Africa Oil Corp. ("Africa Oil", "AOC" or the "Company") (TSX:AOI)(OMX:AOI) is pleased to announce that an 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 DeGolyer and MacNaughton Canada Limited ("DMCL").
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).
Keith Hill, President and CEO, commented, "DMCL's independent assessment confirms a significant increase in Contingent Resources for the South Lokichar Basin in Northern Kenya. Based on the continuing drilling and testing program over the past year our best estimate is now that the Company's discoveries in the South Lokichar Basin contain gross unrisked Contingent Resources of 766 million barrels of oil (2C estimate) (Development Pending: 754 million barrels and Development Unclarified: 12 million barrels), an increase of 24% on previous estimates, and may contain as much as 1.63 billion barrels of gross oil Contingent Resources (3C estimate), an increase of 26%. The level of these resources gives us confidence that we will exceed the threshold required for development and we continue to push forward for development sanction during 2017."
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.
Project Description
AOC and its JV partners have completed a substantial exploration and appraisal program across eight discoveries within the South Lokichar Basin, northwest Kenya. The high quality sweet, waxy crude is reservoired in the fluvial and lacustrine sands of the Auwerwer and Lokone reservoirs. The South Lokichar Basin fields have been subject to an extensive data acquisition and analysis program including a large number of production and inter-well interference tests to demonstrate productivity and reservoir connectivity.
Pre-FEED engineering studies have been completed on the production facilities and crude oil pipeline export route. The main fields of the South Lokichar Basin will be developed using wells drilled from multi-well pads and using a secondary recovery waterflood scheme. Given the waxy nature of the reservoir fluids, heated water injection will be required in addition to artificial lift on the production wells to maximize oil recovery efficiency. A heated, insulated export pipeline will be required to transport crude oil to the loading facilities at the port of Lamu.
A draft field development plan was submitted to the Kenyan regulatory authorities in December 2015. An update to the field development plan is expected in 2016 with a target for government development approval and Final Investment Decision ("FID") in 2017.
Contingencies
The key contingencies associated with the development of the South Lokichar Basin by Africa Oil Corp. and its joint venture partners are as follows:
Regulatory Contingencies
All of the Kenyan discoveries are located within Exploration Contracts; the Government of Kenya has extended these Exploration Contracts, per the terms of the Block 10BB and Block 13T Production Sharing Agreements, to allow further exploration and appraisal. Conversion of these permits to production permits has yet to be agreed.
Regulatory support and approval will be required for the commercialisation of the Company's Kenyan Contingent Resources to proceed. In accordance with the Company's Production Sharing Contracts and joint venture agreements, field development plans must be agreed by the Company and its joint venture partners before submission for approval by the government. Oil production from the South Lokichar Basin development will be the first commercial production in Kenya. A draft Field Development Plan has been submitted to the regulatory authorities in Kenya in December 2015, primarily to facilitate discussion between the Block 10BB/13T joint venture partners and the government as the development moves towards sanction. An update to this draft Field Development Plan is expected to be submitted during 2016 prior to government approval for the development.
The probability of removing Regulatory Contingencies has been assessed as 95%.
Market Access Contingencies
Kenya has limited oil infrastructure and no export facilities currently in place. The discoveries in Blocks 10BB and 13T are remote and cannot be delivered to market without significant infrastructure investment. The Lokichar Basin is in a remote part of Kenya, approximately 850 km from the most likely point of export at Lamu. New build pipeline infrastructure and road upgrades will be required to permit field development and production export for these resources. Although technical work has been completed by and on behalf of the Block 10BB/13T joint venture partners on crude oil export route options, there are presently no commercial agreements in place facilitate the pipelines construction or operation.
Pipeline tariffs have been estimated for the purposes of the economic evaluation based on pre-FEED cost estimates and forecasted production volumes for a regional export pipeline system. Pipeline tariffs may vary depending on achieving a regional or Kenya standalone pipeline solution.
The chance of removing Market Access Contingencies has been assessed as 90%.