VANCOUVER, BRITISH COLUMBIA–(Marketwired – May 10, 2016) – 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.”
| Summary of South Lokichar Basin Unrisked 2C Oil Contingent Resources as of December 31, 2015 3 | |||
| Field | Unrisked GROSS 2C Estimate Millions of barrels (“mmbo”)2 |
AOC Working Interest (%)1 |
Unrisked NET 2C Estimate (mmbo) |
| Development Pending | |||
| Ngamia | 296.7 | 50% | 148.3 |
| Amosing | 151.1 | 50% | 75.5 |
| Ekales | 104.5 | 50% | 52.3 |
| Etom | 96.9 | 50% | 48.4 |
| Twiga | 86.7 | 50% | 43.3 |
| Agete | 17.9 | 50% | 8.9 |
| TOTAL | 753.7 | 50% | 376.9 |
| Development Unclarified | |||
| Etuko | 11.6 | 50% | 5.8 |
| Ewoi | 0.6 | 50% | 0.3 |
| TOTAL | 12.2 | 50% | 6.1 |
Notes:
- 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.
- “Gross Contingent Resources” are 100% of the volumes estimated to be recoverable from the field in the event that it is developed.
- 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:
| Summary of South Lokichar Basin Risked 2C Oil Contingent Resources as of December 31, 2015 |
|||||
| Field | Unrisked GROSS 2C Estimate Millions of barrels (“mmbo”) |
AOC Working Interest (%) |
Chance of Commerciality (%)1 |
Risked NET 2C Estimate (mmbo) |
NI 51-101 Resource Category |
| Ngamia | 296.7 | 50% | 86% | 127.6 | Development Pending |
| Amosing | 151.1 | 50% | 86% | 65.0 | Development Pending |
| Ekales | 104.5 | 50% | 86% | 44.9 | Development Pending |
| Etom | 96.9 | 50% | 86% | 41.6 | Development Pending |
| Twiga | 86.7 | 50% | 86% | 37.3 | Development Pending |
| Agete | 17.9 | 50% | 86% | 7.7 | Development Pending |
| TOTAL (Development Pending) | 753.7 | 324.1 | |||
| Etuko | 11.6 | 50% | 50% | 2.9 | Development Unclarified |
| Ewoi | 0.6 | 50% | 50% | 0.1 | Development Unclarified |
| TOTAL (Development Unclarified) | 12.2 | 3.0 | |||
Notes:
- 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%.
| Summary of South Lokichar Basin NET Risked 2C Oil Contingent Resources (Development Pending) Net Present Value as of December 31, 2015 (US$MM)1,2,3,4 |
||||
| 0% | 5% | 10% | 15% | 20% |
| 8,266 | 4,026 | 2,069 | 1,083 | 551 |
Notes:
- 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.
- 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.
- 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 $733mm. (all 2016$).
- Economic evaluation excludes Etuko and Ewoi fields (development unclarified).
| Summary of South Lokichar Basin Risked and Unrisked Contingent Oil Resources as of December 31, 2015 1 | |||
| GROSS Unrisked Contingent Resources (mmbo) |
GROSS Risked Contingent Resources (mmbo) |
NET Risked Contingent Resources (mmbo) |
|
| Low (1C) Estimate | 205 | 176 | 88 |
| Best (2C) Estimate | 754 | 648 | 324 |
| High (3C) Estimate | 1,630 | 1,402 | 701 |
Notes:
- Summary table excludes Etuko and Ewoi fields (development unclarified)
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%.
About Africa Oil Corp.
Africa Oil Corp. is a Canadian oil and gas company with assets in Kenya and Ethiopia. The Company is listed on the Toronto Stock Exchange and on Nasdaq Stockholm under the symbol “AOI”.
Additional Information
The information in this release is subject to the disclosure requirements of Africa Oil Corp. under the Swedish Securities Market Act and/or the Swedish Financial Instruments Trading Act. This information was publicly communicated on May 10, 2016 at 2:00 a.m. Toronto Time.
Forward-Looking Statements
Certain statements made and information contained herein constitute “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements and information (together, “forward looking statements”) relate to future events or the Company’s future performance, business prospects or opportunities. Forward-looking statements include, but are not limited to, statements with respect to estimates of reserves and or resources, future production levels, future capital expenditures and their allocation to exploration and development activities, future drilling and other exploration and development activities, ultimate recovery of reserves or resources and dates by which certain areas will be explored, developed or reach expected operating capacity, that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.
All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar expressions) are not statements of historical fact and may be “forward-looking statements”. Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes that the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. The Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, changes in oil prices, results of exploration and development activities, uninsured risks, regulatory changes, defects in title, availability of materials and equipment, timeliness of government or other regulatory approvals, actual performance of facilities, availability of financing on reasonable terms, availability of third party service providers, equipment and processes relative to specifications and expectations and unanticipated environmental impacts on operations. Actual results may differ materially from those expressed or implied by such forward-looking statements.
ON BEHALF OF THE BOARD
“Keith C. Hill”
President and CEO
DEFINITION OF CONTINGENT RESOURCES
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no evident viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.
The Canadian Securities Administrators (CSA) has introduced a number of amendments to National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI51-101) that became effective on July 1, 2015. These amendments are intended to improve the quality of disclosure of resources other than reserves by issuers by aligning the Instrument with changes made to the Canadian Oil and Gas Evaluation Handbook (COGEH) in July 2014. Included within these amendments is the requirement to describe an estimate of ‘chance of development’ to be used to determine risked Contingent Resources.
- Low (1C) Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
- Best (2C) Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
- High (3C) Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources.
Contingent Resources classified as ‘Development Pending’ require that project activities are ongoing to justify commercial viability in the near future. The critical contingencies have been identified and are expected to be resolved within a reasonable timeframe. Both technical and non-technical contingencies must be successfully resolved in order for the project to progress to commercial development. A project described as development pending would be expected to have a high probability of becoming a commercial development (i.e. a high chance of commerciality) whereby contingent resources would be reclassified directly into the corresponding reserves confidence category.
Contingent Resources may be described as ‘Development Unclarified’ if they are still under evaluation or require significant further appraisal to clarify potential for development, and where the contingencies have yet to be fully defined.
BASIS OF OPINION
This document must be considered in its entirety. It reflects DMCL’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client and/or obtained from other sources e.g. public domain, the limited scope of engagement, and the time permitted to conduct the evaluation.
In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. DMCL has not independently verified any information provided by or at the direction of the Client and/or obtained from other sources e.g. public domain, and has accepted the accuracy and completeness of these data. DMCL has no reason to believe that any material facts have been withheld from it, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.
The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.
There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas reserve engineering and resource assessment must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves or resources prepared by other parties may differ, perhaps materially, from those contained within this report. The accuracy of any reserve estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.
This assessment has been conducted within the context of DMCL’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, DMCL is not in a position to attest to property title or rights, conditions of these rights including environmental and abandonment obligations, and any necessary licenses and consents including planning permission, financial interest relationships or encumbrances thereon for any part of the appraised properties.
In carrying out this study, DMCL is not aware that any conflict of interest has existed. As an independent consultancy, DMCL is providing impartial technical, commercial and strategic advice within the energy sector. DMCL’s remuneration was not in any way contingent on the contents of this report. In the preparation of this document, DMCL has maintained, and continues to maintain, a strict independent consultant-client relationship with the Client. Furthermore, the management and employees of DMCL have no interest in any of the assets evaluated or related with the analysis carried out as part of this report.
Staff members who prepared this report are professionally qualified with appropriate educational qualifications and levels of experience and expertise to perform the work.
Sophia Shane
Corporate Development
(604) 689-7842
africaoilcorp@namdo.com
www.africaoilcorp.com