Africa Oil Corp.

An independent assessment of the Company's Contingent Resources in the South Lokichar Basin located in Blocks 10BB and 13T in Kenya was completed by DeGolyer and MacNaughton Canada Limited ("DMCL"), with effective date December 31, 2015.

The estimated gross 2C unrisked resources in the South Lokichar Basin, Kenya have increased by 150 million barrels (or 24%) to 766 million barrels of oil (Development Pending: 754 million barrels and Development Unclarified: 12 million barrels).

Note:
¹ This summation of resources has been prepared for convenience by the Company and not by DMCL.

Contingent resources South Lokichar Basin: blocks 10BB and 13T (Dec 31, 2015)
For the independent assessment of contingent resources for Blocks 10BB and 13T (effective date December 31, 2015), see May 10, 2016 news release: Africa Oil Announces Significant Increase 2C Oil Resources

Notes:

1. Net Contingent Resources in this table are AOC’s Working Interest fraction of the Gross Field Contingent Resources as of December 31, 2015; they do not represent AOC’s Working Interest following the completion of the farmout to Maersk which was completed in February 2016 or actual Net Entitlement under the terms of the PSC that governs the asset, which would be lower.
2. “Gross Contingent Resources” are 100% of the volumes estimated to be recoverable from the field in the event that it is developed.
3. There is uncertainty that the above stated contingent resources will be commercially viable to produce any portion of the resources.

The effective date of this resource evaluation is December 31, 2015. Subsequent to this date, AOC completed a farmout transaction with Maersk Olie og Gas A/S (“Maersk”), whereby Maersk acquired 50% of Africa Oil’s interest in Blocks 10BB and 13T, amongst others. Accordingly, the net contingent resources described below do not represent AOC’s current working interest of 25% in these blocks nor its actual Net Entitlement volumes under the terms of the Production Sharing Contracts (“PSCs”) that governs the asset, which would be lower.

The independent assessment of the Company’s Contingent Resources in the South Lokichar Basin located in Blocks 10BB and 13T in Kenya has been completed by DMCL in accordance with the standards established by the Canadian Securities Administrators in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities with an effective date of December 31, 2015.

New disclosure rules, implemented to NI51-101 to improve quality of disclosure of resources other than reserves, require that an assessment of project maturity and chance of development be included to determine associated risked estimates of Contingent Resources:

Notes:

1. In the case of contingent resources, the chance of commerciality is calculated on the chance of development based on all contingencies required for the re-classification of the contingent resources as reserves being resolved. Assigning a factor of 100% or less to each of the major contingencies provides for a chance of development measurement. In the case of the combined development of Ngamia, Amosing, Ekales, Etom, Twiga and Agete the chance of commerciality is currently assessed at 86%.

Notes:

1. An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.
2. The basis of the calculation is the net present value of future net revenue calculated under the terms of the Block 10BB and Block 13T PSCs using DMCL’s forecast prices with effective date December 31, 2015 less a constant $3/bbl discount to Brent blend.
3. The 2C development pending case is realized with $4433mm drilling and $2489mm facilities capital expenditure and an average facilities operating cost of $160mm per year. First oil is delivered in 2021. Provision is made for abandonment expenditure of $733mm. (all 2016$).
4. Economic evaluation excludes Etuko and Ewoi fields (development unclarified).

Notes:

1. Summary table excludes Etuko and Ewoi fields (development unclarified)