Exhibit

Pursuant to your request, we have conducted an independent evaluation to serve as a reserves audit of the extent and value of the proved oil reserves, as of December 31, 2016, 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 February 28, 2017. 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, 2016. 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 included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2016. 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 2016. 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.$), and all monetary values in this report are expressed in U.S.$.

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 appraised 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 (where applicable), and 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. 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, 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 properties, 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 properties was not considered necessary for the purposes of this report.

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 constructed 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 estimated 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.

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.

(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.

(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.

(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.

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.

Revenue values in this report were estimated using initial prices and costs specified by Erin Energy. Futures prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The assumptions used for estimating futures prices and expenses are as follows:

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.$42.71 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.$42.21 per barrel. This price was held constant for the life of the field.

Estimates of future operating expenses were based on current expenses. In certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changed operating conditions, but no general escalation that might result from inflation was applied. Future capital expenditures were estimated using current capital costs and were not escalated for inflation. Abandonment costs are included and have not been escalated for inflation.

The estimates of the net oil proved reserves, as of December 31, 2016, attributable to the interests owned by Erin Energy in the Oyo field, offshore Nigeria, are summarized as follows, expressed in thousands of barrels (10³bbl):

The estimated future revenue to be derived from the production and sale of the net proved oil reserves, as of December 31, 2016, of the properties appraised, expressed in thousands of United States dollars (10³U.S.$), is summarized as follows:



	Proved
	Developed (10³U.S.$)		Undeveloped (10³U.S.$)	Total (10³U.S.$)

Future Net Revenue	(2,685	)	52,298	49,613
Present Worth at 10 Percent	1,343		42,242	43,585

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 oil reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2016, estimated proved oil reserves.

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.

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.



		Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2016 Oil (10³bbl)

Proved
Developed		3,256
Undeveloped		5,994

Total Proved		9,250


1.	That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Erin Energy dated February 28, 2017, and that I, as Senior Vice President, was responsible for the preparation of this report.


2.	That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1983; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 33 years of experience in oil and gas reservoir studies and evaluations.