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Reserves / Resources

Updates to estimated reserves and contingent resources for the Atrush block as of December 31, 2016. The reserves and contingent resources estimates were provided by McDaniel & Associates Consultants Ltd. (“McDaniel”), the Company’s independent qualified resources evaluator, and were prepared in accordance with standards set out in the Canadian National Instrument NI 51-101 and Canadian Oil and Gas Evaluation Handbook (COGEH).

Limited new subsurface information was obtained during 2016, which resulted in no changes in Gross Working Interest Reserves and Contingent Resource estimates. Reserves Net Present Values and Net Reserves were updated to reflect timing of first production, projected costs, the fourth amendment to the Atrush production sharing contract, the Atrush Facilitation Agreement and oil price assumptions.

The Company’s crude oil reserves as of December 31, 2016 and the respective net present values of the reserves based on forecast prices and costs were estimated to be as follows:


 Proved DevelopedProved UndevelopedTotal ProvedProbableTotal Proved & ProbablePossibleTotal Proved, Probable & Possible
Light/Medium Oil (Mbbl)(1)
Gross(2) -   4,653 4,653 7,779 12,432 10,366 22,798
Net(3) -   3,096 3,096 4,302 7,399 3,339 10,737
Heavy Oil (Mbbl)(1)
Gross(2) -   2,287 2,287 2,394 4,681 3,108 7,789
Net(3) -   1,522 1,522 1,264 2,786 882 3,668
  1. The Atrush Field contains crude oil of variable density even within a single reservoir unit and as such the actual split between Light/Medium Oil and Heavy Oil is uncertain.
  2. Company gross reserves are based on the Company’s 20.1 percent working interest share of the property gross reserves.
  3. Company net reserves are based on Company share of total Cost and Profit Revenues.  Note, as the government pays income taxes on behalf of the Company out of the government’s profit oil share, the net reserves were based on the effective pre-tax profit revenues by adjusting for the tax rate.


McDaniel has prepared for ShaMaran an assessment of the crude oil and natural gas contingent resources as of December 31, 2016.

The resource estimates have been prepared in accordance with standards set out in the Canadian National Instrument NI 51-101 and the COGE Handbook.

The Atrush Block crude oil and natural gas contingent resources as of December 31, 2016 were estimated to be as follows:

 Light & Medium Oil 
Heavy Oil 
Natural Gas 
ContingentGrossCompany InterestGrossCompany InterestGrossCompany Interest
Low Estimate (1C)79,85216,050N/A100,77520,256N/A24,9235,010N/A
Best Estimate (2C)89,45417,980N/A207,24641,656N/A43,8318,810N/A
High Estimate (3C)98,98219,895N/A331,42166,616N/A68,43613,756N/A
Risked Best Estimate71,56414,384N/A165,79733,325N/A2,192440N/A


  1. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.   
  2. The risked contingent resources take into account the chance of development which is defined as the probability of a project being commercially viable.  Quantifying the chance of development requires consideration of both economic contingencies and other contingencies, such as legal, regulatory, market access, political, social license, internal and external approvals and commitment to project finance and development timing.  As many of these factors are extremely difficult to quantify, the chance of development is uncertain and must be used with caution.  The chance of development was estimated to be 80 percent for both Crude Oil types and 5 percent for the Natural Gas.
  3. The Atrush Field contains crude oil of variable density even within a single reservoir unit and as such the actual split between Light/Medium Oil and Heavy Oil is uncertain.
  4. Company gross interest resources are based on a 20.1 percent working interest share of the property gross resources.
  5. Company net interest resources are not available as McDaniel did not undertake a valuation of the resources.

The resources included in the table above are classified as contingent with development unclarified as the associated project(s) are dependent upon the results of the Atrush Phase 1 development; this first phase of development should, together with further appraisal drilling, narrow the uncertainty in the contingent resources estimates and help determine if their development is economic.

The reservoir in the Atrush field consists of fractured carbonates, which require production data for an optimized development plan. As such it was decided to develop the asset under a phased approach whereby information is collected during the first phase of development. This will aid in determining the best approach to the development of the larger volume of discovered resources (contingent resources). As some of the parameters of development are not clear yet, these contingent resources have been classified as “development unclarified”. A larger development could have been implemented from early on, but without the proper assessment of production performance and narrowing of the uncertainty, the results would not have been optimized. As such it is our view that there is a high likelihood of future development phases proceeding to development and commercialization. Given the nature of the reservoir (containing both types of oil in developed reservoirs) the same chance of development has been applied.

The uncertainty in the estimates is largely related to the drive mechanism and contribution of the oil stored in the matrix of the reservoir rocks and long-term oil production from the Jurassic reservoirs in 2017 will aid in narrowing the uncertainty significantly. The information collected from those activities will assist to decide on a concept for the next phase of development (“Phase 2”). Commercial decisions to select the best concept and implement Phase 2 will most likely be taken during 2018. Variation between the possible technical concepts is too large to provide a meaningful timeline for implementation of Phase 2 before that concept is selected. Management estimates the cost of developing all of the full field contingent resources (unrisked best estimate of 304 MMbbls) at $1.8 billion resulting in an cost factor of approximately 6 USD per barrel of oil.

The Atrush Block prospective resources estimates have not been re-evaluated since December 31, 2013.

The Atrush Block is operated by the Abu Dhabi National Energy Company PJSC (“TAQA”) and is held 39.9% by TAQA, ShaMaran Petroleum Corp, through its wholly owned subsidiary General Exploration Partners, Inc. 20.1% and Marathon Oil KDV B.V., (a wholly owned subsidiary of Marathon Oil Corporation (NYSE: MRO) 15%. Atrush reserves and resource estimates presented represent solely the view of ShaMaran and its experts.

Reserves and resources: ShaMaran Petroleum Corp.’s reserve and contingent resource estimates are as at December 31, 2016, and have been prepared and audited in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). Unless otherwise stated, all reserves estimates contained herein are the aggregate of “proved reserves” and “probable reserves”, together also known as “2P reserves”. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Contingent resources: Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. There is no certainty that it will be commercially viable for the Company to produce any portion of the contingent resources.

BOEs: BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf per 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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