basic net loss per share and basic HEPS	213,713		 	212,318		 	211,616		
 	 	 	 	 	 	
Weighted average number of shares used to calculate dilutive net loss per share and diluted HEPS	213,713		 	212,318		 	211,616		
 	 	 	 	 	 	
Headline earnings per share:	 	 	 	 	 	
Basic	$	(0.35	)	 	$	(0.67	)	 	$	(0.80	)	
Diluted	$	(0.35	)	 	$	(0.67	)	 	$	(0.80	)	

LIQUIDITY AND CAPITAL RESOURCES
 
Cash Flows
 
The table below sets forth a summary of the Company’s cash flows for the years ended December 31, 2017 , 2016 , and 2015 :

	
												
 	Years Ended December 31,	
(In thousands)	2017	 	2016	 	2015	
Net cash provided by operating activities	$	26,057		 	$	6,355		 	$	2,145		
Net cash used in investing activities	$	(61,015	)	 	$	(19,293	)	 	$	(84,039	)	
Net cash provided by financing activities	$	49,915		 	$	6,073		 	$	63,886		
Effect of exchange rate changes on cash	$	—		 	$	5,679		 	$	1,228		
Net increase (decrease) in cash and cash equivalents	$	14,957		 	$	(1,186	)	 	$	(16,780	)	
 
Cash Flows from Operating Activities
 
The increase in net cash provided by operating activities of $19.7 million in 2017 as compared to 2016 was primarily due to higher revenues and higher non-cash adjustments to net loss, offset by a decrease in vendor financing.

The increase in net cash provided by operating activities of $4.2 million in 2016 as compared to 2015 was primarily due to a combination of higher revenues and use of vendor financing.
 
Cash Flows from Investing Activities
 
Cash used in investing activities for the year ended December 31, 2017 was $61.0 million , as compared to $19.3 million for the same period in 2016. Cash used in investing activities for 2017 was primarily used for costs related to the drilling of the Oyo-9 well and the Oyo-NW exploration well. Cash used in investing activities for 2016 was primarily due to the payment of outstanding liabilities associated with additions to property, plant, and equipment for the Oyo field redevelopment campaign in the OMLs, some of which originated in 2015.

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The cash used in investing activities for the year ended December 31, 2016 was $19.3 million, as compared to $84.0 million for the same period in 2015. Cash used in investing activities for both periods was used primarily to settle outstanding liabilities associated with additions to property, plant, and equipment for the Oyo field redevelopment campaign in the OMLs.
 
Cash Flows from Financing Activities
 
Net cash provided by financing activities of $49.9 million during the year ended December 31, 2017 , consisted of $0.2 million of proceeds from a short-term note payable from a related party, $11.7 million of proceeds from the 2017 Loan Agreement, and $65.7 million of proceeds from the MCB Finance Facility, partially offset by a $9.1 million principal repayment of our Term Loan Facility, $8.7 million payment for debt issuance costs, $0.1 million repayment of the MCB Finance Facility, $0.7 million payment to settle withholding tax obligations upon vesting of restricted stock awards, and $9.1 million of funds restricted for debt servicing.

Net cash provided by financing activities of $6.1 million during the year ended December 31, 2016 , consisted of $6.1 million of funds released from restricted cash, $6.8 million inflows from short-term borrowings from related parties, $0.5 million of proceeds from a short-term note payable, and $0.4 million of proceeds from the exercise of stock options, partially offset by $6.0 million of principal repayment of our Term Loan Facility, $1.0 million of payment for debt issuance costs, $0.4 million repayment of short-term note payable, and $0.2 million in connection with a payment to settle withholding tax obligations upon vesting of restricted stock awards.

In 2015, of the $63.9 million cash from financing activities, $62.4 million was from related party debt borrowings and from funding from a non-controlling interest and $1.9 million was obtained from the issuance of common stock pursuant to the exercise of stock warrants.
 
Capital Resources

The Company has incurred losses from operations in each of the years ended December 31, 2017, 2016 and 2015. As of December 31, 2017, the Company's total current liabilities of $398.3 million exceeded its total current assets of $51.3 million , resulting in a working capital deficit of $347.0 million .

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

As of December 31, 2017 , we had available unrestricted cash of approximately $22.1 million and total current assets of approximately $51.3 million . Conversely, we had total current liabilities of $398.3 million , of which $277.4 million include accounts payable and accrued liabilities.

Well Oyo-7 is currently shut-in as a result of an emergency shut-in of the Oyo field production that occurred in early July 2016. This has resulted in a loss of approximately 1,400 BOPD from the field. The Company is currently working on relocating an existing gaslift line to well Oyo-7 to enable continuous gaslift operation. For cost effectiveness, the relocation of the gaslift line to well Oyo-7 is now planned to be combined with the Oyo-9 subsea equipment installation scheduled for the second half of 2018, subject to fund availability. In October 2017, the Company successfully completed the drilling phase of the Oyo-9 well. However, due to chronic delays in the release of the remaining funds and improper interference by the guarantor of the MCB Finance Facility, the Company temporarily suspended the completion and hookup of the Oyo-9 well.

In February 2017, the Company and its subsidiary, EPNL, entered into a Pre-export Finance Facility Agreement (the “MCB Finance Facility”) with The Mauritius Commercial Bank Limited . See Note 8. - Debt - Long-Term Debt - MCB Finance Facility and Related Agreements, to the Notes to Consolidated Financial Statements for further information.

We are currently pursuing a number of potential financing actions, including i) obtaining additional funds through public or private financing sources, ii) restructuring existing debts from lenders, iii) obtaining forbearance of debt from trade creditors, iv) reducing ongoing operating costs, v) minimizing projected capital costs for the remaining 2018 exploration and development campaign, vi) farming-out a portion of our rights to certain of our oil and gas properties and vii) exploring potential business combination transactions. Sufficient liquidity may not be raised from one or more of these actions and these actions may not be consummated within the period needed to meet certain obligations.

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

CONTRACTUAL OBLIGATIONS
 
The following table summarizes the Company’s significant estimated future contractual obligations at December 31, 2017 :

	
																				
 	Payments Due By Period	
(In thousands)	Total	 	2018	 	2019-2020	 	2021-2022	 	Thereafter	
Long-term debt obligations:	 	 	 	 	 	 	 	 	 	
Notes payable - related party	$	129,800		 	$	—		 	$	123,400		 	$	—		 	$	6,400		
Term loan facility	79,576		 	19,504		 	47,874		 	12,198		 	—		
MCB Finance Facility	65,596		 	65,596		 	—		 	—	 	—	
JSC 2017 Note	11,688		 	3,896		 	7,792		 	 	 	 	
Operating lease obligations:		 	 	 	 	 	 	 	 	
FPSO - Nigeria	145,087		 	48,363		 	96,724		 	—		 	—		
Office leases	972		 	485		 	448		 	39		 	—		
Minimum work obligations:		 	 	 	 	 	 	 	 	
The Gambia	145		 	145		 	—		 	—		 	—		
Purchase obligations	4,201		 	4,201		 	—		 	—		 	—		
Total	$	437,065		 	$	142,190		 	$	276,238		 	$	12,237		 	$	6,400		
 
The minimum obligations for The Gambia and Ghana require annual surface rental payments, training and community fees, all of which have been included in the above table.
 
Off-Balance Sheet Arrangements
 
From time-to-time, we may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As of December 31, 2017 , material off-balance sheet obligations include operating leases with 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.
 
CRITICAL ACCOUNTING POLICIES
 
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amounts of reported assets, liabilities and oil and natural gas reserve quantities. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States.

Successful Efforts Method of Accounting for Oil and Gas Activities
 
We follow the successful efforts method of accounting for our costs of acquisition, exploration and development of oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Drilling costs of exploratory wells are capitalized pending determination that proved reserves have been found. If the determination is dependent upon the results of planned additional wells and require additional capital expenditures to develop the reserves, the drilling costs will be capitalized as long as sufficient reserves have been found to justify

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completion of the exploratory well as a producing well, and additional wells are underway or firmly planned to complete the evaluation of the well. Exploratory wells not meeting the criteria for continued capitalization are expensed when such a determination is made. Other exploration costs are expensed as incurred.

Depreciation, depletion and amortization costs for productive oil and gas properties are recorded on a unit-of-production basis. For other depreciable property, depreciation is recorded on a straight-line basis over the estimated useful life of the assets, which range between three to five years, or the lease term if shorter. Repairs and maintenance charges, including workover costs, are charged to expense as incurred.
 
Impairment of Long-Lived Assets
 
We review our long-lived assets in property, plant and equipment for impairment each reporting period, or whenever changes in circumstances indicate that the carrying amount of assets may not be fully recoverable. Possible indicators of impairment include lower expected future oil and gas prices, actual or expected future development or operating costs significantly higher than previously anticipated, significant downward oil and gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable.
 
An impairment loss is recognized for proved properties when the estimated undiscounted future cash flows expected to result from the asset are less than its carrying amount. We estimate the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset. Our cash flow projections into the future include assumptions on variables, such as future sales, sales prices, operating costs, economic conditions, market competition and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount over the fair value of the assets.
 
In December 2015, the Company recorded an impairment charge of $261.2 million, including a charge of $228.6 million to write down the carrying value of its oil and gas properties to their estimated fair market values, and a charge of $32.6 million to write-off the carrying value of well Oyo-5 from a suspended work in progress well because the Company elected not to recomplete it into a water injection well under current plans.

There were no impairment charges for our long-lived assets during the year ended December 31, 2016.

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

Unevaluated leasehold costs are assessed for impairment at the end of each reporting period and transferred to proved oil and gas properties to the extent they are associated with successful exploration activities. Significant unevaluated leasehold costs are assessed individually for impairment, based on our current exploration plans, and any indicated impairment is charged to expense. In December 2016, the Company recorded an impairment charge of $0.6 million , mainly to write-off the carrying value of its offshore leases in Kenya. In June 2017, the Company recorded a non-cash impairment charge of $0.6 million to write-off the carrying value of its onshore leases in Kenya.
 
Asset Retirement Obligations
 
We recognize a liability for asset retirement obligations ("ARO") in accordance with applicable accounting standards. These standards require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. The ARO liability represents the present value, using a credit-adjusted risk free interest rate, of the estimated site restoration costs with a corresponding increase to the carrying amount of the related long-lived assets. See Note 7. — Asset Retirement Obligations to the Notes to Consolidated Financial Statements for further information.

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

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

RECENTLY ISSUED ACCOUNTING STANDARDS
 
For more information on recently issued accounting standards, see Note 2. - Basis of Presentation and Significant Accounting Policies to the Notes to Consolidated Financial Statements.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We 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 condition 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 macro economic conditions, and other factors beyond our control.
 
The weighted average exchange rate between the U.S. dollar and the Nigerian Naira was 237.59 Naira per each U.S. dollar in the year ended December 31, 2017 . For the year ended December 31, 2017 , a 10% fluctuation in the weighted average exchange rate between the U.S. dollar and the Nigerian Naira would have had an approximate $5.6 million impact on our capital and operating costs in Nigeria.
 
To date, we have not engaged in hedging activities to hedge our foreign currency exposure in our foreign operations. In the future, we may enter into hedging instruments to manage our foreign currency exchange risk or continue to be subject to exchange rate risk.
 
Commodity Price Risk
 
As an independent oil producer, our revenue, other income and profitability, reserves 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 sales 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 year ended December 31, 2017 , a $10.00 fluctuation in the prices received for our crude oil sales would have had an approximate $16.1 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 year ended December 31, 2017 , the weighted average interest rate on our variable rate debt was 7.91%. Assuming our current level of borrowings, a 100 basis point

53

increase in the interest rates we pay under our various debt facilities would result in an increase of our interest expense by $2.9 million over a twelve month period.
 
ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
 
The Company’s Consolidated Financial Statements and the accompanying Notes that are filed as part of this Annual Report are listed under Item 15. Exhibits, Financial Statements and Schedules and are set forth immediately following the signature pages of this Form 10-K.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	
 
None.
 
ITEM 9A.    CONTROLS AND PROCEDURES
 
Evaluation of Disclosure Controls and Procedures
 
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our 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 our Chief Executive Officer (“CEO”) and Principal Financial Officer (“PFO”), as appropriate, to allow timely decisions regarding required disclosures.
 
Our management, with the participation of our CEO and PFO, evaluated the effectiveness of our disclosure controls and procedures. Based on their evaluation, as of the end of the period covered by this Form 10-K, our CEO and PFO have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective.
 
Management’s Report On Internal Control Over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, our principal executive and principal financial officers and is effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles (“GAAP”) and includes those policies and procedures that:

•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets;	
		
•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and	
		
•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.	
 
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Furthermore, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time. Our system contains self-monitoring mechanisms, and actions are taken to correct deficiencies as they are identified.
 
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2017 , based on the criteria described in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
Based on this assessment, management, including the Company’s CEO and PFO, concluded that our internal control over financial reporting was effective as of December 31, 2017 .
 
Pannell Kerr Forster of Texas, P.C., the independent registered public accounting firm that audited our consolidated financial statements included in this Form 10-K, has audited the effectiveness of our internal control over financial reporting as of December 31, 2017 , as stated in their report, which is included herein.

55

Changes in Internal Control Over Financial Reporting
 
Except as disclosed below, no change in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2017 , that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

On June 29, 2017, Daniel Ogbonna resigned as Senior Vice President and Chief Financial Officer of the Company, effective as of the close of business on June 30, 2017.

On or around June 30, 2017, Dippo Bello, the Vice President, Financial Planning and Treasurer of the Company, began performing functions similar to those of a principal financial and principal accounting officer of the Company. Mr. Bello will be responsible for those functions moving forward, until a replacement Chief Financial Officer can be located.

56

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
See Report of Independent Registered Public Accounting Firm under Item 15. Exhibits, Financial Statements and Schedules of this Annual Report on Form 10-K.

57

ITEM 9B.    OTHER INFORMATION
 
None.

PART III
 
ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item will be included in the Company’s Definitive Proxy Statement (the “Proxy Statement”) for its 2018 annual meeting of shareholders, and is incorporated by reference. The Proxy Statement will be filed with the SEC within 120 days subsequent to December 31, 2017 .

ITEM 11.    EXECUTIVE COMPENSATION
The information required under Item 11 of Form 10-K will be set forth in the 2018 Proxy Statement and is incorporated herein by reference.
 
ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required under Item 12 of Form 10-K will be set forth in the 2018 Proxy Statement and is incorporated herein by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required under Item 13 of Form 10-K will be set forth in the 2018 Proxy Statement and is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required under Item 14 of Form 10-K will be set forth in the 2018 Proxy Statement and is incorporated herein by reference.

58

PART IV
 
ITEM 15.    EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES
 
(a) Documents filed as part of this Annual Report:
 
The following is an index of the financial statements, schedules and exhibits included in this Form 10-K or incorporated herein by reference.

	
			
(1)	Consolidated Financial Statements	 	
 	Reports of Independent Registered Public Accounting Firm s	F-1	
 	Consolidated Balance Sheets at December 31, 2017 and 2016	F-4	
 	Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	F-5	
 	Consolidated Statements of Comprehensive Loss for the years ended December 31, 2017, 2016 and 2015	F-6	
 	Consolidated Statements of Changes in Equity (Capital Deficiency) for the years ended December 31, 2017, 2016 and 2015	F-7	
 	Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	F-8	
 	Notes to Consolidated Financial Statements	F-10	
(2)	Consolidated Financial Statement Schedules	 	
 	Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)	S-1	
 	Schedules not included have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes	 	
(3)	Exhibits	 	

59

The following exhibits are filed with, and/or incorporated by reference, in this report:

			
Exhibit Number	 	Description	
2.1	 	Transfer Agreement, dated as of November 19, 2013, by and among CAMAC Energy Inc., CAMAC Petroleum Limited, CAMAC Energy Holdings Limited, CAMAC International (Nigeria) Limited and Allied Energy Plc (incorporated by reference to Exhibit 2.1 of our Form 8-K filed on November 22, 2013).	
3.1	 	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of the Company, dated February 13, 2014 (incorporated by reference to Exhibit 3.1 of our Form 8-K filed on February 19, 2014).	
3.2	 	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of the Company, dated April 7, 2010 (incorporated by reference to Exhibit 3.1 of our Form 8-K filed on April 13, 2010).	
3.3	 	Amended and Restated Certificate of Incorporation of the Company, dated May 3, 2007 (incorporated by reference to Exhibit 3.1 of our Form 10-SB filed on August 16, 2007).	
3.4	 	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).	
3.5	 	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of the Company as of April 22, 2015 (incorporated by reference to Exhibit 3.4 of our Quarterly Report on Form 10-Q filed on May 8, 2015).	
3.6	 	First Amendment to the Amended and Restated Bylaws of the Company adopted on March 11, 2016(incorporated by reference to Exhibit 3.1 of our Form 8-K filed on March 17, 2016).
	
4.1	 	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of our Form 10-SB filed on August 16, 2007).	
4.2	 	Form of Common Stock Warrant (incorporated by reference to Exhibit 4.2 of our Form 10-SB filed on August 16, 2007).	
4.3	 	Company 2007 Stock Plan (incorporated by reference to Exhibit 10.1 of our Form 10-SB filed on August 16, 2007). *	
4.4	 	Company 2009 Equity Incentive Plan (incorporated by reference to Registration Statement on Form S-8 filed on July 1, 2011). (File Number 333-175294)*	
4.5	 	First Amendment to the Company’s Amended 2009 Equity Incentive Plan, dated February 18, 2014 (incorporated by reference to Exhibit 99.1 of our Form 8-K filed on February 19, 2014).	
4.6	 	Form of Series A Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 12, 2010).	
4.7	 	Form of Series C Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on March 3, 2010).	
4.8	 	Registration Rights Agreement, by and between the Company and CAMAC Energy Holdings Limited, dated April 7, 2010 (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on April 13, 2010).	
4.9	 	Form of Warrant (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on December 23, 2010).	
4.10	 	Registration Rights Agreement, dated as of February 15, 2011, by and among the Company, CAMAC Energy Holdings Limited, Allied Energy Plc, and CAMAC International (Nigeria) Limited (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 16, 2011).	
4.11	 	Registration Rights Agreement, dated February 21, 2014, by and between the Company and Allied Energy Plc (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 27, 2014).	
4.12	 	Registration Rights Agreement, dated February 21, 2014, by and between the Company and The Public Investment Corporation (SOC) Limited (incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed on February 27, 2014).	
10.1	 	Form of Securities Purchase Agreement, dated February 10, 2010 (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed on February 12, 2010).	
10.2	 	Company 2007 Stock Plan form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 of our Form 10-SB filed on August 15, 2007). *	
10.3	 	Company 2007 Stock Plan form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of our Form 10-SB filed on August 15, 2007). *	
10.4	 	Form of Indemnification Agreement for Officers (incorporated by reference to Exhibit 10.4 of our Annual Report on Form 10-K filed on April 15, 2013). *	
10.5	 	Form of Indemnification Agreement for Directors (incorporated by reference to Exhibit 10.5 of our Annual Report on Form 10-K filed on April 15, 2013). *	

60

	
			
Exhibit Number	 	Description	
10.6	 	Company 2009 Equity Incentive Plan form of Stock Option Agreement (incorporated by reference to Exhibit 10.5 of our Annual Report on Form 10-K filed on March 2, 2010).*	
10.7	 	Purchase and Sale Agreement, dated November 18, 2009, by and among the Company, CAMAC Energy Holdings Limited, CAMAC International (Nigeria) Limited, and Allied Energy Plc. (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on November 23, 2009).	
10.8	 	Form of Securities Purchase Agreement, dated March 2, 2010 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed March 3, 2010).	
10.9	 	Production Sharing Contract , dated July 22, 2005, by and between Allied Energy Resources Nigeria Limited, CAMAC International (Nigeria) Limited, and Nigerian Agip Exploration Limited (incorporated by reference to Annex E on our Form DEF 14A filed March 19, 2010).	
10.10	 	Agreement Novating Production Sharing Contract, by and among Allied Energy Plc, CAMAC International (Nigeria) Limited, Nigerian Agip Exploration Limited, and CAMAC Petroleum Limited, dated April 7, 2010 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K dated April 13, 2010).	
10.11	 	The Oyo Field Agreement, by and among Allied Energy Plc, CAMAC Energy Holdings Limited and CAMAC Petroleum Limited, dated April 7, 2010 (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on April 13, 2010).	
10.12	 	The Right of First Refusal Agreement, by and among the Company, CAMAC Energy Holdings Limited, CAMAC International (Nigeria) Limited, and Allied Energy Plc, dated April 7, 2010 (incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed on April 13, 2010).	
10.13	 	Purchase and Continuation Agreement, dated December 10, 2010, by and among CAMAC Energy Inc., CAMAC Petroleum Limited, CAMAC Energy Holdings Limited, Allied Energy Plc, and CAMAC International (Nigeria) Limited (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on December 13, 2010).	
10.14	 	Form of Securities Purchase Agreement (incorporated by reference to Exhibit 10.1 of our Current Report filed on December 23, 2010).	
10.15	 	Limited Waiver Agreement Related to Purchase and Continuation Agreement, dated as of February 15, 2011, by and among CAMAC Energy Inc., CAMAC Petroleum Inc., CAMAC Energy Holdings Limited, Allied Energy Plc, and CAMAC International (Nigeria) Limited (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on February 16, 2011) .	
10.16	 	Second Agreement Novating Production Sharing Contract, dated as of February 15, 2011, by and among Allied Energy Plc, CAMAC International (Nigeria) Limited, Nigerian Agip Exploration Limited, and CAMAC Petroleum Limited (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on February 16, 2011).	
10.17	 	Amended and Restated Oyo field Agreement Hereby Renamed OML 120/121 Management Agreement, dated as of February 15, 2011, by and among CAMAC Petroleum Limited, CAMAC Energy Holdings Limited, and Allied Energy Plc (incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed on February 16, 2011).	
10.18	 	Promissory Note Agreement dated June 6, 2011 by and among CAMAC Petroleum Limited and Allied Energy Plc. (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on June 9, 2011).	
10.19	 	Guaranty Agreement dated June 6, 2011 by and among CAMAC Energy Inc. and Allied Energy Plc. (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on June 9, 2011).	
10.20	 	Executive Employment Agreement dated September 1, 2011 by and between Nicholas J. Evanoff and the Company (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on September 7, 2011).*	
10.21	 	Executive Employment Agreement dated September 1, 2011 by and between Babatunde Omidele and the Company (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on September 7, 2011).*	
10.22	 	Executive Consulting Agreement effective March 1, 2012 by and between Earl W. McNiel and the Company (incorporated by reference to Exhibit 10.47 of our Annual Report on Form 10-K filed on March 15, 2012).*	
10.23	 	Production Sharing Contract, by and between the Government of the Republic of Kenya and Erin Energy Kenya Limited, dated May 10, 2012, relating to Block L1B (incorporated by reference to Exhibit 10.4 of our Form 10-Q filed on May 9, 2012).	
10.24	 	Production Sharing Contract, by and between the Government of the Republic of Kenya and Erin Energy Kenya Limited, dated May 10, 2012, relating to Block L16 (incorporated by reference to Exhibit 10.5 of our Form 10-Q filed on May 9, 2012).	
10.25	 	Production Sharing Contract, by and between the Government of the Republic of Kenya and Erin Energy Kenya Limited, dated May 10, 2012, relating to Block L27 (incorporated by reference to Exhibit 10.6 of our Form 10-Q filed on May 9, 2012).	

61

	
			
Exhibit Number	 	Description	
10.26	 	Production Sharing Contract, by and between the Government of the Republic of Kenya and Erin Energy Kenya Limited, dated May 10, 2012, relating to Block L28 (incorporated by reference to Exhibit 10.7 of our Form 10-Q filed on May 9, 2012).	
10.27	 	Petroleum (Exploration, Development and Production) License, by and between the Republic of The Gambia and CAMAC Energy A2 Gambia Ltd., dated May 24, 2012, relating to Block A2 (incorporated by reference to Exhibit 10.8 of our Form 10-Q filed on May 9, 2012).	
10.28	 	Petroleum (Exploration, Development and Production) License, by and between the Republic of The Gambia and CAMAC Energy A5 Gambia Ltd., dated May 24, 2012, relating to Block A5 (incorporated by reference to Exhibit 10.9 of our Form 10-Q filed on May 9, 2012).	
10.29	 	Share Sale and Purchase Agreement, by and between Leyshon Resources Limited and CAMAC Energy Inc., dated July 22, 2012 (incorporated by reference to Exhibit 10.1 of our Form 10-Q filed on November 9, 2012).	
10.30	 	Executive Employment Agreement dated February 27, 2013 by and between Earl W. McNiel and the Company (incorporated by reference to Exhibit 10.38 of our Annual Report on Form 10-K filed April 15, 2013).*	
10.31	 	Amended and Extended Maturity Date of the Promissory Note dated June 6, 2011, amended August 3, 2012, by and among CAMAC Petroleum Limited and Allied Energy Plc (incorporated by reference to Exhibit 10.39 of our Form 10-K filed on April 15, 2013).	
10.32	 	Amended and Extended Maturity Date of the Promissory Note dated June 6, 2011, amended March 25, 2013, by and among CAMAC Petroleum Limited and Allied Energy Plc (incorporated by reference to Exhibit 10.40 of our Form 10-K filed on April 15, 2013).	
10.33	 	Technical Services Agreement, by and between Allied Energy Plc and CAMAC Petroleum Limited, dated January 10, 2013 (incorporated by reference to Exhibit 10.41 of our Form 10-K filed on April 15, 2013).	
10.34	 	Amended and Restated Promissory Note, effective September 10, 2013, by and among CAMAC Petroleum Limited and Allied Energy Plc (incorporated by reference to Exhibit 10.1 of our Form 10-Q filed on November 14, 2013).	
10.35	 	Amendment No. 1 to Guaranty Agreement, effective September 10, 2013, by and among the Company and Allied Energy Plc (incorporated by reference to Exhibit 10.2 of our Form 10-Q filed on November 14, 2013).	
10.36	 	Equitable Share Mortgage Arrangement, effective September 10, 2013, by and among the Company and Allied Energy Plc (incorporated by reference to Exhibit 10.3 of our Form 10-Q filed on November 14, 2013).	
10.37	 	Executive Employment Agreement, dated September 1, 2013, by and between Heidi Wong and the Company (incorporated by reference to Exhibit 10.4 of our Form 10-Q filed on November 14, 2013).*	
10.38	 	Share Purchase Agreement, effective as of November 18, 2013, by and between CAMAC Energy Inc. and Public Investment Corporation (SOC) Limited (incorporated by reference to Exhibit 10.1 of our Form 8-K filed on November 22, 2013).	
10.39	 	Third Agreement Novating Production Sharing Contract, dated as of November 19, 2013, by and among Allied Energy Plc, CAMAC International (Nigeria) Limited and CAMAC Petroleum Limited (incorporated by reference to Exhibit 10.2 of our Form 8-K filed on November 22, 2013).	
10.40	 	Convertible Subordinated Note, dated February 21, 2014, by and between the Company and Allied Energy Plc. (incorporated by reference to Exhibit 4.2 of our Form 8-K filed on February 27, 2014).	
10.41	 	Assignment and Bill of Sale, dated February 21, 2014, by and between Allied Energy Plc and CAMAC Petroleum Limited (incorporated by reference to Exhibit 10.1 of our Form 8-K filed on February 27, 2014).	
10.42	 	Right of First Refusal and Corporate Opportunities Agreement, dated February 21, 2014, by and among the Company and CAMAC Energy Holdings Limited (incorporated by reference to Exhibit 10.2 of our Form 8-K filed on February 27, 2014).	
10.43	 	Corporate Guarantee, dated July 22, 2014, by CAMAC Energy Inc. to Zenith Bank PLC (incorporated by reference to Exhibit 10.43 to the Company’s Annual Report on Form 10-K filed on March 16, 2015).	
10.44	 	Term Loan Facility Agreement for the Expansion and Development of the Oil Block OML 120 and 121, dated September 30, 2014, among CAMAC Petroleum Limited and Zenith Bank PLC (incorporated by reference to Exhibit 10.44 to the Company’s Annual Report on Form 10-K filed on March 16, 2015).	
10.45	 	Corporate Guarantee, dated December 15, 2014, by CAMAC Energy Inc. to Zenith Bank PLC (incorporated by reference to Exhibit 10.45 to the Company’s Annual Report on Form 10-K filed on March 16, 2015).	
10.46	 	Joint Operating Agreement, dated January 23, 2015, among GNPC Exploration and Production Company Limited, CAMAC Energy Ghana Limited, and Base Energy Ghana Limited (incorporated by reference to Exhibit 10.46 to the Company’s Annual Report on Form 10-K filed on March 16, 2015).	
10.47	 	Extension of Maturity Date for the Second Amended and Restated Promissory Note, dated March 9, 2015, among CAMAC Petroleum Limited and Allied Energy Plc (incorporated by reference to Exhibit 10.47 to the Company’s Annual Report on Form 10-K filed on March 16, 2015).	

62

	
			
Exhibit Number	 	Description	
10.48	 	Convertible Note, dated March 11, 2015, by and between the Company and Allied Energy Plc (incorporated by reference to Exhibit 10.48 to the Company’s Annual Report on Form 10-K filed on March 16, 2015).	
10.49	 	Common Stock Purchase Warrant, dated March 11, 2015, by and between the Company and Allied Energy Plc (incorporated by reference to Exhibit 10.49 to the Company’s Annual Report on Form 10-K filed on March 16, 2015).	
10.50	 	Offer of Employment as Senior Vice President and Chief Financial Officer, dated April 28, 2015, by and between the Company and Christopher J. Hearne (incorporated by reference to Exhibit 10.2 on Form 8-K filed on May 8, 2015).	
10.51	 	Separation Agreement and General Release of Claims, dated May 6, 2015, by and between the Company and Earl W. McNiel (incorporated by reference to Exhibit 10.1 on Form 8-K filed on May 8, 2015).	
10.52	 	Block A2 License Amendment, dated May 25, 2015, by and between the CAMAC Energy Gambia Limited and The Republic of the Gambia (incorporated by reference to Exhibit 10.1 on Form 8-K filed on May 29, 2015).	
10.53	 	Block A5 License Amendment, dated May 25, 2015, by and between the CAMAC Energy Gambia Limited and The Republic of the Gambia (incorporated by reference to Exhibit 10.2 on Form 8-K filed on May 29, 2015).	
10.54	 	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).	
10.55	 	Amended and Extended Maturity Date of the Promissory Note dated June 6, 2011, amended October 19, 2015, by and among CAMAC Petroleum Limited and Allied Energy Plc (incorporated by reference to Exhibit 10.2 on Form 10-Q filed on November 9, 2015).	
10.56	 	Offer of Employment as Senior Vice President, General Counsel and Secretary, dated November 12, 2015, by and between the Company and Jean-Michel Malek (incorporated by reference to Exhibit 10.1 on Form 8-K filed on November 18, 2015).	
10.57	 	Extension of Maturity Date for the 2015 Convertible Note dated March 11, 2015, amended March 16, 2016, by and among Erin Energy Corporation and Allied Energy Plc (incorporated by reference to Exhibit 10.57 to the Company’s Annual Report on Form 10-K filed on March 23, 2016).	
10.58	 	Deferment Letter, dated March 30, 2016, from Zenith Bank Plc (incorporated by reference to Exhibit 10.1 on Form 8-K filed on April 5, 2016).	
10.59	 	Promissory Note, dated May 9, 2016, by and between the Company and James Street Capital Partners (incorporated by reference to Exhibit 10.3 on Form 10-Q filed on May 10, 2016).	
10.60	 	Offer Letter to J. Kent Gilliam, dated July 11, 2016 (incorporated by reference to Exhibit 10.1 on Form 10-Q filed on August 8, 2016).*	
10.61	 	Offer for Credit Facility, dated June 17, 2016, by and between Erin Petroleum Nigeria Limited and Zenith Bank PLC (incorporated by reference to Exhibit 10.2 on Form 10-Q filed on August 8, 2016).	
10.62	 	Loan Agreement dated August 3, 2016, by and between Erin Petroleum Nigeria Limited and Zenith Bank PLC (incorporated by reference to Exhibit 10.3 on Form 10-Q filed on August 8, 2016).	
10.63	 	Offer of Employment as Chief Executive Officer, executed July 11, 2016, by and between the Company and Babatunde (Segun) Omidele (incorporated by reference to Exhibit 10.1 on Form 10-Q filed on November 14, 2016).*	
10.64	 	Retention Bonus Agreement, executed November 14, 2016, by and between the Company and Babatunde (Segun) Omidele. (incorporated by reference to Exhibit 10.2 on Form 10-Q filed on November 14, 2016).*	
10.65	 	Pre-export Finance Facility Agreement between Erin Energy Corporation, Erin Petroleum Nigeria Limited and The Mauritius Commercial Bank Limited, dated February 6, 2017 (incorporated by reference to Exhibit 10.1 on Form 8-K filed on February 9, 2017).	
10.66	 	Financing Support Agreement between Erin Energy Corporation and the Public Investment Corporation SOC Ltd., dated February 6, 2017 (incorporated by reference to Exhibit 10.2 on Form 8-K filed on February 9, 2017).	
10.67	 	Override Deed between Erin Energy Corporation, Erin Petroleum Nigeria Limited, Zenith Bank PLC and The Mauritius Commercial Bank Limited, dated February 8, 2017 (incorporated by reference to Exhibit 10.3 on Form 8-K filed on February 9, 2017).	
10.68	 	Extension of Maturity Date for the Second Amended and Restated Promissory Note, dated March 14, 2017, among the Company, CAMAC Petroleum Limited and Allied Energy Plc. (incorporated by reference to Exhibit 10.68 to the Form 10-K for the year ended December 31, 2017, filed on March 16, 2017).	
10.69	 	Extension of Maturity Date for the 2015 Convertible Note dated March 11, 2015, amended March 7, 2017, by and among Erin Energy Corporation and Allied Energy Plc. (incorporated by reference to Exhibit 10.69 to the Form 10-K for the year ended December 31, 2017, filed on March 16, 2017).	

63

	
			
Exhibit Number	 	Description	
10.70	 	Extension of Maturity Date for the 2016 Promissory Note, dated March 14 2017, by and between the Company and James Street Capital Partners. (incorporated by reference to Exhibit 10.70 to the Form 10-K for the year ended December 31, 2017, filed on March 16, 2017).	
10.71	 	Separation Agreement, effective as of May 31, 2017, by and between Erin Energy Corporation and Jean-Michel Malek (incorporated by reference to Exhibit 10.1 of the Form 8-K filed on May 24, 2017).*	
10.72	 	Consulting Agreement, effective as of June 1, 2017, by and between Erin Energy Corporation and Jean-Michel Malek (incorporated by reference to Exhibit 10.1 of the Form 8-K filed on May 24, 2017).*	
10.73	 	Voting Agreement, dated as of July 5, 2017, by and among Dr. Kase Lawal, Latmol Investment Limited and Oltasho Nigeria Limited (incorporated by reference to Exhibit 10.1 on Form 8-K filed on July 7, 2017).	
10.74	 	Loan Agreement, effective as of October 27, 2017, by and between Erin Energy Corporation or its designated affiliate Erin Petroleum Nigeria Limited and James Street Capital Partners Limited (incorporated by reference to Exhibit 10.4 of the Form 10-Q for the quarter ended September 30, 2017, filed on November 8, 2017).	
10.75	 	Convertible Subordinated Note Amendment and Debt Conversion Agreement, dated February 26, 2018, with Oltasho Nigeria Limited. (incorporated by reference to Exhibit 10.1 of the form 8-K filed on February 27, 2018).	
21.1*	 	Subsidiaries of the Company.	
23.1*	 	Consent of Pannell Kerr Forster of Texas, P.C., Independent Registered Public Accounting Firm, filed herewith.	
23.2*	 	Consent of Grant Thornton LLP, Independent Registered Public Accounting Firm, filed herewith.	
23.3*	 	Consent of DeGolyer and MacNaughton.	
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 Principle Financial and Accounting 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 Principle Financial and Accounting Officer Pursuant to 18 U.S.C. § 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
99.1*	 	Report of DeGolyer and MacNaughton.	
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.	
*    Indicates a management contract or compensatory plan or arrangement .
**     Filed herewith.
***    Furnished herewith.

64

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) 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.
 
Dated: March 16, 2018

	
			
 	Erin Energy Corporation	
 	By:	/s/ Sakiru Adefemi (Femi) Ayoade	
 	 	Sakiru Adefemi (Femi) Ayoade	
 	 	Chief Executive Officer	
 	 	(Principal Executive Officer)  	
 	By:	/s/ Dippo Bello	
 	 	Dippo Bello	
 	 	Vice President, Financial Planning and Treasurer	
 	 	(Interim Principal Financial Officer)	
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of registrant and in the capacities and on the dates indicated.

	
					
 	 	Title	 	Date	
/s/ SAKIRU ADEFEMI (FEMI) AYOADE	 	Chief Executive Officer	 	March 16, 2018	
Sakiru Adefemi (Femi) Ayoade	 	(Principal Executive Officer)	 	 	
/s/ DIPPO BELLO	 	Vice President, Financial Planning and Treasurer	 	March 16, 2018	
Dippo Bello	 	(Interim Principal Financial Officer)	 	 	
 
/s/ FRANK INGRISELLI	 	Director	 	March 16, 2018	
Frank Ingriselli	 	 	 	 	
 
/s/ DR. LEE PATRICK BROWN 	 	Director	 	March 16, 2018	
Dr. Lee Patrick Brown	 	 	 	 	
 
/s/ DR. JOHN RUDLEY	 	Director	 	March 16, 2018	
Dr. John Rudley	 	 	 	 	
 
/s/ DUDU HLATSHWAYO	 	Director	 	March 16, 2018	
Dudu Hlatshwayo	 	 	 	 	
 
/s/ MAHMOUD YAYALE AHMED	 	Director	 	March 16, 2018	
Mahmoud Yayale Ahmed	 	 	 	 	
 
/s/ J. MICHAEL STINSON	 	Director	 	March 16, 2018	
J. Michael Stinson	 	 	 	 	

65

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Erin Energy Corporation

Opinions on the Consolidated Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Erin Energy Corporation and subsidiaries (the Company) as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive loss, changes in equity (capital deficiency), and cash flows for each of the years in the two year period ended December 31, 2017 (collectively referred to as the Consolidated Financial Statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the two year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles. Lastly, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by COSO.

Basis for Opinion

The Company’s management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express an opinion on the Company’s Consolidated Financial Statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Going Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to that matter.

F-1

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We have served as the Company’s auditor since 2016.

/s/ PANNELL KERR FORSTER OF TEXAS, P.C.
Houston, Texas
March 16, 2018

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders
Erin Energy Corporation

We have audited the accompanying consolidated balance sheet of Erin Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2015, (not presented herein), and the related consolidated statements of operations, comprehensive loss, changes in equity (capital deficiency), and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Erin Energy Corporation and subsidiaries as of December 31, 2015, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements previously filed in Form 10-K on March 23, 2016, which is not presented herein, the Company incurred net losses in each of the years ended December 31, 2015, 2014 and 2013, and as of December 31, 2015, the Company’s current liabilities exceeded its current assets by $314.8 million. These conditions, along with other matters as set forth in that Note 3, raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in that Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ GRANT THORNTON LLP

Houston, Texas
March 23, 2016 (except for the effects of the adjustments described in Note 16 - Correction of Immaterial Error in Previously Issued Consolidated Financial Statements, included in the Form 10-K previously filed on March 16, 2017, as to which the date is March 16, 2017)

F-3

ERIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except for share and per share data)

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

F-4

ERIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for per share amounts)

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

F-5

ERIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)  

	
												
 	Years Ended December 31,	
 	2017	 	2016	 	2015	
Net loss, before non-controlling interest	$	(152,914	)	 	$	(143,242	)	 	$	(431,899	)	
Comprehensive loss	(152,914	)	 	(143,242	)	 	(431,899	)	
Comprehensive loss attributable to non-controlling interests	1,022		 	841		 	962		
Comprehensive loss attributable to Erin Energy Corporation	$	(151,892	)	 	$	(142,401	)	 	$	(430,937	)	

The accompanying notes are an integral part of these consolidated financial statements.

F-6

ERIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (CAPITAL DEFICIENCY)
(In thousands)  

																											
 	Common Stock	 	Additional Paid-in Capital	 	Accumulated Deficit	 	Treasury Stock	 	Non-controlling Interest	 	Total
Equity ( Capital Deficiency )	
 	Shares	 	Amount	 		 		 		 		 		
At December 31, 2014	210,308		 	$	210		 	$	778,095		 	$	(444,954	)	 	$	—		 	$	654		 	$	334,005		
Common stock issued	1,308		 	2		 	1,978		 	—		 	—		 	—		 	1,980		
Stock-based compensation	—		 	—		 	4,631		 	—		 	—		 	—		 	4,631		
Warrants issued with debt	—		 	—		 	4,911		 	—		 	—		 	—		 	4,911		
Non-controlling interest	—		 	—		 			 	—		 	—		 	1,105		 	1,105		
Net loss	—		 	—		 	—		 	(430,937	)	 	—		 	(962	)	 	(431,899	)	
December 31, 2015	211,616		 	212		 	789,615		 	(875,891	)	 	—		 	797		 	(85,267	)	
Common stock issued	1,106		 	1		 	363		 	—		 	—		 	—		 	364		
Stock-based compensation	—		 	—		 	2,941		 	—		 	—		 	—		 	2,941		
Warrants issued with debt	—		 	—		 	53		 	—		 	—		 	—		 	53		
Transfer to treasury upon vesting of restricted stock, for income taxes	—		 	—		 	—		 	—		 	(228	)	 	—		 	(228	)	
Non-controlling interest	—		 	—		 	—		 	—		 	—		 	759		 	759		
Net loss	—		 	—		 	—		 	(142,401	)	 	—		 	(841	)	 	(143,242	)	
December 31, 2016	212,722		 	213		 	792,972		 	(1,018,292	)	 	(228	)	 	715		 	(224,620	)	
Common stock issued	2,679		 	2		 	3,619		 	—		 			 	—		 	3,621		
Stock-based compensation	—		 	—		 	1,932		 	—		 	—		 	—		 	1,932		
Warrants issued with debt	—		 	—		 	8,950		 	—		 	—		 	—		 	8,950		
Transfer to treasury upon vesting of restricted stock, for income taxes	—		 	—		 	—		 	—		 	(717	)	 	—		 	(717	)	
Non-controlling interest	—		 	—		 	—		 	—		 	—		 	970		 	970		
Net loss	—		 	—		 	—		 	(151,892	)	 	—		 	(1,022	)	 	(152,914	)	
December 31, 2017	215,401		 	$	215		 	$	807,473		 	$	(1,170,184	)	 	$	(945	)	 	$	663		 	$	(362,778	)	
 
The accompanying notes are an integral part of these consolidated financial statements.  

F-7

ERIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

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

F-8

	
												
Discount on notes payable pursuant to issuance of warrants	$	10,785		 	$	53		 	$	4,911		
Reduction in oil and gas properties arising from settlement of accounts payable and accrued liabilities	$	11,478		 	$	10,048		 	$	—		
Reduction in accounts payable from settlement of Northern Offshore contingency	$	—		 	$	—		 	$	24,307		
Receivable from non-controlling interest	$	—		 	$	—		 	$	552		
Shares issued for services	$	93		 	$	—		 	$	—		
Change in asset retirement obligation estimate	$	—		 	$	—		 	$	(4,284	)	
The accompanying notes are an integral part of these consolidated financial statements 

F-9

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
NOTE 1. — COMPANY DESCRIPTION
 
Erin Energy Corporation (NYSE American: ERN, JSE: ERN) is an independent exploration and production company engaged in the acquisition and development of energy resources in Africa. The Company’s asset portfolio consists of five licenses across three countries covering an area of approximately 6,000 square kilometers (approximately 1.5 million acres). The Company owns producing properties and conducts exploration activities offshore Nigeria, and conducts exploration activities offshore Ghana and The Gambia.
 
The Company is headquartered in Houston, Texas and has offices in Lagos, Nigeria, Nairobi, Kenya, and Accra, Ghana.
 
The Company’s operating subsidiaries include Erin Petroleum Nigeria Limited (“EPNL”), Erin Energy Kenya Limited, Erin Energy Gambia Ltd., and Erin Energy Ghana Limited. The terms “we,” “us,” “our,” “the Company,” and “our Company” refer to Erin Energy Corporation and its subsidiaries.
 
The Company also conducts certain business transactions with related parties. See Note 9. — Related Party Transactions for further information.

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

Changes in Control during 2017

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

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

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

F-10

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These change in control events had no accounting impact on the Company.

NOTE 2. — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
 
Basis of Presentation
 
The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned direct and indirect subsidiaries, and have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). All significant intercompany transactions and balances have been eliminated in consolidation. The consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the consolidated financial position and results of operations for the indicated periods. All such adjustments are of a normal recurring nature.

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

Use of Estimates
 
The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates based on assumptions. Estimates affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenues and expenses during the reporting periods. Accordingly, accounting estimates require the exercise of judgment. While management believes that the estimates and assumptions used in the preparation of the Company’s consolidated financial statements are appropriate, actual results could differ from those estimates.
 
Estimates that may have a significant effect on the Company’s financial position and results from operations include share-based compensation assumptions, oil and natural gas reserve quantities, impairment of oil and gas properties, depletion and amortization relating to oil and gas properties, asset retirement obligation assumptions, calculations related to derivative liabilities, and income taxes. The accounting estimates used in the preparation of the consolidated financial statements may change as new events occur, more experience is acquired, additional information is obtained and our operating environment changes.
 
Cash and Cash Equivalents
 
Cash and cash equivalents include cash on hand, demand deposits and short-term investments with initial maturities of three months or less.
 
Restricted Cash
 
Restricted cash consists of cash deposits that are contractually restricted for withdrawal or required to be maintained in a reserve bank account for a specific period of time, as provided for under certain agreements with third parties.
 
Restricted cash as of December 31, 2017 totaling $11.7 million consists of $2.6 million held in a debt service reserve account to secure certain interest and principal repayments pursuant to the Term Loan Facility in Nigeria and $9.1 million held in a debt service account as required under the MCB Finance Facility (see Note 8 - Debt - Long-Term Debt) for further information and definitions of the Term Loan Facility and MCB Finance Facility). Restricted cash as of December 31, 2016 consists of $2.6 million held in a debt service reserve account to secure certain interest and principal repayments pursuant to the Term Loan Facility in Nigeria.

F-11

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accounts Receivable and Allowance for Doubtful Accounts
 
Accounts receivable are accounted for at cost less allowance for doubtful accounts. The Company establishes provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of December 31, 2017 and 2016 , no allowance for doubtful accounts was necessary.
 
As of December 31, 2017 and 2016, the Company had a trade receivable balance of $6.7 million and nil , respectively.

Partner accounts receivable consist of balances owed from joint venture (“JV”) partners. As of December 31, 2017 and 2016 , the Company was owed $1.8 million and $0.7 million , respectively, from its Ghana JV partners for their share of the expenditures incurred in the Shallow Water Tano block, pursuant to the Ghana JV Joint Operating Agreement. 
Crude Oil Inventory
 
Inventories of crude oil are valued at the lower of cost or net realized value using the first-in, first-out method and include certain costs directly related to the production process and depletion, depreciation and amortization attributable to the underlying oil and gas properties. The Company had crude oil inventory of $3.6 million and $9.4 million as of December 31, 2017 and 2016 , respectively.
 
Successful Efforts Method of Accounting for Oil and Gas Activities
 
The Company follows the successful efforts method of accounting for its costs of acquisition, exploration and development of oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Drilling costs of exploratory wells are capitalized pending determination that proved reserves have been found. If the determination is dependent upon the results of planned additional wells and require additional capital expenditures to develop the reserves, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well as a producing well, and additional wells are underway or firmly planned to complete the evaluation of the well. Exploratory wells not meeting the criteria for continued capitalization are expensed when such a determination is made. Other exploration costs are expensed as incurred.
 
A portion of the Company’s oil and gas properties include oilfield materials and supplies inventory to be used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or net realized value, which approximates fair value, and they are regularly assessed for obsolescence. Oilfield materials and supplies inventory balances were $36.7 million and $34.7 million at December 31, 2017 and 2016 , respectively.
 
Depreciation, depletion and amortization costs for productive oil and gas properties are recorded on a unit-of-production basis. For other depreciable property, depreciation is recorded on a straight-line basis over the estimated useful life of the assets, which range between three to five years , or the lease term if shorter. Repairs and maintenance charges, including workover costs, are charged to expense as incurred.
 
Impairment of Long-Lived Assets
 
The Company reviews its long-lived assets in property, plant and equipment for impairment each reporting period, or whenever changes in circumstances indicate that the carrying amount of assets may not be fully recoverable. Possible indicators of impairment include lower expected future oil and gas prices, actual or expected future development or operating costs significantly higher than previously anticipated, significant downward oil and gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable.
 
An impairment loss is recognized for proved properties when the estimated undiscounted future cash flows expected to result from the asset are less than its carrying amount. The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset. The Company’s cash flow projections into the future include assumptions on variables, such as future sales, sales prices, operating

F-12

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

costs, economic conditions, market competition and inflation. Prices used to quantify the expected future cash flows are estimated based on forward prices prevailing in the marketplace and management’s long-term planning assumptions. Impairment is measured by the excess of carrying amount over the fair value of the assets.
 
Unevaluated leasehold costs are assessed for impairment at the end of each reporting period and transferred to proved oil and gas properties to the extent they are associated with successful exploration activities. Significant unevaluated leasehold costs are assessed individually for impairment, based on the Company’s current exploration plans, and any indicated impairment is charged to expense.         
 
Asset Retirement Obligations
 
The Company accounts for asset retirement obligations in accordance with applicable accounting guidelines , which require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. Specifically, the Company records a liability for the present value, using a credit-adjusted risk free interest rate, of the estimated site restoration costs with a corresponding increase to the carrying amount of the related long-lived asset.

Revenues
 
Revenues are recognized when crude oil is delivered to a buyer. The recognition criteria are satisfied when there exists a signed contract with defined pricing, delivery, and acceptance, and there is no significant uncertainty of collectability. Crude oil revenues are recorded net of royalties.
 
Income Taxes
 
The Company accounts for income taxes using the asset and liability method of accounting for income taxes in accordance with applicable accounting rules. Under the asset and liability method, deferred tax assets and liabilities are recognized for temporary differences between the tax bases of assets and liabilities and their carrying values for financial reporting purposes and for operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets to their net realizable amounts if it is more likely than not that the related tax benefits will not be fully realized.
 
The Company routinely evaluates any tax deduction and tax refund position in a two-step process. The first step is to determine whether it is more likely than not that a tax position will be sustained. If that test is met, the second step is to determine the amount of benefit or expense to recognize in the consolidated financial statements. See Note 12. — Income Taxes for further information.
 
Debt Issuance Costs
 
Debt issuance costs consist of certain costs paid to lenders in the process of securing a borrowing facility. Debt issuance costs incurred are capitalized and subsequently charged to interest expense over the term of the related debt, using the effective interest rate method.

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

Capitalized Interest

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

F-13

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Treasury Stock

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

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

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

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

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

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

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

F-14

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net Earnings (Loss) Per Common Share
 
Basic net earnings or loss per common share is computed by dividing net earnings or loss by the weighted average number of shares of common stock outstanding at the end of the reporting period. Diluted net earnings or loss per share is computed by dividing net earnings or loss by the fully dilutive common stock equivalent, which consists of shares outstanding, augmented by potentially dilutive shares issuable upon the exercise of the Company’s stock options, stock warrants, non-vested restricted stock awards, and the conversions of the 2011 Promissory Note, 2014 Convertible Subordinated Note and the 2016 Promissory Note (collectively, the "Convertible Notes"), described and defined below under Note 8. - Debt - Long-Term Debt - Related Party ), calculated using the treasury stock method.
 
The table below sets forth the number of stock options, warrants, non-vested restricted stock, and shares issuable upon conversion of Convertibles Notes that were excluded from dilutive shares outstanding during the years ended December 31, 2017 , 2016 and 2015 , as these securities are anti-dilutive because the Company was in a loss position each year.

	
									
 	Years Ended December 31,	
(In thousands)	2017	 	2016	 	2015	
Stock options	141		 	230		 	1,101		
Stock warrants	39		 	3		 	541		
Unvested restricted stock awards	1,660		 	1,942		 	1,275		
Convertible Notes	—		 	—		 	12,379		
 	1,840		 	2,175		 	15,296		
 
Upon the occurrence of certain events, the Company is also contingently liable to make additional payments to Allied, under the November 2013 Transfer Agreement by the Company and its affiliates, and Allied (the “Transfer Agreement”), up to an additional amount totaling $50.0 million in cash, or the equivalent in shares of the Company’s common stock, at Allied’s option. See Note 10. — Commitments and Contingencies for further information.
 
Non-Controlling Interests
 
The Company reports its non-controlling interests as a separate component of equity. The Company also presents the consolidated net loss and the portion of the consolidated net loss allocable to the non-controlling interests and to the shareholders of the Company separately in its consolidated statements of operations. Losses attributable to the non-controlling interests are allocated to the non-controlling interests even when those losses are in excess of the non-controlling interests’ investment basis.
 
As of December 31, 2017 and 2016 , the non-controlling interest recorded in equity was $1.0 million and $0.8 million , respectively, attributable to the joint ownership of an affiliate in our Erin Energy Ghana Limited subsidiary.

Fair Value Measurements

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

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

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

F-15

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Fair Value on a Recurring Basis

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

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

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

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

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

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

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

F-16

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	
				
 	Year ended	
(in thousands)	December 31, 2017	
Beginning balance	$	—		
Loss (gain) on fair value of derivative liability	(36	)	
Additions	2,046		
Revisions	(211	)	
Transfers	—		
Ending balance	$	1,799		
 	 	
Change in unrealized loss (gain) included in earnings relating to derivatives still held as of December 31, 2017	$	(36	)	

Fair Value on a Non-Recurring Basis

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

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

Fair Value of Financial Instruments

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

Risks and Uncertainties

The Company’s producing properties are located offshore Nigeria.

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

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

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

Recently Issued Accounting Standards

In May of 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, Revenue form Contracts with Customers (Topic 606) . ASU 2014-09 core principal is that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects

F-17

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to be entitled in exchange for those goods or services. The Company has evaluated the impact of this guidance and concluded that this standards update is not expected to have a material impact on the Company’s consolidated financial statements.

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

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

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

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

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

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

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

In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features .

F-18

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASU No. 2017-11 amendments simplify the accounting for certain financial instruments with down round features. The amendments require companies to disregard the down round feature when assessing whether the instrument is indexed to its own stock, for purposes of determining liability or equity classification. Companies that provide earnings per share (EPS) data will adjust their basic EPS calculation for the effect of the feature when triggered (i.e., when the exercise price of the related equity-linked financial instrument is adjusted downward because of the down round feature) and will also recognize the effect of the trigger within equity. ASU No. 2017-11 is effective for interim and annual periods beginning after December 15, 2018, and the Company will adopt this standards update, as required, beginning with the first quarter of 2019. The adoption of this standard update is not expected to have a material impact on the Company’s consolidated financial statements.

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

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

NOTE 3. - LIQUIDITY AND GOING CONCERN

The Company has incurred losses from operations in each of the years ended December 31, 2017, 2016 and 2015. As of December 31, 2017 , the Company's total current liabilities of $398.3 million exceeded its total current assets of $51.3 million , resulting in a working capital deficit of $347.0 million . As a result of the low commodity prices, the Company has not been able to generate sufficient cash from operations to satisfy certain obligations as they became due.

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

The Company is currently pursuing a number of actions, including (i) obtaining additional funds through public or private financing sources, (ii) restructuring existing debts from lenders, (iii) obtaining forbearance of debt from trade creditors, (iv) reducing ongoing operating costs, (v) minimizing projected capital costs for the remaining 2017 exploration and development campaign, (vi) farming-out a portion of its rights to certain of its oil and gas properties and (vii) exploring potential business combination transactions. There can be no assurances that sufficient liquidity can be raised from one or more of these actions or that these actions can be consummated within the period needed to meet certain obligations.
 
The Company's consolidated financial statements have been prepared under the assumption that it will continue as a going concern, which assumes the continuity of operations, the realization of assets and the satisfaction of liabilities as they come due in the normal course of business. Although the Company believes that it will be able to generate sufficient liquidity from the measures described above, its current circumstances raise substantial doubt about its ability to continue to operate as a going concern. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

F-19

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4. — PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment were comprised of the following:

	
								
 	As of December 31,	
(In thousands)	2017	 	2016	
Wells and production facilities	$	308,351		 	$	318,739		
Proved properties	386,196		 	386,196		
Work in progress and exploration inventory	113,303		 	34,712		
Oilfield assets	807,850		 	739,647		
Accumulated depletion and impairment	(614,648	)	 	(483,754	)	
Oilfield assets, net	193,202		 	255,893		
Unevaluated leaseholds	6,200		 	9,820		
Oil and gas properties, net	199,402		 	265,713		
Other property and equipment	2,877		 	3,040		
Accumulated depreciation	(2,518	)	 	(2,324	)	
Other property and equipment, net	359		 	716		
Total property, plant and equipment, net	$	199,761		 	$	266,429		
 
All of the Company’s oilfield assets are located offshore Nigeria in the Oil Mining Leases 120 and 121 (the "OMLs"). “Work-in-progress and exploration inventory” includes warehouse inventory items purchased as part of the redevelopment plan of the Oyo field. During the year ended December 31, 2016, the Company wrote off $33.0 million of suspended exploratory well costs to exploration expense. There was no such write off for the year ended December 31, 2017.
 
The Company’s unevaluated leasehold costs include costs to acquire the rights to the exploration acreage in its various oil and gas properties. At December 31, 2017 and 2016 unevaluated leasehold costs were $6.2 million and $9.8 million , respectively.

The Gambia Sale Agreement

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

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

Impairment of Oil and Gas Properties

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

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

F-20

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 5. — SUSPENDED EXPLORATORY WELL COSTS
 
In November 2013, the Company achieved both its primary and secondary drilling objectives for the well Oyo-7. The primary drilling objective was to establish production from the existing Pliocene reservoir. The secondary drilling objective was to confirm the presence of hydrocarbons in the deeper Miocene formation. Hydrocarbons were encountered in three Miocene intervals totaling approximately 65 feet, as interpreted by the logging-while-drilling (“LWD”) data. As of December 31, 2016 , the Company’s suspended exploratory well costs were $26.5 million for the costs related to the Miocene exploratory drilling activities. Plans were underway to secure a rig to drill at least one exploration well in the nearby G-Prospect. However, due to the then current economics, the primary objective of the G-Prospect was no longer to target the same Miocene formation as the ones found in the Oyo-7 exploratory drilling. As such, during the year ended December 31, 2016 , the Company wrote off the $26.5 million suspended exploratory well costs to exploration expense.
 
In August 2014, the Company drilled well Oyo-8 to a total vertical depth of approximately 6,059 feet (approximately 1,847 meters) and successfully encountered four new oil and gas reservoirs in the eastern fault block, with total gross hydrocarbon thickness of 112 feet, based on results from the LWD data, reservoir pressure measurement, and reservoir fluid sampling. Management completed a detailed evaluation of the results and initially capitalized suspended exploratory well costs amounting to $6.5 million at December 31, 2016 for the costs related to the Pliocene exploration drilling activities in the eastern fault block. During the year ended December 31, 2016, the Company wrote off the $6.5 million to exploration expense as the then current drilling plans no longer specifically targeted such area due to the then current economics.
 
NOTE 6. — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
 
The table below sets forth a summary of the Company’s accounts payable and accrued liabilities at December 31, 2017 and 2016 :

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

NOTE 7. —ASSET RETIREMENT OBLIGATIONS
 
The Company’s asset retirement obligations primarily represent the estimated fair value of the amounts that will be incurred to plug, abandon and remediate its producing properties at the end of their productive lives. Significant inputs used in determining such obligations include, but are not limited to, estimates of plugging and abandonment costs, estimated future inflation rates and changes in property lives. The inputs used in the fair value determination were based on Level 3 inputs, which were essentially management's assumptions.

F-21

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	
								
 	As of December 31,	
(In thousands)	2017	 	2016	
Asset retirement obligations at January 1	$	22,476		 	$	20,609		
Accretion expense	1,933		 	1,867		
Additions	—		 	—		
Revisions in estimated liabilities	—		 	—		
Loss on settlement of asset retirement obligations	—		 	—		
Payments to settle asset retirement obligations	—		 	—		
Asset retirement obligations at December 31	$	24,409		 	$	22,476		
 
Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying consolidated statements of operations.
 
The table below shows the current and long-term portions of the Company's asset retirement obligations as of the end of December 31, 2017 and 2016 :

	
								
 	As of December 31,	
(In thousands)	2017	 	2016	
Asset retirement obligations, current portion	$	—		 	$	—		
Asset retirement obligations, long-term portion	24,409		 	22,476		
 	$	24,409		 	$	22,476		
 
NOTE 8. — DEBT
 
Short-Term Debt:

Short-Term Borrowing - Glencore Advance

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

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

Short-Term Debt - Related Party

On September 19, 2017, the Company, through its wholly-owned subsidiary EPNL, borrowed $0.2 million under a short-term
loan agreement (the "2017 Short-Term Note") entered into with CAMAC Nigeria Limited, an affiliated company, at a flat interest rate of 5% and maturity date of June 30, 2018.

Long-Term Debt:

Term Loan Facility
 
In September 2014, the Company, through its wholly owned subsidiary EPNL, entered into the Term Loan Facility (as amended or modified, the “Term Loan Facility”) with Zenith for a five -year senior secured term loan providing initial borrowing capacity

F-22

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of up to $100.0 million . Of the total commitment provided, 90% of the Term Loan Facility is available in U.S. dollars, while the remaining 10% is available in Nigerian Naira. U.S. dollar borrowings under the Term Loan Facility currently bear interest at the rate of LIBOR plus 11.1% . The obligations under the Term Loan Facility include a legal charge over the OMLs and an assignment of proceeds from oil sales. The obligations of EPNL have been guaranteed by the Company and rank in priority with all its other obligations. Proceeds from the Term Loan Facility were used for the further expansion and development of the Oyo field in Nigeria.
 
In June 2016, the Term Loan Facility was modified contingent upon the signing of a loan agreement, which was signed in August 2016. The modification put in place a twelve month moratorium on principal payments and extended the term of the Term Loan Facility until February 2021. Additionally, it reduced the funding requirement of the debt service reserve account (“DSRA”) to an amount equal to one quarter of interest until the price of oil exceeds $55 per barrel, at which time an amount equal to two quarters of interest will then be required.

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

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

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

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

MCB Finance Facility and Related Agreements

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

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

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

F-23

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

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

On February 8, 2017, and in connection with the MCB Finance Facility, the Company, EPNL, MCB and Zenith, the Company’s existing secured lender, also entered into an Override Deed (the “Override Deed”). The Override Deed establishes, inter alia,

F-24

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

pro-rata rights of MCB and Zenith in respect of the proceeds from the Off-take Contract, governs the mechanics of any enforcement action by the creditors and sets out pro-rata sharing of enforcement proceeds between MCB and Zenith. The Override Deed also grants the necessary consents to EPNL’s entry into the MCB Finance Facility and related documents.

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

2017 James Street Capital Note

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

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

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

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

Long-Term Debt Maturities

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

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

Long-Term Debt - Related Party:

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

F-25

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Allied, a related party, was originally the holder of each of the 2011 Promissory Note, the 2014 Convertible Subordinated Note, and the 2015 Convertible Note (collectively the “Related Party Notes”). During 2017, Oltasho became the holder of each of the Related Party Notes. Please also see Note 1 - Company Description for changes in control in the Company which occurred during 2017.
 
Each of the Related Party Notes contains certain default and cross-default provisions, including failure to pay interest and principal amounts when due, and default under other indebtedness. As of December 31, 2017 , the Company was not in compliance with the default provisions of the Related Party Notes with respect to the payment of quarterly interest. Further, the risk of cross-default exists for each of the Related Party Notes if the holder of the Term Loan Facility exercises its right to terminate the Term Loan Facility and accelerate its maturity. In July 2017, Oltasho agreed to waive through their respective maturity dates its rights under all default provisions of each of the Related Party Notes.

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

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

2014 Convertible Subordinated Note
 
As partial consideration in connection with the February 2014 acquisition of interests in Oil Mining Leases ("OMLs") located offshore Nigeria from Allied, the Company issued the $50.0 million Convertible Subordinated Note in favor of Allied (the "2014 Convertible Subordinated Note"). Interest on the 2014 Convertible Subordinated Note accrues at a rate per annum of one-month LIBOR plus 5% , payable quarterly in cash until the maturity of the 2014 Convertible Subordinated Note five years from the closing of the Allied Transaction.
 
At the election of the holder, the 2014 Convertible Subordinated Note is convertible into shares of the Company’s common stock at an initial conversion price of $4.2984 per share, subject to anti-dilution adjustments. The 2014 Convertible Subordinated Note is subordinated to the Company’s existing and future senior indebtedness and is subject to acceleration upon an Event of Default (as defined in the 2014 Convertible Subordinated Note). The following events, among others, constitute an Event of Default under the 2014 Convertible Subordinated Note: the Company failing to pay interest within thirty days of the due date; the Company failing to pay principal when due; bankruptcy, insolvency, liquidation or dissolution of the Company; a material breach of the 2014 Convertible Subordinated Note by the Company that remains unremedied within ten days of such material breach; or a representation or warranty of the Company proves to have been incorrect or materially inaccurate when made. Upon any event of default, all outstanding principal and interest under any loans will become immediately due and payable. As of December 31, 2017 , outstanding principal and interest was $50.0 million and $11.4 million , respectively.

The Company may, at its option, prepay the 2014 Convertible Subordinated Note in whole or in part, at any time, without premium or penalty. Further, the 2014 Convertible Subordinated Note is subject to mandatory prepayment upon (i) the Company’s issuance of capital stock or incurrence of indebtedness, the proceeds of which the Company does not apply to repayment of senior indebtedness or (ii) any capital markets debt issuance to the extent the net proceeds of such issuance exceed $250.0 million . The holder may assign all or any part of its rights and obligations under the 2014 Convertible Subordinated Note to any person upon written notice to the Company.

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

F-26

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2015 Convertible Note

In March 2015, the Company entered into a borrowing facility with Allied in the form of a Convertible Promissory Note (the "2015 Convertible Note"), allowing the Company to borrow up to $50.0 million for general corporate purposes. In March 2017, the maturity date of the 2015 Convertible Note was extended to April 2018. Interest accrues at the rate of LIBOR plus 5% and is payable quarterly. 

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

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

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

2016 Promissory Note

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

NOTE 9. — RELATED PARTY TRANSACTIONS
 
Assets and Liabilities
 
The Company has transactions in the normal course of business with its shareholders, CEHL and their affiliates. Effective April 3, 2017, Oltasho became a majority shareholder of the Company and the holder of the Related Party Notes. CEHL and its affiliates, which include Allied, are entities controlled by Dr. Lawal. These entities are deemed to be related parties for financial reporting purposes. The table below sets forth the related party assets and liabilities as of December 31, 2017 and 2016 :

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

As of December 31, 2017 and 2016 , the related party receivable balances of $2.9 million and $2.0 million , respectively, were for advance payments made for certain transactions on behalf of affiliates.
 
As of December 31, 2017 and 2016 , the Company owed $40.5 million and $29.5 million , respectively, to affiliates primarily for logistical and support services in relation to the Company's oilfield operations in Nigeria, as well as accrued interest on the various related party notes payable. As of December 31, 2017 and 2016 , accrued and unpaid interest on the various related party notes payable were $23.3 million and $15.2 million , respectively.

F-27

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

As of December 31, 2017 , the Company had a combined note payable balance of $129.8 million owed to affiliates, consisting of $24.9 million in borrowings under the 2011 Promissory Note, $50.0 million in borrowings under the 2014 Convertible Subordinated Note, $48.5 million in borrowings under the 2015 Convertible Note, net of discount and $6.4 million under the 2016 Promissory Note. As of December 31, 2016 , the Company had a long-term note payable balance of $129.8 million owed to an affiliate, consisting of $24.9 million in borrowings under the 2011 Promissory Note, $50.0 million in borrowings under the 2014 Convertible Subordinated Note, and $48.5 million in borrowings under the 2015 Convertible Note, net of discount. See Note 8. - Debt for further information relating to the notes payable transactions.
 
Results from Operations
 
The table below sets forth the transactions incurred with affiliates during the years ended December 31, 2017 , 2016 and 2015 :

	
												
 	Year Ended December 31,	
(In thousands)	2017	 	2016	 	2015	
Total operating expenses	$	11,058		 	$	14,621		 	$	15,106		
Interest expense	$	8,157		 	$	6,843		 	$	5,490		
 
Certain affiliates of the Company provide procurement and logistical support services to the Company’s operations. In connection therewith, during the years ended December 31, 2017 , 2016 and 2015, the Company incurred operating costs amounting to approximately $11.1 million , $14.6 million and $15.1 million , respectively.

During the years ended December 31, 2017 , 2016 and 2015, the Company incurred interest expense, excluding debt discount amortization, totaling approximately $8.2 million , $6.8 million and $5.5 million , respectively, attributed to its related party notes payable.
 
Non-controlling Interests
 
In April 2014, the Company, through its 50% ownership of its Erin Energy Ghana Limited subsidiary, signed a Petroleum Agreement with the Republic of Ghana relating to the Expanded Shallow Water Tano block offshore Ghana. An affiliate of the Company owns the remaining 50% non-controlling interest in the Erin Energy Ghana Limited subsidiary.
 
NOTE 10. — COMMITMENTS AND CONTINGENCIES

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

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

F-28

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

The Company also has commitments related to four production sharing contracts with the Government of the Republic of Kenya (the “Kenya PSCs”), two Petroleum Exploration, Development & Production Licenses with the Republic of The Gambia (the “Gambia Licenses”), and one Petroleum Agreement with the Republic of Ghana. In all cases, the Company entered into these commitments through a subsidiary. To maintain compliance and ownership, the Company is required to fulfill certain minimum work obligations and to make certain payments as stated in each of the Kenya PSCs, the Gambia Licenses, and the Ghana Petroleum Agreement. The table above sets forth the Company's future contractual obligations with regards to the minimum work obligations in each country. In December 2016, the Company recorded a charge of $0.6 million to write-off the carrying value of certain of its offshore leases in Kenya because the Company no longer intends to renew or extend its leases on these offshore blocks. In June 2017, the Company recorded a non-cash impairment charge of $0.6 million to write-off the carrying value of its onshore leases in Kenya.

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

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

Contingencies
 
Legal Contingencies and Proceedings

From time to time, the Company may be involved in various legal proceedings and claims in the ordinary course of business. As of December 31, 2017 , and through the filing date of this report, the Company does not believe the ultimate resolution of such actions or potential actions of which the Company is currently aware will have a material effect on its consolidated financial position or results of operations.

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

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ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

granting Transocean Offshore Gulf of Guinea VII Limited’s and Indigo Drilling Limited’s motion to enforce the Consent Award and for entry of final judgment.  Specifically, the Consent Award was confirmed as the judgment of the United States District Court for the Southern District of Texas.  The parties are in the process of negotiating a settlement agreement concerning the Company’s payment of the Consent Award.

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

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

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

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

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

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

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ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Unrecognized Loss Contingency

As of December 31, 2017 , the Company has not accrued penalty and interest related to certain outstanding transactional tax obligations in Nigeria, including withholding taxes, value-added taxes, Nigerian Oil and Gas Industry Content Development Act (NCD) tax, Cabotage taxes, and Niger Delta Development Corporation taxes (NDDC). As of the date of this report, the Company believes that, based on its experience with local practices in Nigeria, no notice of penalty and interest has been assessed by any Nigerian taxing authority, however the likelihood of being assessed penalty and interest is reasonably possible, with an estimated liability up to $27.4 million .

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

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

Contingency under the 2015 Convertible Note

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

NOTE 11. — STOCK BASED COMPENSATION
 
Under the Company’s amended 2009 Equity Incentive Plan (“2009 Plan”), the Company may issue restricted stock awards and stock options to result in issuance of a maximum aggregate of 16.7 million shares of common stock. Options awarded expire between  five and ten years from the date of the grant, or a shorter term as fixed by the Board of Directors.
 
Stock Options
 
The table below sets forth a summary of stock option activity for the year ended December 31, 2017 .

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ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	
							
 	Shares
Underlying
Options
(In Thousands)	 	Weighted-Average
Exercise Price	 	Weighted-Average
Remaining
Contractual Term
(Years)	
Stock Options	 	
Outstanding at December 31, 2016	1,147		 	$2.54	 	2.0	
Granted	745		 	$2.26	 	0.9	
Exercised	(511	)	 	$1.81	 	—	
Forfeited	(639	)	 	$2.69	 	—	
Expired	(145	)	 	$3.55	 	—	
Outstanding at December 31, 2017	597		 	$2.40	 	1.5	
Expected to vest	145		 	$1.88	 	4.4	
Exercisable at December 31, 2017	452		 	$2.57	 	0.6	
 
During the year ended December 31, 2017 , the Company issued 183,160 shares of common stock as a result of the exercise of stock options, all of which were issued as a result of the cashless exercise of options to purchase 510,555 shares of common stock. Also, during the year ended December 31, 2017 , options to purchase 144,842 shares of common stock expired, and options to purchase 638,891 shares were forfeited.

The total intrinsic value of options outstanding and options exercisable were $0.4 million and $0.2 million , respectively, at December 31, 2017 . The total intrinsic values realized by recipients on options exercised were $0.5 million , $0.7 million , and $0.01 million in 2017 , 2016 and 2015 , respectively.
 
The Company recorded compensation expense relative to stock options in 2017 , 2016 and 2015 of approximately $0.1 million , $0.4 million and $1.3 million , respectively. As of December 31, 2017 , there were approximately $0.1 million of total unrecognized compensation cost related to stock options, with $0.04 million , $0.04 million and $0.02 million to be recognized during the years ended December 31, 2018, 2019 and 2020, respectively.
 
The fair values of stock options used in recording compensation expense are computed using the Black-Scholes option pricing model. The table below shows the weighted-average amounts and the assumptions used in the model for options awarded in each year under equity incentive plans.

	
												
 	2017	 	2016	 	2015	
Expected price volatility	83.9% - 87.3%	 	—	%	 	77.1% - 83.1%		
Risk free interest rate (U.S. treasury bonds)	1.4% - 1.5%	 	—	%	 	1.0% - 1.2%		
Expected annual dividend yield	—	 	—		 	—		
Expected option term (years)	3.0	 	—		 	3.0		
Weighted-average grant date fair value per share	$	1.23		 	$	—		 	$	2.73		
 
Stock Warrants
 
The table below sets forth a summary of stock warrant activity for the year ended December 31, 2017 .

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ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

During the year ended December 31, 2016, and in connection with the execution of the 2015 Convertible Note, the Company issued to Allied warrants to purchase 48,291 shares of the Company’s common stock at exercise prices ranging from $2.00 to $2.13 per share. The warrants are exercisable at any time starting from the date of issuance and have a five -year term. See Note 8 – Debt - Long Term Debt - Related Party - 2015 Convertible Note .
 
During the year ended December 31, 2014 , as compensation for services received, the Company issued warrants to a service provider to purchase 0.3 million shares of common stock at an exercise price of $3.36 per share. The warrants are exercisable at any time starting from the date of issuance and have a five year term. During the years ended December 31, 2017, 2016 and 2015, the Company recognized stock-based compensation expense of nil , nil and $0.4 million , respectively, related to these warrants, based on the Black-Scholes option pricing model.

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

	
												
 	2017	 	2016	 	2015	
Expected price volatility	82.2	%	 	84.7% - 84.8%		 	76.8% - 83.2%		
Risk free interest rate (U.S. treasury bonds)	1.6	%	 	0.8	%	 	0.8% - 1.1%		
Expected annual dividend yield	—		 	—		 	—		
Expected option term (years)	2.0		 	3.0		 	3.0		
Weighted-average grant date fair value per share	$	1.23		 	$	1.12		 	$	1.86		
 
Restricted Stock Awards (“RSA”)
 
In addition to stock options, the Company’s 2009 Plan allows for the grant of restricted stock awards (“RSAs”). The Company determines the fair value of RSAs based on the market price of its common stock on the date of grant. Compensation cost for RSAs is recognized on a straight-line basis over the vesting or service period and is net of forfeitures.
 
The table below sets forth a summary of RSA activity for the year ended December 31, 2017 .

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ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	
					
 	Shares
(In Thousands)	 	Weighted-Average
Grant Date Fair
Value	
Restricted Stock	 	 	 	
Non-vested at December 31, 2016	2,072		 	$2.25	
Granted	1,122		 	$3.00	
Vested	(1,174	)	 	$2.40	
Forfeited	(861	)	 	$2.96	
Non-vested as of December 31, 2017	1,159		 	$2.30	
 
During the year ended December 31, 2017 , the Company granted its officers, directors, and employees a total of approximately 1.1 million shares of restricted common stock, including 0.2 million shares of performance-based restricted stock awards ("PBRSAs") to certain officers with vesting periods varying from immediate vesting to 36 months . During the year ended December 31, 2017 , 860,607 shares of restricted common stock were forfeited.

With regards to the PBRSA, each grant will vest if the individuals remain employed three years from the date of grant and the Company achieves specific performance objectives at the end of the designated performance period. Up to 50% additional shares may be awarded if performance objectives are exceeded. None of the PBRSAs will vest if certain minimum performance goals are not met. The performance conditions are based on the Company’s total shareholder return over the performance period compared to an industry peer group of companies. Total estimated compensation expense, net of forfeitures, is $0.09 million over three years .

The Company recorded compensation expense relative to RSAs, including PBRSAs, in 2017 , 2016 and 2015 of $1.9 million , $2.5 million and $3.3 million , respectively.
 
The total grant date fair value of RSA shares that vested during 2017 and 2016 was approximately $2.3 million and $2.1 million , respectively. As of December 31, 2017 , there were approximately $0.7 million of total unrecognized compensation cost related to non-vested RSAs, with $0.6 million and $0.1 million to be recognized during the years ended December 31, 2018 and 2019, respectively.
 
Issuance of Common Shares

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

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

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ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12. — INCOME TAXES
 
Following is a reconciliation of the expected statutory U.S. Federal income tax provision to the actual income tax expense for the respective periods:

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

Significant components of our deferred tax assets are as follows:

								
 	As of December 31,	
(In thousands)	2017	 	2016	
Basis difference in fixed assets	$	19,126		 	$	(3,249	)	
Unused capital allowances	644,099		 	572,051		
Net operating losses	96,701		 	109,230		
Other	10,295		 	12,421		
 	770,221		 	690,453		
Valuation allowance	(770,221	)	 	(690,453	)	
Net deferred income tax assets	$	—		 	$	—		
 
The majority of the Company’s basis difference in fixed assets and unused capital allowances were generated from its Nigerian operations. The Company’s foreign net operating losses in Nigeria are not subject to expiration, and can be carried forward indefinitely. The foreign operating losses in The Gambia, Kenya and Ghana are included in the respective subsidiaries cost oil accounts, which will be offset against future taxable revenues. The U.S. Federal NOL will begin to expire in 2027.  The ability to utilize NOLs and other tax attributes could be subject to a limitation if the Company were to undergo an ownership change as defined in Section 382 of the Tax Code.
 
Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. Based on current facts and circumstances related to its Nigerian operations, management has determined that it cannot demonstrate that it is more likely than not that the Nigerian losses and unutilized capital allowances will be utilized to reduce the Company’s petroleum profit tax liability within the foreseeable future.
 
Furthermore, because the Company does not currently have any revenue generating activities either in the U.S. or in any of its non-Nigerian subsidiaries, it cannot demonstrate that it is more likely than not that any of the related deferred tax assets will be utilized in the foreseeable future.
 
On the basis of this assessment, valuation allowances of $770.2 million and $690.5 million were recorded as of December 31, 2017 and 2016 , respectively.
 
At December 31, 2017 and 2016 , the Company was subject to foreign and United States federal taxes only, with no allocations made to state and local taxes.

F-35

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

	
				
United States:	2007	-	2017	
Nigeria:	2010	-	2017	
Kenya:	2012	-	2017	
The Gambia:	2012	-	2017	
 
U.S. Tax Reform

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

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

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

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

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

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ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 13. — SEGMENT INFORMATION
 
The Company’s current operations are based in Nigeria, Kenya, The Gambia, and Ghana. Management reviews and evaluates the operations of each geographic segment separately. Segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues and expenditures are recognized at the relevant geographical location. The Company evaluates each segment based on operating income (loss).
 
The table below sets forth segment activity for the years ended December 31, 2017 , 2016 , and 2015 .

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

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

F-37

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 14. — SELECTED UNAUDITED QUARTERLY FINANCIAL DATA (In thousands, except for per share amounts)

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

F-38

ERIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 15. — SUBSEQUENT EVENTS

Subsequent to December 31, 2017, the Company granted to employees approximately 0.1 million shares of restricted stock, and granted performance-based restricted stock awards (PBRSA) to certain officers totaling 0.2 million shares.

On February 22, 2018, the Company entered into a Promissory Note ("the 2018 Promissory Note'") with CAMAC International Corporation in the amount of $600,000 . Interest accrues on the outstanding principal of the 2018 Promissory Note at the rate of LIBOR plus 5% and matures on September 30, 2018.

In February of 2018, FAR, the Company's joint venture partner in the Gambia, reported that a subsidiary of Petroliam Nasional Berhad ("PETRONAS"), has signed a Farm-out Agreement ("FOA") with them. The FOA, expected to be completed March 31, 2018, assigns a 40% interest in the A2 and A5 offshore blocks in The Gambia to PETRONAS with FAR retaining operatorship and a 40% interest in each block. Erin Energy has a 20% interest in blocks A2 and A5 following its farm-out to FAR in 2017.

On February 26, 2018, the Company executed the Convertible Subordinated Note Amendment and Debt Conversion Agreement (the "Conversion Agreement") effective December 29, 2017, whereby the conversion price of the 2014 Convertible Subordinated Note was amended to $2.75 , and the holder of the 2014 Convertible Subordinated Note agreed to convert the outstanding principal and interest balance of the note Company in exchange for 22,327,327 shares of common stock. The shares are expected to be issued during the first quarter of 2018.

F-39

ERIN ENERGY CORPORATION
SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

The unaudited supplemental information on oil and gas exploration and production activities for 2017, 2016 and 2015 has been presented in accordance with FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. The totality of the Company’s proved reserves are located offshore Nigeria.
 
Estimated Net Proved Crude Oil Reserves
 
The following estimates of the net proved crude oil reserves in Nigeria are based on evaluations prepared by third-party reservoir engineers DeGolyer and MacNaughton (“D&M”). D&M has prepared evaluations on 100 percent of our rights to proved reserves and the estimates of proved crude oil reserves attributable to our net interests in oil and gas properties for the years ended December 31, 2017 , 2016 and 2015. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. The average first-day-of-the-month commodity prices during the 12-month periods ending on December 31, 2017 , 2016 , and 2015 , were $54.19 , $42.21, and $53.51 per barrel of crude oil, respectively, including price differentials.

Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

	
			
 	Crude Oil	
 	(MBbls)	
International	 	
December 31, 2014	9,051		
Revisions	4,497		
Production	(1,564	)	
December 31, 2015	11,984		
Revisions	(980	)	
Production	(1,754	)	
December 31, 2016	9,250		
Revisions	(418	)	
Production	(1,725	)	
December 31, 2017  (1)	7,107		
 	 	
Proved developed reserves	 	
December 31, 2015	7,594		
December 31, 2016	3,256		
December 31, 2017	—		
 	 	
Proved undeveloped reserves	 	
December 31, 2015	4,390		
December 31, 2016	5,994		
December 31, 2017	7,107		
  (1) Total proved volume of 7,107 MBbls as of December 31, 2017 include proved developed volumes of 3,210 MBbls from Oyo-7 and Oyo-8 producer wells .

The 418 MBbls downward revision during the year ended December 31, 2017 was due to the higher operating costs applied compared to 2016. The 980 MBbls downward revision in our proved reserves for the year ended December 31, 2016 was due to field depletion during 2016 and the poorer performance of well Oyo-7 than initially predicted. The 4,497 MBbl upward revision in our proved reserves during 2015 was primarily due to the excellent performance of one of our producing wells and better projected performance for one of our planned wells.

S-1

ERIN ENERGY CORPORATION
SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

Capitalized Costs
 
The Company follows the successful efforts method of accounting for capitalization of costs of oil and gas producing activities. Capitalized costs include the cost of properties, equipment and facilities for oil and gas producing activities. Capitalized costs for proved properties include costs for oil and gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion and costs of exploratory wells suspended or waiting on completion. Amounts below include only activities classified as exploration and producing.

								
 	As of December 31,	
(In thousands)	2017	 	2016	
International	 	 	 	
Proved properties	$	749,012		 	$	671,913		
Unproved properties	28,373		 	42,850		
Materials and equipment	36,665		 	34,704		
Total capitalized costs	814,050		 	749,467		
Accumulated depreciation, depletion and amortization	(614,648	)	 	(483,754	)	
Net capitalized costs	$	199,402		 	$	265,713		
 
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
 
Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and gas property acquisition, exploration, and development activities. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities. Costs associated with corporate activities are not included.

												
 	Years Ended December 31,	
(In thousands)	2017	 	2016	 	2015	
International	 	 	 	 	 	
Property acquisitions	 	 	 	 	 	
Proved	$	—		 	$	—		 	$	—		
Unproved	—		 	—		 	1,000		
Exploration (1)	26,750		 	39,269		 	16,437		
Development	56,418		 	1,669		 	135,966		
Total costs incurred	$	83,168		 	$	40,938		 	$	153,403		
		
(1)	Includes capitalized exploratory drilling costs, as well as other geological and geophysical costs. In 2016, this includes the write-off of the Company's suspended exploratory well costs related to the Miocene and Pliocene exploration drilling of $33.0 million , which was capitalized in prior years pending the completion of its evaluation as proved reserves.	

S-2

ERIN ENERGY CORPORATION
SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

Results of Continuing Operations
 
Results of continuing operations for producing activities consist of all activities within the oil and gas exploration and production operations.

												
 	Years Ended December 31,	
(In thousands)	2017	 	2016	 	2015	
International	 	 	 	 	 	
Revenues	$	101,173		 	$	77,815		 	$	68,429		
Production, Crude inventory, G&A and other costs	(83,792	)	 	(103,278	)	 	(94,299	)	
Exploratory expenses	(816	)	 	(34,371	)	 	(1,706	)	
Depreciation, depletion and amortization	(55,111	)	 	(57,620	)	 	(98,664	)	
Impairment of oil and gas properties	(78,091	)	 	(25	)	 	(261,208	)	
Results from oil and gas producing activities	$	(116,637	)	 	$	(117,479	)	 	$	(387,448	)	
 
Standardized Measure of Discounted Future Net Cash Flows
 
Standardized Measure of Discounted Future Net Cash Flows reflects the Company’s estimated future net revenues, net of estimated income taxes, to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the average of the first-day-of-the-month commodity prices during the 12-month period ended) without giving effect to non-property related expenses such as DD&A expense and discounted at 10% per year. Amounts below for production sold and production costs exclude royalties. The standardized measure of discounted future net cash flow should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company’s oil and gas properties.

	
												
 	Years Ended December 31,	
(In thousands)	2017	 	2016	 	2015	
International	 	 	 	 	 	
Future cash inflows from production sold	$	385,122		 	$	390,466		 	$	641,351		
Future production costs	(238,986	)	 	(225,863	)	 	(330,583	)	
Future development costs	(86,860	)	 	(103,914	)	 	(95,081	)	
Future income taxes	(13,610	)	 	(11,076	)	 	(27,921	)	
Future net cash flows before discount	45,666		 	49,613		 	187,766		
Discount at 10% annual rate	(4,623	)	 	(6,028	)	 	(25,799	)	
Standardized measure of discounted future cash flows	$	41,043		 	$	43,585		 	$	161,967		

S-3

ERIN ENERGY CORPORATION
SUPPLEMENTAL DATA ON OIL AND GAS EXPLORATION AND PRODUCING ACTIVITIES (UNAUDITED)

Change in Standardized Measure of Discounted Future Net Cash Flows

	
												
 	Years Ended December 31,	
(In thousands)	2017	 	2016	 	2015	
International	 	 	 	 	 	
Balance at Beginning of Year	$	43,585		 	$	161,967		 	$	237,049		
Sales of oil and gas, net of production costs	(19,474	)	 	26,932		 	28,372		
Net changes in prices and production costs	17,294		 	(111,408	)	 	(328,943	)	
Net change due to revision of quantity estimates	(7,724	)	 	(12,556	)	 	100,547		
Net change due to purchases of minerals in place	—		 	—		 	—		
Changes in estimated future development costs	14,982		 	(7,760	)	 	103,652		
Accretion of discount	3,829		 	16,197		 	21,432		
Net change in income taxes	(2,278	)	 	14,798		 	8,590		
Change in production costs, timing, and other	(9,171	)	 	(44,585	)	 	(8,732	)	
Balance at End of Year	$	41,043		 	$	43,585		 	$	161,967		

S-4

Exhibit 21.1

SUBSIDIARIES OF THE COMPANY

Erin Petroleum Nigeria Limited

Erin Energy Ltd.

Erin Energy Kenya Limited

Erin Energy Gambia A5 Ltd.

Erin Energy Gambia Ltd.

Erin Energy International Ltd.

Erin Energy Ghana Limited

Erin Energy Finance Ltd.

CAMAC Energy Sierra Leone

Erin Energy Chad Ltd.

Erin Energy Services Limited

1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To: Erin Energy Corporation

We consent to the incorporation in the Registration Statements on Forms S-8 (Registration Nos. 333-175294, 333-160737, 333-194503 and 333-152061) and on Forms S-3 (Registration Nos. 333-163869, 333-167013, 333-201177 and 333-205911) of our reports dated March 16, 2018, with respect to the consolidated financial statement of Erin Energy Corporation as of and for the year ended December 31, 2017 and the effectiveness of internal control over financial reporting as of December 31, 2017 which reports appear in the Annual Report of Erin Energy Corporation on Form 10-K for the year ended December 31, 2017.

/s/ PANNELL KERR FORSTER OF TEXAS, P.C.
Houston, Texas
March 16, 2018

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated March 23, 2016 (except for the effects of the adjustments described in Note 16 - Correction of Immaterial Error in Previously Issued Consolidated Financial Statements included in the Form 10-K previously filed on March 16, 2017, as to which the date is March 16, 2017), with respect to the consolidated financial statements included in the Annual Report of Erin Energy Corporation on Form 10-K for the year ended December 31, 2017. We consent to the incorporation by reference of said reports in the Registration Statements of Erin Energy Corporation on Forms S-8 (File No. 333-175294, 333-160737, 333-194503 and 333-152061) and on Forms S-3 (File No. 333-163869, 333-167013, 333-201177 and 333-205911).

/s/ GRANT THORNTON LLP
Houston, Texas
March 16, 2018

Exhibit 23.3

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
March 15, 2018
Erin Energy Corporation
1330 Post Oak Boulevard
Suite 2550
Houston, Texas 77056
Ladies and Gentlemen:

We hereby consent to the incorporation into the United States Securities and Exchange Commission Registration Statements on Form 10-K of Erin Energy Corporation of (a) the references to DeGolyer and MacNaughton contained in “Part I, Item 2,” “List of Exhibits,” and in the section “Supplemental Data on Oil and Gas Exploration and Producing Activities (Unaudited)” and (b) our third-party letter report dated March 12, 2018, containing our opinion on the proved reserves as of December 31, 2017, attributable to the interest owned by Erin Energy Corporation in the Oyo field offshore Nigeria, which report is included as “Exhibit 99.1” to be filed on or about March 15, 2018.

Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716

Exhibit 31.1
CERTIFICATION PURSUANT TO
15 U.S.C. § 7241
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Sakiru Adefemi (Femi) Ayoade, certify that:
		
1.	I have reviewed this Annual Report on Form 10-K of Erin Energy Corporation;	
		
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
		
3.	Based on my knowledge, the financial statements and other financial information included in this report, fairly present, in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
		
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
		
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
		
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles;	
		
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
		
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
		
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors:	
		
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and	
		
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

	
			
Date: March 16, 2018	 	/s/ Sakiru Adefemi (Femi) Ayoade	
 	 	Sakiru Adefemi (Femi) Ayoade	
 	 	Chief Executive Officer
(Principal Executive Officer)	

Exhibit 31.2
CERTIFICATION PURSUANT TO
15 U.S.C. § 7241
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Dippo Bello, certify that:
		
1.	I have reviewed this Annual Report on Form 10-K of Erin Energy Corporation;	
		
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
		
3.	Based on my knowledge, the financial statements and other financial information included in this report, fairly present, in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
		
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
		
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
		
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles;	
		
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
		
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
		
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors:	
		
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and	
		
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

	
			
Date: March 16, 2018	 	/s/ Dippo Bello	
 	 	Dippo Bello
Vice President, Financial Planning and Treasurer
(Interim Principal Financial Officer)	

Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. § 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
The undersigned hereby certifies, in his capacity as the Principal Executive Officer of Erin Energy Corporation (the “Company”), that the Annual Report of the Company on Form 10-K for the year ended December 31, 2017 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained in such report fairly presents, in all material respects, the financial condition and the results of operations of the Company.

	
			
Date: March 16, 2018	 	/s/ Sakiru Adefemi (Femi) Ayoade	
 	 	Sakiru Adefemi (Femi) Ayoade
Chief Executive Officer
(Principal Executive Officer)	

Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. § 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
The undersigned hereby certifies, in his capacity as the Principal Financial Officer of Erin Energy Corporation (the “Company”), that the Annual Report of the Company on Form 10-K for the year ended December 31, 2017 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained in such report fairly presents, in all material respects, the financial condition and the results of operations of the Company. 

	
			
Date: March 16, 2018	 	/s/ Dippo Bello	
 	 	Dippo Bello
Vice President, Financial Planning and Treasurer
(Interim Principal Financial Officer)	

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

March 12, 2018
Erin Energy Corporation
1330 Post Oak Boulevard
Suite 2250
Houston, Texas 77056
Ladies and Gentlemen:
Pursuant to your request, we have conducted an independent reserves evaluation of the extent and value of the proved oil reserves, as of December 31, 2017, of a 100-percent working interest which Erin Energy Corporation (Erin Energy) has represented that it owns in the Oyo field in Oil Mining Lease (OML) 120, offshore Nigeria. This evaluation was completed on March 12, 2018. Erin Energy has represented that this property accounts for 100 percent, on a net equivalent barrel basis, of Erin Energy’s net proved reserves as of December 31, 2017. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Erin Energy.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from this property after December 31, 2017. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Erin Energy after deducting a royalty of 12 percent.

This report presents values for proved reserves that have been estimated using prices and costs as of December 2017. Initial prices and costs were not escalated in this evaluation to account for inflation. Prices and costs provided by Erin Energy were expressed in United States dollars (U.S.$), and all monetary values in this report are expressed in U.S.$.

DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244

Values shown herein are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated operating expenses, capital costs, abandonment costs, and Nigerian taxes from the future gross revenue. Operating expenses include field operating expenses, estimated expenses of direct supervision, and an allocation of overhead that directly relates to production activities. Abandonment costs are represented by Erin Energy to be inclusive of those costs associated with the removal of equipment, plugging of the wells, and reclamation and restoration associated with the abandonment. Future United States income taxes have not been taken into account in the preparation of this report. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold. In this report, present worth values, using a discount rate of 10 percent, are reported as totals.

Estimates of oil reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this evaluation were obtained from reviews with Erin Energy personnel, from Erin Energy files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Erin Energy with respect to property interests, production from such property, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the property was not considered necessary for the purposes of this report.

3

DeGolyer and MacNaughton

.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Erin Energy, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, drill-stem test results, bottomhole pressures, and other available data were used to prepare these maps. Certain of these data were also used to estimate representative values for porosity and water saturation.

Where appropriate, estimates of ultimate recovery were obtained after applying recovery factors to OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, engineering methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. A history-matched dynamic model was available and applicable, and model results were used to estimate recovery factors and construct reserves production forecasts.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships.

4

DeGolyer and MacNaughton

In the analyses of production profiles, reserves were estimated only to the limits of economic production that were prior to the expiration of the production license.
Oil quantities estimated herein are those resulting from normal field separation, expressed in terms of 42 United States gallons per barrel and reported in thousands of barrels (10 3 bbl).
Definition of Reserves
Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

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(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.
Primary Economic Assumptions
Revenue values in this report were estimated using initial prices and costs specified by Erin Energy. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The assumptions used for estimating future prices and expenses are as follows:

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Oil Price
Erin Energy has represented that the oil price was based on a Brent oil reference price. The reference price was calculated as the unweighted arithmetic average of the first day-of-the-month price for each month within the 12‑month period prior to the end of the reporting period. The 12-month average reference price is U.S.$54.36 per barrel. Erin Energy supplied differentials to the Brent reference price and has represented that the 12-month average oil price for the Oyo field was U.S.$54.19 per barrel. This price was held constant for the life of the field.
Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of future operating expenses were based on current expenses and have not been escalated for inflation. Future capital expenditures were estimated using current capital costs and were not escalated for inflation. Abandonment costs were included and have not been escalated for inflation. Abandonment costs are represented by Erin Energy to be inclusive of those costs associated with the removal of equipment, plugging of the wells, and reclamation and restoration associated with the abandonment.

Nigerian Taxes
Gross revenue is subject to certain Nigerian taxes. These
Nigerian taxes include the education tax, investment tax allowance, and petroleum profits tax, as applicable for
OML 120.

Royalty
Royalties are paid in kind to the Nigerian Government from future gross production and are calculated, based on the OML 120 water depth, at a rate of 12 percent. Net reserves in this report are after royalty.

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Summary of Oil Reserves and Revenue
The estimates of the net oil proved reserves, as of December 31, 2017, attributable to the interests owned by Erin Energy in the Oyo field, offshore Nigeria, are summarized as follows, expressed in thousands of barrels (10 3 bbl):

	
			
 	 	Estimated by DeGolyer
and MacNaughton
Net Proved Reserves
as of
December 31, 2017
Oil
(10 3 bbl)	
 	 	 	
Proved	 	 	
Developed	 	0	
Undeveloped	 	7,107	
 	 	 	
Total Proved	 	7,107	

The estimated future revenue to be derived from the production and sale of the net proved oil reserves, as of December 31, 2017, of the properties evaluated, expressed in thousands of United States dollars (10 3 U.S.$), is summarized as follows:

	
								
 	 	Proved	
 	 	Developed
(10 3 U.S.$)	 	Undeveloped
(10 3 U.S.$)	 	Total
(10 3 U.S.$)	
 	 	 	 	 	 	 	
Future Net Revenue	 	0		 	45,666	 	45,666	
Present Worth at 10 Percent	 	0		 	41,043	 	41,043	
 	 	 	 	 	 	 	
Notes:	
1. Future United States income taxes have not been taken into account in the preparation of these estimates.	
2. Future net revenue for the proved developed reserves is negative due to abandonment costs.	

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2017, estimated proved reserves.

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In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932‑235-50-6, 932-235-50-7, 932‑235‑50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, that (i) future United States income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

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To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Erin Energy. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Erin Energy. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.
Submitted,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716

/s/ Lloyd W. Cade, P.E. Senior

Lloyd W. Cade, P.E. Senior
[SEAL]                Senior Vice President
DeGolyer and MacNaughton

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION
I, Lloyd W. Cade, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.	That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Erin Energy dated March 12, 2018, and that I, as Senior Vice President, was responsible for the preparation of this letter report.	

2.	That I attended Kansas State University, and that I graduated with a Bachelor of Science degree in Mechanical Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have more than 35 years of experience in oil and gas reservoir studies and reserves evaluations.	

SIGNED: March 12, 2018