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Operations

Reserves / Resources

December 31, 2018 Reserves and Contingent Resources Estimate

Reserves and contingent resources estimates were provided by McDaniel & Associates Consultants Ltd. (“McDaniel”), ShaMaran’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). This estimate does not reflect the increase in ShaMaran’s working interest in the Atrush field to 27.6%.

December 31, 2018 Reserves Estimate

McDaniel’s reserves estimate reflects the solid production results from the Atrush field which confirms the subsurface view of the reservoir. The estimates assume that six extra production wells will be drilled in 2019 and 2020 to further develop the medium gravity oil in the reserves area of the field, increasing medium oil recovery. Reserves associated with the heavy oil extended well test in the Atrush-3 well have also been included. The Atrush Gross 2P reserves estimate is 106.0 MMbbls at December 31, 2018, up from 102.7 MMbbls at the end of 2017 which, taking into account 2018 production of 8.1 MMbbls, represents a 2P reserves increase of 11% and a 2P Reserves replacement ratio of Atrush production of 140%.

Total field Best Estimate Contingent Oil Resources (“2C”)1 on a property gross basis is 268 MMbbls at end 2018, down from 296 MMbbls at the end of 2017. The decrease is due to the reclassification of contingent resources to reserves during the year, as well as the latest drilling results and resulting updated subsurface maps which show the structure to be slightly steeper than previously assumed.

The Company’s crude oil reserves and the respective net present values of the reserves based on forecast prices and costs and the Company’s working interest of 20.1 percent at December 31, 2018, were estimated to be as follows:

COMPANY ESTIMATED Reserves
as Of December 31, 2018

 Proved
Developed
Proved
Undeveloped
Total
Proved
ProbableTotal Proved &
Probable
PossibleTotal Proved,
Probable &
Possible
Light/Medium Oil (Mbbl)(1)
Gross(2)4,8393,4028,24111,60319,84410,22730,071
Net(3)2,6951,9404,6355,76110,3973,25613,653
Heavy Oil (Mbbl)(1)
Gross(2)-4844847401,2247762,000
Net(3)-272272369641267908

Notes:

  1. The Atrush Field contains crude oil of variable density. Fluid type is classified according to COGEH: Light/Medium Oil is based on density less than 920 kg/m3 and Heavy Oil is between 920 and 1000 kg/m3.
  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.

Company Estimated Share of Reserves net Present Values (1)(2)(3)(4)(5)(6)
as of December 31, 2018

 Net Present Value (US $1,000) Discounted At
 0%5%10%15%20%
Proved Developed Producing Reserves65,55160,51757,77655,29653,049
Proved Undeveloped Reserves6592657,04349,74843,68338,586
Total Proved Reserves129,476117,560107,52398,97991,635
Probable Reserves216,696173,314141,408117,35498,830
Total Proved Plus Probable Reserves346,173290,875248,931216,333190,465
Possible Reserves92,34964,64247,80736,98029,656
Total Proved, Probable Plus Possible Reserves438,521355,516296,739253,312220,120

Notes:

  1. Based on a 20.1 percent Company working interest.
  2. Based on forecast prices and costs at January 1, 2019
  3. Interest expenses and corporate overhead, etc. were not included.
  4. Possible delays in receiving revenue payments have not been incorporated.
  5. The net present values may not necessarily represent the fair market value of the reserves.
  6. The net present values in the table above are exclusive of the following recoverable assets due to ShaMaran as of December 31, 2018:
    • Atrush Development Cost Loan (due from KRG) of $7.136 million
    • Atrush Feeder Pipeline Cost Loan of $4.718 million
    • Accounts receivable on Atrush deliveries of $14.531million

The reserves and net present values were estimated using forecast prices and costs. The sales oil price was based on the McDaniel January 1, 2019 Brent price forecast. McDaniel’s estimates include a $15.43/bbl discount to Brent crude oil to account for quality differential, marketing fees and pipeline tariff for export via Ceyhan in Turkey based on the most recent sales agreement with the KRG.

The Company’s crude oil and natural gas contingent resources as of December 31, 2018 were estimated to be as follows:

COMPANY ESTIMATED Contingent Resources (1)(2)(4)(5)
as Of December 31, 2018

 Low Estimate
(1C)
Best Estimate
(2C)
High Estimate
(3C)
Risked Best Estimate
Light/Medium Oil (Mbbl)(3)    
Gross10,69110,73511,0048,588
Heavy Oil (Mbbl)(3)    
Gross21,03943,15370,90834,522
Natural Gas (MMcf)    
Gross5,0299,05813,763453

Notes:

  1. Based on a 20.1 percent Company working interest share of the property gross resources.
  2. There is no certainty that it will be commercially viable to produce any portion of the resources.
  3. The Atrush Field contains crude oil of variable density. Fluid type is classified according to COGEH: Light/Medium Oil is based on density less than 920 kg/m3 and Heavy Oil is between 920 and 1000 kg/m3.
  4. These are unrisked contingent resources that do not account for 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 the Crude Oil and 5 percent for the Natural Gas.
  5. The contingent resources are sub-classified as “development unclarified” with an “undetermined” economic status.

The contingent resources represent the likely recoverable volumes associated with further phases of development after Phase 1. These are considered to be contingent resources rather than reserves due to the uncertainty over the future development plan which will depend in part on Phase 1 production performance and the heavy oil extended well test planned for the first half of 2019.

Prospective resources have not been re-evaluated since December 31, 2013.

Notes:
ShaMaran Petroleum Corp.'s reserve and contingent resource estimates are as at December 31, 2018, 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.

1 This estimate of contingent resources that have not been adjusted for risk based on the chance of development.

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