ShaMaran Petroleum Corp.
Annual Report
For the year ended December 31, 2018
SHAMARAN PETROLEUM CORP.
MANAGEMENT DISCUSSION AND ANALYSIS
For the year ended December 31, 2018
Management’s discussion and analysis (“MD&A”) of the financial and operating results of ShaMaran Petroleum Corp.
(together with its subsidiaries, “ShaMaran” or the “Company”) is prepared with an effective date of March 7, 2019.
The MD&A should be read in conjunction with the audited consolidated financial statements for the year ended
December 31, 2018, together with the accompanying notes.
The financial statements of the Company have been prepared in accordance with International Financial Reporting
Standards (“IFRS”) as issued by the International Accounting Standards Board. Unless otherwise stated herein all
currency amounts indicated as “$” in this MD&A are expressed in thousands of United States dollars (“USD”).
OVERVIEW
ShaMaran Petroleum Corp. is a Canadian oil and gas company listed on the TSX Venture Exchange and the NASDAQ
First North Exchange (Stockholm) under the symbol "SNM". ShaMaran has a 20.1% direct interest in the Atrush Block
production sharing contract (“Atrush PSC”) located. The Atrush Block is in the Kurdistan Region of Iraq (“Kurdistan”),
approximately 85 kilometers northwest of Erbil, the capital of Kurdistan. The Atrush Block is 269 square kilometers in
area and has oil proven in Jurassic fractured carbonates in the Chiya Khere structure.
Oil production from Atrush commenced in July 2017. Installed production facilities have a capacity of 30,000 barrels
of oil per day (“bopd”). Ten wells have been drilled to date. Five wells are currently producing.
Atrush is continuously being appraised and further phases of development, including further drilling and possible
facilities expansion will be defined based on production data, appraisal information and economic circumstances.
HIGHLIGHTS AND DEVELOPMENTS
Atrush Operations
•
•
•
ShaMaran entered into agreements on December 26, 2018 to acquire jointly with TAQA Atrush B.V. (“TAQA”) the
15% interest in the Atrush Block (“the Marathon Acquisition”) held by Marathon International Oil Company
(“MIOC”). Following close of these agreements ShaMaran’s working interest in Atrush will increase from 20.1%
to 27.6%. The parties to the agreements are currently in the process of obtaining the consent of the Kurdistan
Regional Government (“KRG”).
YTD 2019 average production was 26 thousand barrels of oil per day (“Mbopd”), coming mainly from four wells:
Atrush-2, (“AT-2”) Chiya Khere-5 “CK-5”), Chiya Khere-7 (“CK-7”) and Chiya Khere-8 (“CK-8”). The Chiya Khere-10
(“CK-10”) well was offline for 18 days for an intervention to replace an electric submersible pump (“ESP”) and the
Atrush Production Facilities were shut-in for 7 days in February during maintenance of the export pipeline.
Currently Atrush is producing around 30 Mbopd.
Fourth quarter average production was 27.4 Mbopd, significantly up from the 21.7 Mbopd average third quarter
production. The increase was due to successful resolution of processing capacity restrictions caused by high salt
concentrations produced from two wells.
• Annual production for the year 2018 was 22.1 Mbopd, which was below guidance mainly due to salt-related
processing restrictions negatively impacting production during the second and third quarters. Processing capacity
constraints associated with salt production and low ambient temperatures during the winter months have been
addressed. The Atrush Production Facilities can now consistently operate at, or above, the 30.0 thousand barrels
of liquids per day (“Mblpd”) design rate during normal operations.
•
The average lifting costs in the fourth quarter was $7.84 per barrel, down from $7.92 per barrel in the third
quarter mainly due to the higher average production in the fourth quarter. Lifting costs averaged $7.41 per barrel
over the year 2018 compared to $8.52 per barrel in the year 2017. The 2018 average lifting costs were above
guidance due to lower production than planned and additional costs related to mitigating salt related problems.
1
• Revenue from oil sales in the fourth quarter was $14.5 million, up from $13.2 million reported in the third quarter
due to the higher fourth quarter production and despite lower average netback oil prices over the same period
which decreased from $59.72 per barrel to $52.58 per barrel. The Company reported $69.6 million of revenue
from oil sales for the year 2018.
•
•
Three wells were successfully completed in the year 2018. The CK-7 and CK-10 production wells started
production near the end of July 2018. The CK-9 water disposal well was completed and tested according to
schedule during November 2018 and is now online and used for disposal of Atrush produced water.
In December 2018 the Atrush 3 (“AT-3”) well was re-completed as a heavy oil production well. Following the AT-
3 re-completion the CK-11 production well was spudded at the start of January 2019 and the Chiya Khere 6 (“CK-
6”) was re-completed.
• Heavy oil extended well test (“HOEWT”) facilities have been installed and heavy oil production from AT-3 is
expected to commence in March 2019. This test aims to progress development planning for the significant
volumes of heavy oil currently classified as Atrush contingent resources.
•
The procurement process for Atrush early production facilities (“EPF”) is underway and it is expected that these
facilities, as well as ongoing debottlenecking of the existing Production Facilities, will deliver 50.0 Mblpd
processing capacity in the second half of 2019.
Financial and Corporate
•
The Company issued new $240 million senior unsecured bonds with 5-year term to July 5, 2023 and 12% semi-
annual coupon interest and bonds due to mature in November 2018 were retired. On December 31, 2018 the
Company deposited cash of $14.4 million to the bondholders’ Debt Service Retention Account and, on January 5,
2019, paid the first semi-annual interest payment of $14.4 million to ShaMaran bondholders. Refer to the
discussion under “Borrowings” section below.
• Amendments were approved to the terms of the Company’s $240 million senior bonds on February 1, 2019. On
February 8, 2019 the Company repaid $50 million of bonds plus accrued interest reducing its bonds currently
outstanding to $190 million.
• Atrush related cash inflows in the year ending December 31, 2018:
o $69 million for entitlement share of Atrush PSC profit oil and cost oil for October 2017 through September
2018 oil deliveries. A further 10.9 million has been received in the year to date 2019 relating to October and
November 2018 oil sales.
o $2.3 million of Atrush Exploration Costs receivable1 on October 2017 through September 2018 oil sales. A
further $0.5 million was received in the year to date 2019 relating to October and November 2018 oil sales.
o $15.6 million in payments of principal plus interest on the Atrush Development Cost Loan and the Atrush
Feeder Pipeline Cost loans for invoices from January to December 2018 and an additional $2.6 million has
been collected in the year to date 2019.
• An amended Atrush oil sales agreement was concluded between Atrush co-venturers and the KRG in the fourth
quarter which reduced the oil price discount from the previous $15.73 per barrel to $15.43 per barrel with effect
from October 1, 2018. The KRG purchases oil exported from the Atrush field by pipeline at the Atrush block
boundary based upon the Dated Brent oil price minus an oil price discount for quality and all local and
international transportation costs.
Reserves and Resources
•
In February 2019, the Company reported estimated reserves and contingent resources for the Atrush field as at
December 31, 2018. Total Field Proven plus Probable (“2P”) Reserves on a property gross basis for Atrush
increased from 102.7 million barrels (“MMbbl”) reported as at December 31, 2017 to 106 MMbbl which, when
2018 Atrush production of 8 MMbbl is included, represents an increase of 11 percent. Total Field Unrisked Best
Estimate Contingent Oil Resources (“2C”)2 on a property gross basis for Atrush decreased from the 2017 estimate
of 296 MMbbl to 268 MMbbl. Total discovered oil in place in the Atrush Block is a low estimate of 1.5 billion
barrels, a best estimate of 2 billion barrels and a high estimate of 2.6 billion barrels.
1 The Exploration Costs Receivable is related to the repayment of certain development costs that ShaMaran paid on behalf of the KRG which, for
purposes of repayment, are governed under the Atrush PSC and the related Facilitation Agreement and are deemed to be Exploration Costs.
2 This estimate of remaining recoverable resources (unrisked) includes contingent resources that have not been adjusted for risk based on the
chance of development. It is not an estimate of volumes that may be recovered.
2
OPERATIONS
Atrush oil production
Oil production on the Atrush Block commenced on July 3, 2017. Cumulative production exported from Atrush from
July 2017 to December 31, 2018, was 11.4 million barrels of oil.
Average daily oil production (bopd)
Oil produced and sold – gross field (Mbbls)
ShaMaran production entitlement (Mbbls)
Q4.2018
Q3.2018
Q4.2017
27,426
2,523
276
21,712
1,998
223
21,681
1,995
295
From start up, production in Atrush steadily increased to approximately 26.0 Mbopd in January 2018. In March 2018
production dropped to approximately 20.3 Mbopd due to a partial blockage by sediment in a production facility heat
exchanger. In early April 2018 production was temporarily suspended to address the partial blockage of the heat
exchanger. The sediments were successfully removed from the heat exchanger during this plant shut down.
Analysis of the removed sediments indicate high concentrations of salts lost to the formation during drilling
operations. These materials were flowed back into the production facilities with the produced dry oil where they
caused capacity restrictions. To target these materials, fresh water was introduced at the CK-5 wellhead from June
2018 onwards. The salt materials are now diluted into the fresh water, which is then separated and disposed of during
normal processing operations.
During the third quarter of 2018, daily production was constrained by exceptionally high export pipeline downtime
during the month of August (over 6 days) as well as salt fill in the production facilities stripper column. The salt fill
became apparent once additional well capacity from the CK-7 and CK-10 wells enabled Production Facility rates to
exceed 26.0 Mbopd. The stripper column was flushed during a two-day shutdown in late September which
successfully removed all salt restrictions and enabled the high stabilized rates throughout the fourth quarter.
During the fourth quarter 2018, well rates were steadily increased to test and evaluate the limits of the Production
Facility. By the end of November 2018 and through early December 2018, several days with rates over 30.0 Mbopd
were reported until the onset of failure of the CK-10 ESP, which reduced the available well capacity and therefore
negatively impacted the daily production rate. The CK-10 well was brought back on production late January 2019 after
a successful work-over.
The Company’s production entitlement share decreased after its exploration cost sharing arrangement with Taqa was
fully settled in the second quarter of 2018. This is explained further in the discussion under the “Gross Margin” section
below.
Drilling, Testing and Facilities
The CK-7 well was drilled in Q4 2017 and the reservoir section was encountered 114 meters shallower than prognosis.
In March and April 2018 three intervals were successfully tested: the Mus formation tested 20.1 API oil at a rate of
0.8 Mbopd, with a final productivity of 13 stb/d/psi3; the Alan formation tested 27.1 API oil at a rate of 0.9 Mbopd,
with a final productivity of 6 stb/d/psi; and the main Lower Sargelu formation tested 26.4 API oil at 1.0 Mbopd at a
drawdown of only 2 psi, yielding a final productivity of 446 stb/d/psi. No water was produced at the end of the test.
CK-7 is now completed over the Alan and Lower Sargelu formation with an electric submersible pump. During the
final completion test the well produced 7,040 bopd at only 14 psi drawdown.
The CK-10 well was spudded on May 15, 2018 was drilled to a total depth of 1,985 meters, which was reached on
time and within budget on June 16, 2018. The reservoir section was encountered some 60 meters shallow to
prognosis. The well flow tested approximately 4.4 Mbopd at a low drawdown, yielding a final productivity index of
313 stb/d/psi. The well is now completed over the Lower Sargalu formation.
The CK-9 water disposal well was spudded on July 20, 2018 and was drilled to a total depth of 3015 meters, which
was reached on time and within budget on October 18, 2018. Water injection started in January 2019.
A further two appraisal wells have previously been drilled and tested in the eastern part of the field and have proven
reservoir communication between the eastern and the western parts of the field. It is planned to conduct an extended
well test in one of the two eastern appraisal wells, AT-3. This will provide important production information on the
heavier part of the oil column. Together with production data from the other producing wells, this will allow for
defining the next phases of Atrush development.
3 Stock tank barrels per day per pound per square inch (“stb/d/psi”) is a standard industry measure of productivity.
3
The AT-3 well was re-completed as a heavy oil production well during December 2018. The well commenced
production in February 2019.
The CK-11 production well was spudded at the start of January 2019 and is currently drilling.
Positive production results have shown the potential to increase Atrush production levels. It is expected that by
installing an EPF and debottlenecking existing Production Facilities, the Atrush processing capacity can be increased
to 50.0 Mblpd. The procurement process for an Atrush EPF is underway and increased processing capacity is expected
to be available in the second half of 2019.
The Company’s independent reserves and resources evaluator, McDaniel & Associates Consultants Ltd (“McDaniel”)
increased the 2P oil reserves estimate to 106MMbbl at the end of the year 2018. This estimate assumes that four
extra production wells will be drilled to further develop the medium gravity oil in the reserves area of the field
increasing medium oil recovery. Reserves associated with the HOEWT planned in 2019 for the AT-3 well have also
been included. Reserves which were included in McDaniel’s previous estimate for heavy oil production from the wells
currently producing have now been transferred to contingent resources because production to date has shown no
indication of heavy oil.
The contingent oil resources represent the likely recoverable oil volumes associated with further phases of
development after Phase 1. McDaniel has estimated gross 2C best estimate contingent oil resources of 268 MMbbl.
These are contingent oil 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 HOEWT planned for the beginning of 2019.
McDaniel estimates the chance of developing the 2C contingent oil resources at 80 percent.
OUTLOOK
Operations
The Company provides the following guidance for 2019:
• Atrush field gross production is expected to range from 30 Mbopd to 35 Mbopd and will depend mainly on the
timing of the installation of additional production facilities;
• Atrush lifting costs are estimated to range from $6.30 per barrel to $7.90 per barrel. Atrush lifting costs are mainly
fixed costs and therefore we expect the dollar per barrel estimates to decrease with increasing levels of
production; and
• Atrush gross capital expenditures for 2019 is estimated at $137 million which includes:
o debottlenecking to increase existing production capacity beyond 30.0 Mbopd;
o re-completing the Chiya Khere-6 well to initially monitor the heavy oil well during the HOEWT, and then later
produce from the medium oil interval;
o completing drilling, testing and completion activities at CK-11;
o drilling, testing and completing three additional production wells;
o expansion of processed oil storage capacity to reduce impact of export pipeline shutdowns on Atrush
production rates;
o
installation of a desalter vessel at the Processing Facilities to reduce the operating costs associated with the
short-term salt mitigation measures;
o construction of the Chamanke-D drilling location to enable addition of future production wells, and
o
installing of an EPF and debottlenecking of existing Production Facilities, to extend Atrush oil processing
capacity to 50.0 Mblpd in the second half of 2019.
Following the 2019 drilling program, the extended well testing in AT-3 and increased production, the Company
expects to further assess the significant undeveloped Atrush resource base with the potential to grow to
approximately 100.0 Mblpd production. Management expects that investment decisions for further phases of
development can be made by early 2020.
4
OWNERSHIP, PRINCIPAL TERMS OF THE ATRUSH PSC
At the end of 2018 ShaMaran, through its wholly owned subsidiary, General Exploration Partners, Inc. (“GEP”), held
a 20.1% direct interest in the Atrush PSC. TAQA Atrush B.V. (“TAQA” a subsidiary of Abu Dhabi National Energy
Company PJSC, and the “Operator” of the Atrush Block) with a 39.9% direct interest, the KRG a 25% direct interest
and Marathon Oil KDV B.V. (“MOKDV”) held a 15% direct interest. TAQA, GEP, and MOKDV together are the “Non-
Government Contractors” to the Atrush PSC. The Non-Government Contractors and the KRG together are the
“Contractors” to the Atrush PSC.
The Atrush field was discovered in 2011 and a Phase 1 development plan was approved in October 2013, which
consists of installing and commissioning production facilities with 30,000 bopd capacity and the drilling and
completion of production wells which supply the Production Facility. In August 2010 the Company acquired a 33.5%
shareholding in GEP which then held an 80% working interest in the Atrush PSC, with the remaining 20% third party
interest (“TPI”) being held by the KRG. In October 2010 MOKDV was assigned the 20% TPI in the Atrush PSC. On
December 31, 2012 GEP sold a 53.2% direct interest in the Atrush Block to TAQA, who also assumed from GEP the
Operatorship of the Block and repurchased the entire 66.5% shareholding which Aspect Energy International LLC
(“Aspect”) held in GEP, leaving the Company with a 100% shareholding interest in GEP and, at that time, a 26.8%
direct interest in the Atrush PSC.
On November 7, 2016 the Assignment, Novation and Fourth Amendment Agreement to the Atrush PSC (the “4th PSC
Amendment”) and Atrush Facilitation Agreement were concluded between Non-Government Contractors and the
KRG, in which the KRG acquired a 25% interest in the Atrush PSC effective November 7, 2012, resulting in GEP reducing
its interest in the Atrush PSC to 20.1%.
Under the terms of the Atrush PSC the development period is for 20 years after the declaration of commerciality
(November 7, 2012) with an automatic right to a five-year extension and the possibility to extend for an additional
five years. All qualifying petroleum costs incurred by the Contractors shall be recovered from a portion of available
petroleum production, defined under the terms of the Atrush PSC. All modifications to the Atrush PSC are subject to
the approval of the KRG.
Fiscal terms under the Atrush PSC include a 10% royalty and a variable profit split based on a percentage share to the
KRG. GEP has the right to recover costs using up to 40% of the available oil (produced oil less royalty oil) and 55% of
the produced gas. The Contractors are entitled to cost recovery in respect of all costs and expenditures incurred for
exploration, development, production and decommissioning operations, as well as certain other allowable direct and
indirect costs.
The portion of profit oil available to the Contractors is based on a sliding scale from 32% to 16% depending on the “R-
Factor”, which is a ratio of cumulative revenues to cumulative costs. When the ratio is below one, the Contractors are
entitled to 32% of profit oil, with a reducing scale to 16% when the ratio is greater than 2.75. In respect of gas, the
sliding scale is from 40% to 22%.
SELECTED ANNUAL FINANCIAL INFORMATION
The following is a summary of selected annual financial information for the Company:
(In $000, except per share data)
Revenues
Cost of goods sold
Service fees income
General and administrative expense
Share based payments expense
Depreciation and amortisation expense
Finance income
Finance cost
Income tax expense
Income / (loss) for the year
For the year ended December 31,
2018
2017
2016
69,600
(42,072)
-
(4,564)
-
(8)
2,091
(23,114)
(64)
1,869
17,689
(14,009)
-
(4,511)
(11)
(26)
1,649
(12,195)
(85)
(11,499)
-
-
120
(3,811)
(249)
(45)
484
(5,586)
(69)
(9,156)
Basic and diluted loss in $ per share:
-
(0.01)
(0.01)
5
Financial position – net book value of principal items
Property Plant & Equipment
Exploration and evaluation assets
Loans and receivables
Cash and other assets
Total assets
Borrowings
Other liabilities
Shareholders’ equity
2018
195,908
67,829
61,283
94,756
419,776
(236,717)
(28,860)
154,199
As at December 31,
2017
184,921
89,119
76,973
5,468
356,481
(185,692)
(18,834)
151,955
2016
174,658
89,007
53,366
4,640
321,671
(165,129)
(19,476)
137,066
Common shares outstanding (x 1,000)
2,158,632
2,158,632
1,798,632
Summary of Principal Changes in Annual Financial Information
The Company has reported in 2018 a net income of $1.9 million which was primarily driven by the gross margin on
Atrush oil sales, interest income on Atrush cost loans and interest on cash held in short term deposits offset by finance
cost, the substantial portion of which was expensed borrowing costs on the Company’s bonds, and routine general
and administrative expenses.
The Company’s operations are comprised of the Phase 1 development program on the Atrush Block petroleum
property which commenced production on July 3, 2017. The principal changes in annual financial information are
further explained in the sections below.
Gross margin on oil sales
In $000
---------Three month period---------
Q4.2017
Q4.2018 Q3.2018
-----Twelve month period----
Q4.2017
Q4.2018
Revenues from Atrush oil sales
14,531
13,240
13,907
69,600
17,689
Lifting costs
Other costs of production
Depletion costs
Cost of goods sold
(3,978)
(1,732)
(10,259)
(15,969)
(3,180)
(39)
(3,726)
(6,945)
(3,245)
(834)
(5,347)
(9,426)
(12,047)
(1,854)
(28,171)
(42,072)
(5,547)
(834)
(7,628)
(14,009)
Gross margin on oil sales
3,680
Revenues relate to the Company’s entitlement share of oil sales from Atrush. Revenue for sales of oil is recognised
when the significant risks and rewards of ownership are deemed to have been transferred to the KRG, the amount
can be measured reliably and it is assessed as probable that economic benefit associated with the sale will flow to the
Company. This occurs when oil reaches the delivery point at the Atrush Block boundary in route to the KRG’s main
export pipeline.
(1,438)
27,528
6,295
4,481
Revenue is recognised at fair value which is comprised of the Company’s entitlement production due under the terms
of the Atrush Joint Operating Agreement (“Atrush JOA”) and the Atrush PSC which have two principal components:
cost oil, which is the mechanism by which the Company recovers qualifying costs it has incurred on an asset, and
profit oil, which is the mechanism through which profits are shared between the Company, the Atrush co-venturers
and the KRG. The Company pays capacity building payments on profit oil, which are due for payment once the
Company has received the related profit oil proceeds. Profit oil revenue is reported net of any related capacity building
payments.
The Company’s oil sales are made to the KRG under the terms of a sales agreement which allows for Atrush oil volumes
to be sold to the KRG at the Atrush block boundary at a discount to the Dated Brent oil price for estimated oil quality
adjustments and all local and international transportation costs.
Income tax arising from the Company’s activities under production sharing contracts is settled by the KRG at no cost
and on behalf of the Company. However, the Company is not able to measure the tax that has been paid on its behalf
and consequently revenue is not reported gross of income tax paid.
6
Production from the Atrush field was delivered to the KRG’s Feeder Pipeline at the Atrush block boundary for onward
export through Ceyhan, Turkey. In the three and twelve months ended December 31, 2018, the respective gross
exported oil volumes from Atrush were 2.5 MMbbls and 8.1 MMbbls and the Company’s entitlement shares were
approximately 276 Mbbls and 1.3 MMbbls. ShaMaran’s oil entitlement share is based on PSC terms covering
allocation of profit oil and cost oil, capacity building bonuses owed to the KRG, a priority arrangement with TAQA for
sharing initial exploration cost oil 4 and on export prices. Export prices are based on Dated Brent oil price with an
agreed discount for estimated oil quality adjustments and all local and international transportation costs, of $15.43
per barrel for the three months ended December 31, 2018.
Average Atrush fourth quarter production was 27.4 Mbopd, up from 21.7 Mbopd in the third quarter, and was 22.1
Mbopd for the year 2018. The increased fourth quarter production was due to continued improvements in processing
capacity restrictions caused by unexpectedly high concentrations of salt flowed back by two wells which started to
occur in March 2018. The restrictions were relieved through flushing of plugged process vessels as well as introduction
of fresh water at one well location. Revenue from oil sales in the fourth quarter also moved up to $14.5 million
compared to $13.2 million reported in the third quarter in line with the higher average fourth quarter production and
despite lower average netback oil prices over the same period which decreased from to $52.58 per barrel from the
$59.72 per barrel in the third quarter. The average netback price for the year was $54.52 per barrel.
Lifting costs are comprised of the Company’s share of expenses related to the production of oil from the Atrush Block
including operation and maintenance of wells and production facilities, insurances, and the operator’s related support
costs. The average lifting costs in the fourth quarter was $7.84 per barrel, down from $7.92 per barrel in the third
quarter mainly due to the higher average production in the fourth quarter. Lifting costs averaged $7.41 per barrel
over the year 2018 compared to $8.52 per barrel in the year 2017. The 2018 average lifting costs were above guidance
due to lower production than planned and additional costs related to mitigating salt related problems. Other costs of
production include the Company’s share of production bonuses paid to the KRG, $1.7 million was paid in the fourth
quarter of 2018, and of other costs prescribed under the Atrush PSC.
Oil and gas assets are depleted using the unit of production method based on proved and probable reserves using
estimated future prices and costs and accounting for future development expenditures necessary to bring those
reserves into production. The reserves correspond to the Company’s entitlement to oil under the terms of the PSC.
The depletion cost per entitlement barrel was $37.12 and $22.07, respectively for the three and twelve months ended
December 31, 2018. Changes to depletion rates resulting from changes in reserve quantities and estimates of future
development expenditure are reflected prospectively and the increase in the depletion cost in the fourth quarter of
2018 is attributable to a reclass of capital costs from E&E to PP&E at the end of 2018 and an increase in forecasted
future development costs (for further information refer to the “Reserves and Resource” section below).
General and administrative expense
In $000
Salaries and benefits
Legal, accounting and audit fees
Management and consulting fees
Listing costs and investor relations
General and other office expenses
Travel expenses
Advertisements
General and administrative expense
---------Three month period---------
Q4.2017
Q4.2018 Q3.2018
-----Twelve month period----
Q4.2017
Q4.2018
1,045
472
156
67
86
87
-
1,913
453
40
114
68
84
26
-
785
503
102
121
56
106
43
35
966
2,494
682
463
335
332
258
-
4,564
3,093
242
372
286
331
152
35
4,511
The higher general and administrative expense incurred in the year 2018 was principally due to legal and consulting
services related to refinancing the Company’s bonds and towards acquiring an additional interest in Atrush and were
offset by lower payroll costs relating to salary bonuses incurred by the Company’s Swiss subsidiary in the prior year.
4 The Company’s 2018 entitlement share included an adjustment for the exploration cost sharing arrangement between TAQA and GEP. TAQA
and GEP had under the Atrush JOA agreed a priority arrangement for sharing their combined initial $49.9 million share of exploration cost oil
revenues such that TAQA received the initial $10.8 million and GEP received the next $39.1 million. Thereafter cost oil revenues for these two
parties is determined by their relative participating interests in the Atrush PSC. The Company’s entitlement share of oil sold in 2018 reflects a
full recovery of the $39.1 million.
7
Share based payments expense
In $000
---------Three month period---------
Q4.2017
Q4.2018 Q3.2018
-----Twelve month period----
Q4.2017
Q4.2018
Share based payments expense
-
-
-
-
11
The Company uses the fair value method of accounting for stock options granted to directors, officers, employees
and consultants whereby the fair value of all stock options granted is recorded as a charge to operations. The fair
value of common share options granted is estimated on the date of grant using the Black-Scholes option pricing
model. Share based payments expense results from the vesting of stock options granted over the vesting period which
is normally two years after the grant date. The last stock option grant of January 19, 2015 is now fully vested and was
fully expensed at the end of the first quarter of 2017.
Depreciation and amortisation expense
In $000
---------Three month period---------
Q4.2017
Q4.2018 Q3.2018
----Twelve month period-----
Q4.2017
Q4.2018
Depreciation and amortisation expense
1
1
-
8
26
Depreciation and amortisation expense corresponds to cost of use of the furniture and IT equipment at the Company’s
technical and administrative offices located in Switzerland and Kurdistan.
Finance income
In $000
---------Three month period---------
Q4.2017
Q4.2018 Q3.2018
----Twelve month period-----
Q4.2017
Q4.2018
Interest on Atrush Development Cost Loan
Interest on Atrush Feeder Pipeline Cost Loan
Interest on deposits
Total interest income
Foreign exchange gain
Total finance income
151
99
645
895
5
900
190
122
57
369
-
369
242
106
13
361
-
361
836
535
720
2,091
-
2,091
1,042
500
107
1,649
28
1,677
Under the terms of the 4th PSC Amendment and the Atrush Facilitation Agreement the Non-Government Contractors
have agreed to pay their pro-rata share of the Feeder Pipeline costs and of the KRG’s share of Atrush development
costs up to October 31, 2017. Thereafter these costs will be reimbursed to the Non-Government Contractors. The
loan interest amounts reported in the year 2018 represent 7% per annum interest on the principal balances
outstanding over this period. For further information on the loans refer to the discussion under the “Loans and
receivables” section below.
Interest on deposits represents bank interest earned on cash, investments and restricted cash held in interest bearing
funds. The overall decrease in interest income reported in the year 2018 relative to the amount reported in 2017 is
due to the decreasing loan principal balance over this period because of the loan payments received from the KRG,
and partially offset by the increase in interest on deposits due to the higher level of interest-bearing funds held in
2018.
8
Finance cost
In $000
---------Three month period---------
Q4.2017
Q4.2018 Q3.2018
----Twelve month period-----
Q4.2017
Q4.2018
Interest charges on bonds at coupon rate
Call premiums on early retirement of bonds
Amortisation of bond transaction costs
Interest expense on borrowings
Foreign exchange loss
Unwinding discount on decommissioning provision
Total finance costs before borrowing costs capitalised
Borrowing costs (capitalised as) / reversed from E&E
7,280
-
183
7,463
-
6
7,469
7,429
1,427
484
9,340
21
5
9,366
5,221
-
210
5,431
83
4
5,518
25,428
1,427
1,087
27,942
26
5
27,973
20,018
-
841
20,859
102
4
20,965
and PP&E assets
Finance cost
(122)
(780)
284
(4,859)
(8,770)
7,347
8,586
5,802
23,114
12,195
The increase in interest charges on bonds between the years 2018 and 2017 is principally due to the new ShaMaran
bond issue which brought bonds outstanding before the issue of $186 million up to $240 million after the issue on
July 5, 2018. In addition, the coupon rate on the new bonds increased to 12% from 11.5% coupon rate on the retired
GEP bonds. Since the GEP bonds were retired earlier than the November 13, 2018 maturity date the GEP paid to
bondholders call premiums in accordance with the terms of the related bond agreements.
Borrowing costs are capitalised where they are directly attributable to the acquisition of, and preparation for their
intended use, Atrush development assets. All other borrowing costs are recognised in profit or loss in the period in
which they are incurred. The significant decrease in capitalised borrowing costs in 2018 is due to a significant number
of development projects having been completed for their intended use. For further information on the Company’s
borrowings refer to the discussion in the section below entitled “Borrowings”.
Income tax expense
In $000
---------Three month period---------
Q4.2017
Q4.2018 Q3.2018
----Twelve month period-----
Q4.2017
Q4.2018
Income tax expense
25
12
14
64
85
Income tax expense relates to provisions for income taxes on service income generated in Switzerland which is based
on costs incurred in procuring the services. The decrease in tax expense reported in the year ended December 31,
2018 is primarily due to lower taxable income in the Company’s Swiss subsidiary which decreased compared to 2017
due to lower costs of service.
Capital Expenditures on Property Plant & Equipment (“PP&E”)
The net book value of PP&E is principally comprised of development costs related to the Company’s share of Atrush
PSC proved and probable reserves as estimated by McDaniel less the cumulative depletion costs corresponding to
commercial production which commenced in July 2017. The movements in PP&E are explained as follows:
In $000
Year ended December 31, 2018
Office
equipment
Oil and gas
assets
Total
Year ended December 31, 2017
Office
equipment
Oil and gas
assets
Total
Opening net book value
Additions
Reclass from intangible E&E assets
Depletion and depreciation expense
Net book value
184,918
17,356
21,794
(28,171)
195,897
3
12
-
(4)
11
184,921
17,368
21,794
(28,175)
195,908
174,642
17,903
-
(7,627)
184,918
16
3
-
(16)
3
174,658
17,906
-
(7,643)
184,921
During the year 2018 movements in PP&E were comprised of additions of $17.4 million (year 2017: $17.9 million),
depletion and depreciation expense of $28.2 million (year 2017: $7.6 million) and a reclass to PP&E from E&E of $21.8
million (year 2017: $nil) which resulted in a net increase of $11.0 million to the net book value of PP&E assets. Net
additions in 2018 included capitalised borrowing costs of $5.0 million (year 2017: $8.8 million). During the year 2018
plans were approved to produce and sell heavy oil which has resulted in the reclass from E&E to PP&E of $21.8 of
heavy oil related project costs.
9
Capital Expenditures on Intangible Assets
The net book value of Intangible assets is principally comprised of exploration and evaluation (“E&E”) assets which
represent the Atrush Block exploration and appraisal costs related to the Company’s share of Atrush Block contingent
resources as estimated by McDaniel. The movements in Intangible assets are explained as follows:
In $000
Opening net book value
Additions
Reclass to PP&E
Disposals
Amortisation expense
Net book value
Year ended December 31, 2018
Software
E&E
& Licences
assets
Total
Year ended December 31, 2017
Software
E&E
& Licences
assets
Total
89,113
506
(21,794)
-
-
67,825
6
3
-
-
(5)
4
89,119
509
(21,794)
-
(5)
67,829
88,972
141
-
-
-
89,113
35
2
-
(21)
(10)
6
89,007
143
-
(21)
(10)
89,119
During the year 2018 movements in intangible assets were comprised of net additions of $509 thousand (year 2017:
$143 thousand), depreciation of $5 thousand (year 2017 $10 thousand) and a reclass of $21.8 million (year 2017: $nil)
from E&E to PP&E resulting in a net decrease to intangible assets of $21.3 million. Net additions in 2018 included the
reversal of borrowing costs of $123 thousand (year 2017: $16 thousand).
Loans and receivables
In November 2016 the Company entered into certain agreements with the KRG and other Atrush contractors for the
reimbursement by the KRG to the Atrush contractors of certain Atrush exploration and development costs and
pipeline costs incurred by KRG in the years 2013 through 2017 which were funded by the Atrush contractors. The
Atrush Exploration Costs receivables, which relate to a share of the KRG’s development costs carried by ShaMaran
prior to the year 2016 and deemed to be exploration costs under the Atrush PSC, are repaid through an accelerated
petroleum cost recovery arrangement. The Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost Loan
are being repaid with interest at 7% per annum in 24 equal monthly instalments ending in October 2019. The Company
was owed amounts for its entitlement share of oil deliveries made to the KRG during the last three months of the
year.
At year end the Company had loans and receivables outstanding as follows:
In $000
As at December 31,
Atrush Exploration Costs receivable
Accounts receivable on Atrush oil sales
Atrush Development Cost Loan
Atrush Feeder Pipeline Cost Loan
Total loans and receivables
2018
34,898
14,531
7,136
4,718
61,283
2017
37,247
13,957
16,018
9,751
76,973
In the year 2018 the Company received principal plus interest payments totalling $11.3 million for Atrush
Development Cost Loan and $6.9 million for the Atrush Feeder Pipeline Cost Loan, as well as $2.3 million of Atrush
Exploration Cost receivables.
In the year 2019 up to the date of the MD&A the Company received $14.0 million in total payments for loans and
receivables balances outstanding at December 31, 2018, comprised of $10.9 million in total payments for its
entitlement share of oil sales for the months of October and November 2018, $2.6 million for Atrush Development
Cost Loan and Atrush Feeder Pipeline Cost Loan balances outstanding and $0.5 million in reimbursements of the
Atrush Exploration Costs receivable.
10
Borrowings
On July 5, 2018 the Company issued $240 million of senior unsecured bonds (“the ShaMaran bonds”). The ShaMaran
bonds have a five-year maturity without amortization and carry 12% fixed semi-annual coupon. Holders of $136
million of the $186.4 million of previously outstanding bonds (“GEP bonds”) of General Exploration Partners, Inc.
(“GEP”), a wholly owned subsidiary of the Company, agreed to early redeem their bonds in exchange for receiving an
equivalent amount of ShaMaran bonds. As a result the Company received $104 million ($100.4 million net of related
transaction costs) of cash proceeds from the ShaMaran bond issue. An amount of $50.4 million of the cash proceeds,
with an additional $3 million of the Company’s cash, have been used to early retire the remaining GEP bonds and the
remaining $53 million of the cash proceeds were held by the Company in an escrow account pledged to the
bondholders (the “Marathon Pledged Account”) on the balance sheet date, pending release to the Company upon
the closing of the purchase by the Company of an additional interest in the Atrush asset under terms prescribed in
the bond agreement. On December 31, 2018, in accordance with the terms of the ShaMaran bonds the Company
contributed $14.4 million, representing one semi-annual interest payment, to a Debt Service Retention Account
(“DSRA”) and pledged to the bondholders as security for the Company’s obligations under the ShaMaran bonds. The
amounts on deposit in the Marathon Pledged Account and the DSRA resulted in total restricted cash of $67.9 million
on the balance sheet date, including interest earned of $484 thousand.
The movements in borrowings are explained as follows:
In $000
As at December 31,
Opening balance
Bond issued – net of transaction costs
Interest charges at coupon rate
Call premiums on early retirement of bonds
Amortisation of bond transaction costs
Bonds issued as interest payments
Payment to Bondholders – interest and call premiums
Bonds retired
Ending balance
- Current portion: accrued bond interest expense
- Current portion: borrowings
- Non-current portion: borrowings
2018
188,491
236,361
25,428
1,427
1,087
-
(15,575)
(186,422)
250,797
14,080
-
236,717
2017
167,632
-
20,018
-
841
19,721
(19,721)
-
188,491
2,799
185,692
-
Events after the reporting period related to Borrowings
On January 5, 2019 the Company issued the first semi-annual interest payment to ShaMaran bondholders in the
amount of $14.4 million.
•
•
On February 1, 2019, bondholders approved of certain amendments to the ShaMaran Bonds agreement as follows:
•
funds on deposit in the DSRA may be used by the Company to fund the Acquisition and for general corporate
purposes;
funds in the Marathon Pledged Account will be used by the Company to prepay $50 million of ShaMaran Bonds
plus accrued interest;
the Company will reduce the aggregate outstanding amount of the Bond Issue to a maximum of $175 million on
or before July 2020;
in case the Acquisition is not closed by July 4, 2019 there will be a one-time step up in bond coupon interest by
1% per annum; and
the Liquidity Guarantee will remain in force until the Company has funded the DSRA with 12 months of bond
coupon interest.
•
•
On February 8, 2019, the Company repaid $50 million of ShaMaran Bonds and $550 thousand of related accrued
interest. At the date the financial statements were approved there were $190 million of ShaMaran Bonds
outstanding.
Nemesia S.à.r.l. (“Nemesia”), a company controlled by a trust settled by the estate of the late Adolf H. Lundin, agreed
to guarantee the Company’s obligations under the ShaMaran Bonds agreement up to an amount of $22.8 million (the
“Liquidity Guarantee”) representing one year of coupon interest of $190 million of ShaMaran Bonds now outstanding.
In exchange for providing the Liquidity Guarantee the Company issued Nemesia 2,000,000 common shares of
ShaMaran. In case of a draw down on the Liquidity Guarantee, the Company is required to issue to Nemesia a further
50,000 shares of ShaMaran for each $500 thousand drawn down per month until the drawn amount is repaid.
Nemesia are a related party after this event in 2019.
11
The remaining contractual obligations under the amended ShaMaran Bonds at the date of this MD&A, which are
comprised of the repayment of principal and interest expense based on undiscounted cash flows at payment date,
reflect the repayment of $50.6 million of principal and interest on February 8, 2019, and are based on the current
$190 million of bonds outstanding thereafter until a further reduction in ShaMaran Bonds outstanding to $175 million
is completed in July 2020, are as follows:
In $000
March 8 to December 31, 2019
Year ended December 31, 2020
Three years ended December 31, 2023
Total
11,400
37,800
238,000
287,200
SELECTED QUARTERLY FINANCIAL INFORMATION
The following is a summary of selected quarterly financial information for the Company:
(In $000, except per share
data)
Continuing operations
Revenues
Cost of goods sold
General and admin. expense
Share based payments expense
Depreciation and
amortisation
Finance cost
Finance income
Income tax expense
Dec-31
2018
Sep-30
2018
Jun-30
2018
Mar 31
2018
Dec 31
2017
Sep 30
2017
Jun 30 Mar 31
2017
2017
For the quarter ended
14,531
(15,969)
(1,913)
-
(1)
(7,347)
900
(25)
13,240
(6,945)
(785)
-
(1)
(8,586)
369
(12)
15,328
(6,990)
(941)
-
(2)
(3,016)
444
(11)
26,501
(12,168)
(925)
-
(4)
(4,230)
443
(16)
13,907
(9,426)
(966)
-
-
(5,802)
361
(14)
3,782
(4,583)
(1,637)
-
(8)
(3,436)
525
(36)
-
-
(818)
-
(8)
(1,482)
439
(14)
-
-
(1,090)
(11)
(10)
(1,503)
352
(21)
Net (loss) / income
(9,824)
(2,720)
4,812
9,601
(1,940)
(5,393)
(1,883)
(2,283)
Basic and diluted net (loss) /
inc in $ per share
(0.005)
(0.001)
0.002
0.004
(0.001)
(0.002)
(0.001)
(0.001)
Summary of Principal Changes in the Fourth Quarter Financial Information
In the fourth quarter of 2018 production from the Atrush Block and work on the Atrush development program
continued. The net loss was principally driven by $10.3 million of depletion costs, a non-cash expense, included in
cost of goods sold, as well as the inclusion of $1.7 million of production bonuses paid to the KRG, and relating to the
10 million barrel cumulative production milestone reached in November 2018, as well as the financing costs of $7.3
million which reflected $240 million of bond principal outstanding during the period. The bonds outstanding were
reduced to $190 million on February 8, 2019.
LIQUIDITY AND CAPITAL RESOURCES
Working capital at December 31, 2018 was positive $112.9 million compared to negative $155.6 million at December
31, 2017. The increase in working capital since December 31, 2017, is principally due to significant operational cash
flows over the past year and to the re-financing of the Company’s bonds in the third quarter of 2018. Refer also to
the discussion above under “Borrowings”.
The overall cash position of the Company increased by $87.2 million during the year 2018 compared to an increase in
cash of $0.8 million during the same period of 2017. The main components of the movement in funds are discussed
in the following paragraphs.
12
The operating activities of the Company during the year 2018 resulted in an increase in the cash position of
$47.4 million compared to a decrease of $8.8 million in the cash position during the comparable period of 2017. The
increase in the cash position is explained by net income of $1.9 million plus $45.5 million of net positive cash
adjustments from working capital items, net borrowing costs and non-cash expenses.
Net cash inflows from investing activities in 2018 were $5.5 million compared to cash outflows of $16.7 million during
the same period in 2017. Cash inflows from investing activities in 2018 were comprised of cash inflows of $18.4 million
in payments by the KRG of Atrush loans and receivables, which includes interest on the loans, net of cash outflows of
$12.9 million on investments in the Atrush Block development work program.
Net cash inflows to financing activities in the year were $34.4 million compared to $26.4 million of cash inflows in the
comparable period in 2017. The Company received $100.4 million of net cash proceeds from the ShaMaran bond
issue net of related transaction costs. $15.6 million of coupon interest payments made to bondholders as well as
$50.4 million to early retire GEP bonds which were not exchanged for new ShaMaran bonds.
The consolidated financial statements were prepared on the going concern basis which assumes that the Company
will be able to realise its assets and liabilities in the normal course of business as they come due in the foreseeable
future.
OUTSTANDING SHARE DATA AND STOCK OPTIONS
The Company had 2,158,631,534 outstanding shares at December 31, 2018, (2,183,631,534 outstanding shares after
dilution). On January 23, 2019, the Company issued to Nemesia 2,000,000 common shares of ShaMaran in accordance
with the terms of the Liquidity Guarantee. Therefore, at the date of this MD&A the Company had 2,160,631,534
outstanding shares. Refer also to the discussion under the Borrowings section above. The average outstanding shares
during the year 2018 were 2,158,631,534 before dilution (2017: 2,129,042,493) and 2,183,631,534 after dilution
(2017: 2,157,207,493).
The Company has established share unit plans and a share purchase option plan whereby a committee of the
Company’s Board may, from time to time, grant up to a total of 10% of the issued share capital to directors, officers,
employees or consultants. The number of shares issuable under these plans at any specific time to any one recipient
shall not exceed 5% of the issued and outstanding common shares of the Company. Under the share unit plans the
Company may grant performance share units (“PSU”), restricted share units (“RSU”) or deferred share units (“DSU”).
PSU grants may be awarded annually to employees, directors or consultants (“Participants”) based on the fulfilment
of defined Company and individual performance parameters. RSU grants may be awarded to Participants annually
based on the fulfilment of defined Company performance parameters. RSUs and PSUs will vest based on the
conditions described in the relevant grant agreement and, in any case, no later than the end of the third calendar
year following the date of the grant. DSU’s may be awarded annually to non-employee directors of the Company
based on the performance of the Company and vest immediately at the time of grant; however DSUs may not be
redeemed until a minimum period of three months has passed following the end of service as a director of the
Company. The share unit plans provide for redemption of the share units by way of payment in cash, shares or a
combination of cash and shares. Under the option plan the term of any options granted under the option plan will be
fixed by the Board and may not exceed five years from the date of grant. A four month hold period may be imposed
by the stock exchange from the date of grant. Vesting terms are at the discretion of the Board. All issued share options
have terms of five years and vest over two years from grant date. The exercise prices reflect trading values of the
Company’s shares at grant date.
At December 31, 2018 there were 25,000,000 stock options outstanding under the Company’s employee incentive
stock option plan. 3,165,000 stock options expired during the current year to date (year 2017: nil). No stock options
were forfeited or exercised in 2018 (year 2017: nil). There has been no further change in the number of stock options
outstanding from December 31, 2018, to the date of this MD&A.
There were no grants of share units at the balance sheet date.
The Company has no warrants outstanding.
13
OFF BALANCE SHEET ARRANGEMENTS
The Company has no off-balance sheet arrangements.
RELATED PARTY TRANSACTIONS
In $000
Bennett-Jones
Namdo Management Services Ltd.
Lundin Petroleum AB
Total
Purchases of services during the year
2018
2017
Amounts owing at December 31,
2017
2018
51
34
104
189
45
50
204
299
-
-
-
-
-
-
18
18
Bennett-Jones is a law firm in which an officer of the Company is a partner and has provided legal services to the
Company. Amounts reported under Bennett Jones are inclusive of services provided to the Company by McCullough
O’Connor Irwin LLP, which merged with Bennett Jones on June 1, 2018, where the same officer of the Company was
previously a partner.
Namdo Management Services Ltd. is a private corporation affiliated with a shareholder of the Company and has
provided corporate administrative support and investor relations services to the Company.
The Company received services from various subsidiary companies of Lundin Petroleum AB (“Lundin”), a shareholder
of the Company until June 21, 2018, when Lundin sold its ShaMaran shares. Lundin charges from January 1 to June
21, 2018 of $104 (year 2017: $204) were comprised of office rental, administrative and building services of $88 (year
2017: $177), technical service costs of $nil (year 2017: $1) and investor relations services of $16 (year 2017: $27).
All transactions with related parties are in the normal course of business and are made on the same terms and
conditions as with parties at arm’s length.
Also refer to the discussion under the “Outstanding Share Data and Stock Options” section above.
COMMITMENTS AND CONTINGENCIES
Atrush Block Production Sharing Contract
Under the terms of the Atrush PSC the development period is for 20 years after declaration of commerciality
(November 7, 2012) with an automatic right to a five-year extension and the possibility to extend for an additional
five years. All qualifying petroleum costs incurred by the Contractors shall be recovered from a portion of available
petroleum production, defined under the terms of the Atrush PSC. All modifications to the Atrush PSC are subject to
the approval of the KRG. The Company is responsible for its pro-rata share of the costs incurred in executing the
development work program on the Atrush Block which commenced on October 1, 2013.The Company is responsible
for its pro-rata share of the costs incurred in executing the development work program on the Atrush Block which
commenced on October 1, 2013.
As at December 31, 2018, the outstanding commitments of the Company were as follows:
In $000
For the year ended December 31,
Atrush Block development
Office and other
Total commitments
2019
47,583
39
47,622
2020
120
-
120
2021
Thereafter
Total
120
-
120
1,328
-
1,328
49,151
39
49,190
Amounts relating to Atrush Block development represent the Company’s unfunded paying interest share of 20.1% of
the approved 2019 work program and other obligations under the Atrush PSC.
Under the terms of the Atrush PSC the Company will owe a share of production bonuses payable to the KRG when
cumulative oil production from Atrush reaches production milestones defined in the Atrush PSC as follows: $13.3
million at 25 million barrels (ShaMaran share: $3.6 million); and $23.3 million at 50 million barrels (ShaMaran share:
$6.2 million).
14
PROPOSED TRANSACTIONS
ShaMaran entered into agreements on December 26, 2018 to acquire jointly with TAQA the 15% interest in the Atrush
Block held by MIOC. Following close of these agreements ShaMaran’s working interest in Atrush will increase from
20.1% to 27.6%. The parties to the agreements are currently in the process of obtaining the consent of the KRG.
The Company continues to evaluate other new opportunities.
CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICIES
Accounting Estimates
The consolidated financial statements of the Company have been prepared by management using IFRS. In preparing
financial statements, management makes informed judgments and estimates that affect the reported amounts of
assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and
expenses during the period. Specifically, estimates are utilised in calculating depletion, asset retirement obligations,
fair values of assets on acquisition of control, share-based payments, amortisation and impairment write-downs as
required. Actual results could differ from these estimates and differences could be material.
Significant Accounting Policies
The Company adopted IFRS 15, Revenue from Contracts with Customers and IFRS 9, Financial Instruments effective
January 1, 2018. Refer to Note 3 “Significant Accounting Policies” in the Company’s Consolidated Financial Statements
for the year ended December 31, 2018, for further discussion.
Other standards, amendments and interpretations, which are effective for the financial year beginning on January 1,
2018, have been assessed and do not have a material impact to the Company.
New Accounting Standards Issued But Not Yet Applied
Standards and interpretations issued but not yet effective up to the date of issuance of the financial statements are
listed below.
IFRS 16: Leases will replace IAS 17 Leases and requires assets and liabilities arising from all leases, with some
exceptions, to be recognized on the balance sheet. The new standard will be effective for annual periods beginning
on or after January 1, 2019. The Company currently has no outstanding leases.
There are no other standards that are not yet effective and that would be expected to have a material impact on the
entity in the current or future reporting periods and on foreseeable future transactions.
Accounting for Oil and Gas Operations
The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method
acquisition costs of oil and gas properties, costs to drill and equip exploratory and appraisal wells that are likely to
result in proved reserves and costs of drilling and equipping development wells are capitalised and subject to annual
impairment assessment.
Exploration well costs are initially capitalised and, if subsequently determined to have not found sufficient reserves
to justify commercial production, are charged to exploration expense. Exploration well costs that have found
sufficient reserves to justify commercial production, but whose reserves cannot be classified as proved, continue to
be capitalised if sufficient progress is being made to assess the reserves and economic viability of the well and or
related project.
Capitalised costs of proved oil and gas properties are depleted using the unit of production method based on
estimated gross proved and probable reserves of petroleum and natural gas as determined by independent engineers.
Successful exploratory wells and development costs and acquired resource properties are depleted over proved and
probable reserves. Acquisition costs of unproved reserves are not depleted or amortised while under active
evaluation for commercial reserves. Costs associated with significant development projects are depleted once
commercial production commences. A revision to the estimate of proved and probable reserves can have a significant
impact on earnings as they are a key component in the calculation of depreciation, depletion and accretion.
15
Producing properties and significant unproved properties are assessed annually, or more frequently as economic
events dictate, for potential indicators of impairment. Economic events which would indicate impairment include:
•
•
•
•
•
The period for which the Company has the right to explore in the specific area has expired during the period or
will expire in the near future and is not expected to be renewed.
Substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is
neither budgeted nor planned.
Exploration for and evaluation of resources in the specific area have not led to the discovery of commercially
viable quantities of mineral resources and the Company has decided to discontinue such activities in the specific
area.
Sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying
amounts of E&E and oil and gas assets is unlikely to be recovered in full from successful development or by sale.
Extended decreases in prices or margins for oil and gas commodities or products.
• A significant downwards revision in estimated volumes or an upward revision in future development costs.
For impairment testing the assets are aggregated into cash generating unit (“CGU”) cost pools based on their ability
to generate largely independent cash flows. The recoverable amount of a CGU is the greater of its fair value less costs
to sell and its value in use. Fair value is determined to be the amount for which the asset could be sold in an arm’s
length transaction. Value in use is determined by estimating the present value of the future net cash flows expected
to be derived from the continued use of the asset or CGU.
Where conditions giving rise to the impairment subsequently reverse the effect of the impairment charge is also
reversed as a credit to the statement of comprehensive income net of any depreciation that would have been charged
since the impairment.
A substantial portion of the Company’s exploration and development activities are conducted jointly with others.
RESERVES AND RESOURCE ESTIMATES
The Company engaged McDaniel to evaluate 100% of the Company’s reserves and resource data at December 31,
2018. The conclusions of this evaluation have been presented in a Detailed Property Report which has been prepared
in accordance with standards set out in the Canadian National Instrument NI 51-101 and Canadian Oil and Gas
Evaluation Handbook (“COGEH”).
The Company’s crude oil reserves as of December 31, 2018 were, based on the Company’s working interest of 20.1
percent in the Atrush Block, estimated to be as follows:
Company estimated reserves (diluted)
As of December 31, 2018
Proved
Developed
Proved
Undeveloped
Total
Proved
Probable
Total Proved
& Probable
Possible
Total Proved,
Probable &
Possible
Light/Medium Oil (Mbbl)(1)
Gross(2)
Net(3)
Heavy Oil (Mbbl)(1)
Gross(2)
Net(3)
4,839
2,695
-
-
3,402
1,940
484
272
8,241
4,635
11,603
5,761
19,844
10,397
10,227
3,256
30,071
13,653
484
272
740
369
1,224
641
776
267
2,000
908
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.
The Company’s crude oil and natural gas contingent resources as of December 31, 2018, were estimated to be as
follows, based on a Company working interest of 20.1 percent in the Atrush Block:
16
Company estimated contingent resources (diluted) (1) (2)(4)(5)
As of December 31, 2018
Light/Medium Oil (Mbbl)(3)
Gross
Heavy Oil (Mbbl)(3)
Gross
Natural Gas (MMcf)
Gross
Low Estimate
(1C)
Best Estimate
(2C)
High Estimate
(3C)
Risked Best
Estimate
10,691
10,735
11,004
8,588
21,039
43,153
70,908
34,522
5,029
9,058
13,763
453
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 which differ from reserves mainly due to the uncertainty over the future development plan which will
depend in part on Phase 1 production performance and the HOWET planned for the first half of 2019.
Prospective resources have not been re-evaluated since December 31, 2013.
Risks in estimating resources
There are a number of uncertainties inherent in estimating the quantities of reserves and resources including
factors which are beyond the control of the Company. Estimating reserves and resources is a subjective process
and the results of drilling, testing, production and other new data after the date of an estimate may result in
revisions to original estimates.
Reservoir parameters may vary within reservoir sections. The degree of uncertainty in reservoir parameters used to
estimate the volume of hydrocarbons, such as porosity, net pay and water saturation, may vary. The type of formation
within a reservoir section, including rock type and proportion of matrix and or fracture porosity, may vary laterally
and the degree of reliability of these parameters as representative of the whole reservoir may be proportional to the
overall number of data points (wells) and the quality of the data collected. Reservoir parameters such as permeability
and effectiveness of pressure support may affect the recovery process. Recovery of reserves and resources may also
be affected by the availability and quality of water, fuel gas, technical services and support, local operating conditions,
security, performance of the operating company and the continued operation of well and plant equipment.
Additional risks associated with estimates of reserves and resources include risks associated with the oil and gas
industry in general which include normal operational risks during drilling activity, development and production; delays
or changes in plans for development projects or capital expenditures; the uncertainty of estimates and projections
related to production, costs and expenses; health, safety, security and environmental risks; drilling equipment
availability and efficiency; the ability to attract and retain key personnel; the risk of commodity price and foreign
exchange rate fluctuations; the uncertainty associated with dealing with governments and obtaining regulatory
approvals; performance and conduct of the Operator; and risks associated with international operations.
The Company’s project is in the early production stage and, as such, additional information must be obtained by
further drilling and testing to ultimately determine the economic viability of developing any of the contingent or
prospective resources. There is no certainty that the Company will be able to commercially produ ce any portion
of its contingent or prospective resources. Any significant change, in particular, if the volumetric resource
estimates were to be materially revised downwards in the future, could negatively impact investor confidence
and ultimately impact the Company’s performance, share price and total market capitalisation.
The Company has engaged professional geologists and engineers to evaluate reservoir and development plans;
however, process implementation risk remains. The Company’s reserves and resource estimations are based on
data obtained by the Company which has been independently evaluated by McDaniel.
17
FINANCIAL INSTRUMENTS
The Company’s financial instruments currently consist of cash, cash equivalents, advances to joint operations, other
receivables, borrowings, accounts payable and accrued expenses, accrued interest on bonds, provisions for
decommissioning costs, and current tax liabilities. The Company classifies its financial assets and liabilities at initial
recognition in the following categories:
•
•
•
Financial assets and liabilities at fair value through profit or loss are those assets and liabilities acquired principally
to sell or repurchase in the short-term and are recognised at fair value. Transaction costs are expensed in the
statement of comprehensive income and gains or losses arising from changes in fair value are also presented in
the statement of comprehensive income within other gains and losses in the period in which they arise. Financial
assets and liabilities at fair value through profit or loss are classified as current except for the portion expected
to be realised or paid beyond twelve months of the balance sheet date, which is classified as non-current.
Financial assets carried at amortised cost comprise of loans, receivables and cash and cash equivalents with fixed
or determinable payments that are not quoted on an active market and are generally included within current
assets due to their short-term nature and are classified as financial assets when the Company has a right to cash
collection. If collection of the amounts is expected in one year or less they are classified as current assets. If not,
they are presented as non-current assets. Loans and receivables are initially recognised at fair value and are
subsequently measured at amortised cost using the effective interest method less any provision for impairment.
Financial liabilities at amortised cost comprise of trade and other payables and are initially recognised at the fair
value of the amount expected to be paid and are subsequently measured at amortised cost using the effective
interest rate method. Financial liabilities are classified as current liabilities unless the Company has an
unconditional right to defer settlement for at least 12 months after the balance sheet date.
With the exception of borrowings, accrued interest on bonds and provisions for decommissioning costs, which have
fair value measurements based on valuation models and techniques where the significant inputs are derived from
quoted prices or indices, the fair values of the Company’s other financial instruments did not require valuation
techniques to establish fair values as the instrument was either cash and cash equivalents or, due to the short term
nature, readily convertible to or settled with cash and cash equivalents.
The Company is exposed in varying degrees to a variety of financial instrument related risks which are discussed in
the following sections:
Financial Risk Management Objectives
The Company’s management monitors and manages the Company’s exposure to financial risks facing the operations.
These financial risks include market risk (including commodity price, foreign currency and interest rate risks), credit
risk and liquidity risk.
The Company does not presently hedge against these risks as the benefits of entering into such agreements is not
considered to be significant enough as to outweigh the significant cost and administrative burden associated with
such hedging contracts.
Commodity price risk: The prices that the Company receives for its oil and gas production may have a significant
impact on the Company’s revenues and cash flows provided by operations. World prices for oil and gas are
characterised by significant fluctuations that are determined by the global balance of supply and demand and
worldwide political developments and, in particular, the price received for the Company’s oil and gas production in
Kurdistan is dependent upon the Kurdistan government and its ability to export production outside of Iraq. A decline
in the price of ICE Brent Crude oil, a reference in determining the price at which the Company can sell future oil
production, could adversely affect the amount of funds available for capital reinvestment purposes as well as the
Company’s value in use calculations for impairment test purposes.
The Company does not hedge against commodity price risk.
Foreign currency risk: The substantial portion of the Company’s operations require purchases denominated in USD,
which is the functional and reporting currency of the Company and the currency in which the Company maintains the
substantial portion of its cash and cash equivalents. Certain of its operations require the Company to make purchases
denominated in foreign currencies, which are currencies other than USD and correspond to the various countries in
which the Company conducts its business, most notably, Swiss Francs (“CHF”) and Canadian dollars (“CAD”). As a
result, the Company holds some cash and cash equivalents in foreign currencies and is therefore exposed to foreign
currency risk due to exchange rate fluctuations between the foreign currencies and the USD. The Company considers
its foreign currency risk is limited because it holds relatively insignificant amounts of foreign currencies at any point
in time and since its volume of transactions in foreign currencies is currently relatively low. The Company has elected
not to hedge its exposure to the risk of changes in foreign currency exchange rates.
18
Interest rate risk: The Company earns interest income at variable rates on its cash and cash equivalents and is
therefore exposed to interest rate risk due to a fluctuation in short-term interest rates.
The Company’s policy on interest rate management is to maintain a certain amount of funds in the form of cash and
cash equivalents for short-term liabilities and to have the remainder held on relatively short-term deposits.
ShaMaran is leveraged though bond financing at the corporate level. However, the Company is not exposed to interest
rate risks associated with the bonds as the interest rate is fixed until July 2023.
Credit risk: Credit risk is the risk that a counterparty will default on its contractual obligations resulting in financial
loss to the Company. The Company is primarily exposed to credit risk on its cash and cash equivalents, loans and
receivables and other receivables.
The Company manages credit risk by monitoring counterparty ratings and credit limits and by maintaining excess cash
and cash equivalents on account in instruments having a minimum credit rating of R-1 (mid) or better (as measured
by Dominion Bond Rate Services) or the equivalent thereof according to a recognised bond rating service.
The carrying amounts of the Company’s financial assets recorded in the consolidated financial statements represent
the Company’s maximum exposure to credit risk.
Liquidity risk: Liquidity risk is the risk that the Company will have difficulties meeting its financial obligations as they
become due. In common with many oil and gas exploration companies, the Company raises financing for its
exploration and development activities in discrete tranches to finance its activities for limited periods. The Company
seeks to acquire additional funding as and when required. The Company anticipates making substantial capital
expenditures in the future for the acquisition, exploration, development and production of oil and gas reserves and
as the Company’s project moves further into the development stage, specific financing, including the possibility of
additional debt, may be required to enable future development to take place. The financial results of the Company
will impact its access to the capital markets necessary to undertake or complete future drilling and development
programs. There can be no assurance that debt or equity financing, or future cash generated by operations, would be
available or sufficient to meet these requirements or, if debt or equity financing is available, that it will be on terms
acceptable to the Company.
The Company manages liquidity risk by maintaining adequate cash reserves and by continuously monitoring forecast
and actual cash flows. Annual capital expenditure budgets are prepared, which are regularly monitored and updated
as considered necessary. In addition, the Company requires authorisations for expenditure on both operating and
non-operating projects to further manage capital expenditures.
RISKS AND UNCERTAINTIES
ShaMaran Petroleum Corp. is engaged in the exploration, development and production of crude oil and natural gas
and its operations are subject to various risks and uncertainties which include but are not limited to those listed
below. If any of the risks described below materialise the effect on the Company’s business, financial condition or
operating results could be materially adverse.
The following sections describe material risks identified by the Company; however, risks and uncertainties of which
the Company is not currently aware or currently believes to be immaterial could develop and may adversely affect
the Company’s business, financial condition or operating results. For more information on risk factors which may
affect the Company’s business refer also to the discussion of risks under the “Reserves and Resources” and “Financial
Instruments” sections of this MD&A above, as well as to the “Risk Factors” section of its Annual Information Form,
which is available for viewing both on the Company’s web-site at www.shamaranpetroleum.com and on SEDAR at
www.sedar.com, under the Company’s profile.
Political and Regional Risks
International operations: Oil and gas exploration, development and production activities in emerging countries are
subject to significant political, social and economic uncertainties which are beyond ShaMaran’s control. Uncertainties
include, but are not limited to, the risk of war, terrorism, criminal activity, expropriation, nationalisation,
renegotiation or nullification of existing or future contracts, the imposition of international sanctions, a change in
crude oil or natural gas pricing policies, a change in taxation policies, a limitation on the Company’s ability to export,
and the imposition of currency controls. The materialisation of these uncertainties could adversely affect the
Company’s business including, but not limited to, increased costs associated with planned projects, impairment or
termination of future revenue generating activities, impairment of the value of the Company’s assets and or its ability
to meet its contractual commitments as they become due.
19
Political uncertainty: ShaMaran’s assets and operations are in Kurdistan, a federally recognised semi-autonomous
political region in Iraq, and may be influenced by political developments between Kurdistan and the Iraq federal
government, as well as political developments of neighbouring states within MENA region, Turkey, and surrounding
areas. Kurdistan and Iraq have a history of political and social instability. As a result, the Company is subject to political,
economic and other uncertainties that are not within its control. These uncertainties include, but are not limited to,
changes in government policies and legislation, adverse legislation or determinations or rulings by governmental
authorities and disputes between the Iraq federal government and Kurdistan.
There is a risk that levels of authority of the KRG, and corresponding systems in place, could be transferred to the Iraq
federal government. Changes to the incumbent political regime could result in delays in operations and additional
costs which could materially adversely impact the operations and future prospects of the Company and could have a
material adverse effect on the Company's business and financial condition. Refer also to the discussion in the section
below under “Risks associated with petroleum contracts in Iraq.”
International boundary disputes: Although Kurdistan is recognised by the Iraq constitution as a semi-autonomous
region, its geographical extent is neither defined in the Iraq constitution nor agreed in practice between the Federal
Government and the KRG. There are ongoing differences between the KRG and the Federal Government regarding
certain areas which are commonly known as “disputed territories”. The Company believes that its current area of
operation is not within the “disputed territories”.
Industry and Market Risks
Exploration, development and production risks: ShaMaran’s business is subject to all the risks and hazards inherent
in businesses involved in the exploration, development, production and marketing of oil and natural gas, many of
which cannot be overcome even with a combination of experience, knowledge and careful evaluation. The risks and
hazards typically associated with oil and gas operations include drilling of unsuccessful wells, fire, explosion, blowouts,
sour gas releases, pipeline ruptures and oil spills, each of which could result in substantial damage to oil and natural
gas wells, production facilities, other property or the environment, or in personal injury. The Company is not fully
insured against all of these risks, nor are all such risks insurable and, as a result, these risks could still result in adverse
effects to the Company’s business not fully mitigated by insurance coverage including, but not limited to, increased
costs or losses due to events arising from accidents or other unforeseen outcomes including clean-up, repair,
containment and or evacuation activities, settlement of claims associated with injury to personnel or property, and
or loss of revenue as a result of downtime due to accident.
General market conditions: ShaMaran’s business and operations depend upon conditions prevailing in the oil and
gas industry including the current and anticipated prices of oil and gas and the global economic activity. A reduction
of the oil price, a general economic downturn, or a recession could result in adverse effects to the Company’s
business including, but not limited to, reduced cash flows associated with the Company’s future oil and gas sales.
Worldwide crude oil commodity prices are expected to remain volatile in the near future as a result of global supply
and demand balances, actions taken by the Organization of the Petroleum Exporting Countries ("OPEC"), and ongoing
global credit and liquidity concerns. This volatility may affect the Company's ability to obtain equity or debt financing
on acceptable terms.
Competition: The petroleum industry is intensely competitive in all aspects including the acquisition of oil and gas
interests, the marketing of oil and natural gas, and acquiring or gaining access to necessary drilling and other
equipment and supplies. ShaMaran competes with numerous other companies in the search for and acquisition of
such prospects and in attracting skilled personnel. ShaMaran’s competitors include oil companies which have greater
financial resources, staff and facilities than those of the Company. ShaMaran’s ability to increase reserves in the future
will depend on its ability to develop its present property, to select and acquire suitable producing properties or
prospects on which to conduct future exploration and to respond in a cost-effective manner to economic and
competitive factors that affect the distribution and marketing of oil and natural gas.
Reliance on key personnel: ShaMaran’s success depends in large measure on certain key personnel and directors.
The loss of the services of such key personnel could negatively affect ShaMaran’s ability to deliver projects according
to plan and result in increased costs and delays. ShaMaran has not obtained key person insurance in respect of the
lives of any key personnel. In addition, competition for qualified personnel in the oil and gas industry is intense and
there can be no assurance that ShaMaran will be able to attract and retain the skilled personnel necessary for the
operation and development of its business.
20
Business Risks
Risks associated with petroleum contracts in Iraq: The Iraq oil ministry has historically disputed the validity of the
KRG’s production sharing contracts and, as a result indirectly, the Company’s right and title to its oil and gas assets.
The KRG is disputing the claims and has stated that the contracts are compliant with the Iraq constitution. There is
currently no assurance that production sharing contracts agreed with the KRG are enforceable or binding in
accordance with ShaMaran’s interpretation of their terms or that, if breached, the Company would have remedies.
The Company believes that it has valid title to its oil and gas assets and the right to explore for and produce oil and
gas from such assets under the Atrush PSC. However, should the Iraq federal government pursue and be successful
in a claim that the production sharing contracts agreed with the KRG are invalid, or should any unfavourable changes
develop which impact on the economic and operating terms of the Atrush PSC, it could result in adverse effects
to the Company’s business including, but not limited to, impairing the Company’s claim and title to assets held, and
or increasing the obligations required, under the Atrush PSC.
Government regulations, licenses and permits: The Company is affected by changes in taxes, regulations and other
laws or policies affecting the oil and gas industry generally as well as changes in taxes, regulations and other laws or
policies applicable to oil and gas exploration and development in Kurdistan specifically. The Company’s ability to
execute its projects may be hindered if it cannot secure the necessary approvals or the discretion is exercised in a
manner adverse to the Company. The taxation system applicable to the operating activities of the Company in
Kurdistan is pursuant to the Oil and Gas Law governed by general Kurdistan tax law and the terms of its production
sharing contracts. However, it is possible that the arrangements under the production sharing contracts may be
overridden or negatively affected by the enactment of any future oil and gas or tax law in Iraq or Kurdistan which
could result in adverse effects to the Company’s business including, but not limited to, increasing the Company’s
expected future tax obligations associated with its activities in Kurdistan.
Marketing, markets and transportation: The export of oil and gas and payments relating to such exports from
Kurdistan remains subject to uncertainties which could negatively impact on ShaMaran’s ability to export oil and gas
and receive payments relating to such exports. Potential government regulation relating to price, quotas and other
aspects of the oil and gas business could result in adverse effects to the Company’s business including, but not
limited to, impairing the Company’s ability to export and sell oil and gas and receive full payment for all sales of oil
and gas.
Payments for oil exports: Companies who have exported oil from Kurdistan since the year 2009 have reported
significant amounts outstanding for past oil exports. Cash payments to oil companies for oil exported from Kurdistan
has been under control of the KRG since the beginning of exports in 2009. Since February 1, 2016, when the KRG
announced an interim measure whereby monthly payments to oil companies would be made based on an agreed
mechanism, the KRG has established a relatively consistent record of delivering regular monthly payments to oil
companies for their entitlement revenues in respect of monthly petroleum production, with producers’ most recent
reports indicating having received in February 2019 full payments for November 2018 oil exported. Nevertheless
there remains a risk that the Company may face significant delays in the receipt of cash for its entitlement share of
future oil exports.
Paying interest: On November 7, 2016 the KRG exercised its back-in right under the terms of the Atrush PSC and
acquired a 25% participating interest. Upon the commencement of oil production exports from Atrush the KRG is
required to pay its share of project development costs. There is a risk that the Contractors may be exposed to fund
the KRG share of future project development costs.
Default under the Atrush PSC and Atrush JOA: Should the Company fail to meet its obligations under the Atrush PSC
and or Atrush Block joint operating agreement (“Atrush JOA”) it could result in adverse effects to the Company’s
business including, but not limited to, a default under one or both contracts, the termination of future revenue
generating activities of the Company and impairment of the Company’s ability to meet its contractual commitments
as they become due.
Kurdistan legal system: The Kurdistan Region of Iraq has a less developed legal system than that of many more
established regions. This could result in risks associated with predicting how existing laws, regulations and contractual
obligations will be interpreted, applied or enforced. In addition it could make it more difficult for the Company to
obtain effective legal redress in courts in case of breach of law, regulation or contract and to secure the
implementation of arbitration awards and may give rise to inconsistencies or conflicts among various laws,
regulations, decrees or judgments. The Company’s recourse may be limited in the event of a breach by a government
authority of an agreement governing the Atrush PSC in which ShaMaran acquires or holds an interest.
21
Enforcement of judgments in foreign jurisdictions: The Company is party to contracts with counterparties located in
a number of countries, most notably Kurdistan. Certain of its contracts are subject to English law with legal
proceedings in England. However, the enforcement of any judgments thereunder against a counterparty will be a
matter of the laws of the jurisdictions where counterparties are domiciled.
Change of control in respect of the Atrush PSC: The Atrush PSC definition of “change of control” in a Contractor
includes a change of voting majority in the Contractor, or in a parent company, provided the value of the interest in
the Atrush field represents more than 50% of the market value of assets in the Company. Due to the limited amount
of other assets held by the Company this will apply to a change of control in GEP or any of its parent companies.
Change of control requires the consent of KRG or it will trigger a default under the Atrush PSC.
Project and Operational Risks
Shared ownership and dependency on partners: ShaMaran’s operations are to a significant degree conducted
together with one or more partners through contractual arrangements with the execution of the operations being
undertaken by the Operator in accordance with the terms of the Atrush JOA. As a result, ShaMaran has limited ability
to exercise influence over the deployment of those assets or their associated costs and this could adversely affect
ShaMaran’s financial performance. If the operator or other partners fail to perform, ShaMaran may, among other
things, risk losing rights or revenues or incur additional obligations or costs to itself perform in place of its partners. If
a dispute would arise with one or more partners such dispute may have significant negative effects on the Company’s
operations relating to its projects.
Security risks: Kurdistan and other regions in Iraq have a history of political and social instability which have
culminated in security problems which may put at risk the safety of the Company’s personnel, interfere with the
efficient and effective execution of the Company’s operations and ultimately result in significant losses to the
Company. There have been no significant security incidents in the Company’s area of operation.
Risks relating to infrastructure: The Company is dependent on access to available and functioning infrastructure
(including third party services in Kurdistan) relating to the properties on which it operates, such as roads, power and
water supplies, pipelines and gathering systems. If any infrastructure or systems failures occur or access is not possible
or does not meet the requirements of the Company, the Company’s operations may be significantly hampered which
could result in lower production and sales and or higher costs.
Environmental regulation and liabilities: Drilling for and producing, handling, transporting and disposing of oil and
gas and petroleum by-products are activities that are subject to extensive regulation under national and local
environmental laws, including in those countries in which ShaMaran currently operates. The Company has
implemented health, safety and environment policies since
industry
environmental practices and guidelines for its operations in Kurdistan and is currently in compliance with these
obligations in all material aspects. Environmental protection requirements have not, to date, had a significant effect
on the capital expenditures and competitive position of ShaMaran. Future changes in environmental or health and
safety laws, regulations or community expectations governing the Company’s operations could result in adverse
effects to the Company’s business including, but not limited to, increased monitoring, compliance and remediation
costs and or costs associated with penalties or other sanctions imposed on the Company for non-compliance or
breach of environmental regulations.
incorporation, complies with
its
Risk relating to community relations / labour disruptions: The Company’s operations may be in or near communities
that may regard operations as detrimental to their environmental, economic or social circumstances. Negative
community reactions and any related labour disruptions or disputes could increase operational costs and result in
delays in the execution of projects.
Petroleum costs and cost recovery: Under the terms of the Atrush PSC the KRG is entitled to conduct an audit to
verify the validity of incurred petroleum costs which the Operator has reported to the KRG and is therefore entitled
under the terms of the Atrush PSC to recover through cash payments from future petroleum production. No such
audit yet date taken place. Should any future audits result in negative findings concerning the validity of reported
incurred petroleum costs the Company’s petroleum cost recovery entitlement could ultimately be reduced.
Legal claims and disputes: The Company may suffer unexpected costs or other losses if a counterparty to any
contractual arrangement entered into by the Company does not meet its obligations under such agreements. In
particular, the Company cannot control the actions or omissions of its partners in the Atrush PSC. If such parties were
to breach the terms of the Atrush PSC or any other documents relating to the Company’s interest in the Atrush PSC,
it could cause the KRG to revoke, terminate or adversely amend the Atrush PSC.
22
Uninsured losses and liabilities: Although the Company maintains insurance in accordance with industry standards
to address risks relating to its operations, the insurance coverage may under certain circumstances not protect it from
all potential losses and liabilities that could result from its operations.
Availability of equipment and services: ShaMaran’s oil and natural gas exploration and development activities are
dependent on the availability of third-party services, drilling and related equipment and qualified staff in the areas
where such activities are or will be conducted. Shortages of such equipment or staff may affect the availability of such
equipment to ShaMaran and may delay and or increase the cost of ShaMaran’s exploration and development
activities.
Early stage of production: ShaMaran has conducted oil and gas exploration and development activities in
Kurdistan for approximately nine years. The current operations are in an early production stage and there can be
no assurance that ShaMaran’s operations will be profitable in the future or will generate sufficient cash flow to
satisfy its future commitments.
Financial and Other Risks
Financial statements prepared on a going concern basis: The Company’s financial statements have been prepared
on a going concern basis under which an entity is able to realise its assets and satisfy its liabilities in the ordinary
course of business. Management has made assumptions regarding projected oil sale volumes and pricing, and the
timing and extent of capital, operating, and general and administrative expenditures. Should production be materially
less than anticipated or in case there are extended delays to the forecasted receipt of cash from the sale of oil exports
or in the magnitude of those cash receipts, which are under the control of the KRG, and the Company was unable to
defer certain planned cost activities, the Company could require additional liquidity to fund the forecasted Atrush
operating and development costs and its commitments under the bond agreement in the next 12 months. The
Company’s future operations are dependent upon certain factors the identification and successful completion of
additional equity or debt financing or the achievement of profitable operations. There can be no assurances that the
Company will be successful in completing additional debt or equity financing or achieving profitability. The
consolidated financial statements do not give effect to any adjustments relating to the carrying values and
classification of assets and liabilities that would be necessary should ShaMaran be unable to continue as a going
concern.
Substantial capital requirements: ShaMaran anticipates making substantial capital expenditures in the future for
the acquisition, exploration, development and production of oil and gas. ShaMaran’s results could impact its access
to the capital necessary to undertake or complete future drilling and development programs. To meet its operating
costs and planned capital expenditures, ShaMaran may require financing from external sources, including from the
sale of equity and debt securities. There can be no assurance that such financing will be available to the Company or,
if available, that it will be offered on terms acceptable to ShaMaran. If ShaMaran or any of its partners in the oil asset
are unable to complete minimum work obligations on the Atrush PSC, this PSC could be relinquished under applicable
contract terms.
Dilution: The Company may make future acquisitions or enter into financings or other transactions involving the
issuance of securities of the Company. If additional financing is raised through the issuance of equity or convertible
debt securities, control of the Company may change and the interests of shareholders in the net assets of ShaMaran
may be diluted.
Tax legislation: The Company has entities incorporated and resident for tax purposes in Canada, the Cayman Islands,
the Kurdistan Region of Iraq, the Netherlands, Switzerland and the United States of America. Changes in the tax
legislation or tax practices in these jurisdictions may increase the Company’s expected future tax obligations
associated with its activities in such jurisdictions.
Capital and lending markets: Because of general economic uncertainties and, in particular, the potential lack of risk
capital available to the junior resource sector, the Company, along with other junior resource entities, may have
reduced access to bank debt and to equity. As future capital expenditures will be financed out of funds generated
from operations, bank borrowings if available, and possible issuances of debt or equity securities, the Company’s
ability to do so is dependent on, among other factors, the overall state of lending and capital markets and investor
and lender appetite for investments in the energy industry generally, and the Company’s securities in particular. To
the extent that external sources of capital become limited or unavailable or available only on onerous terms, the
Company’s ability to invest and to maintain existing assets may be impaired, and its assets, liabilities, business,
financial condition and results of operations may be materially and adversely affected as a result.
23
Uncertainty in financial markets: In the future the Company could require financing to grow its business. The
uncertainty which periodically affects financial markets and the possibility that financial institutions may consolidate
or go bankrupt has reduced levels of activity in the credit markets which could diminish the amount of financing
available to companies. The Company’s liquidity and its ability to access the credit or capital markets may also be
adversely affected by changes in the financial markets and the global economy.
Conflict of interests: Certain directors of ShaMaran are also directors or officers of other companies, including oil
and gas companies, the interests of which may, in certain circumstances, come into conflict with those of ShaMaran.
If a conflict arises with respect to a particular transaction, the affected directors must disclose the conflict and abstain
from voting with respect to matters relating to the transaction.
Risks Related to the Company’s Senior Bonds
Possible termination of Atrush PSC / bond agreements in event of default scenario: Should ShaMaran default its
obligations under the bond agreement ShaMaran may also not be able to fulfil its obligations under the Atrush PSC
and or Atrush JOA, with the effect that these contracts may be terminated or limited. In addition, should ShaMaran
default its obligations under the Atrush PSC and or Atrush JOA, with the effect that these contracts may be terminated
or limited, ShaMaran may also default in respect of its obligations under the bond agreement. Either default scenario
could result in the termination of the Company’s future revenue generating activities and impair the Company’s ability
to meet its contractual commitments as they become due.
Ability to service indebtedness: ShaMaran’s ability to make scheduled payments on or to refinance its obligations
under the bond agreement will depend on ShaMaran’s financial and operating performance which, in turn, will be
subject to prevailing economic and competitive conditions beyond ShaMaran’s control. It is possible that ShaMaran’s
activities will not generate sufficient funds to make the required interest payments which could, among other things,
result in an event of default under the bond agreement.
Significant operating and financial restrictions: The terms and conditions of the bond agreement contains restrictions
on ShaMaran’s and the Guarantors’ activities which restrictions may prevent ShaMaran and the Guarantors from
taking actions that it believes would be in the best interest of ShaMaran’s business, and may make it difficult for
ShaMaran to execute its business strategy successfully or compete effectively with companies that are not similarly
restricted. No assurance can be given that it will be granted the necessary waivers or amendments if for any reason
ShaMaran is unable to comply with the terms of the bond agreement. A breach of any of the covenants and
restrictions could result in an event of default under the bond agreement.
Mandatory prepayment events: Under the terms of the bond agreements the bonds are subject to mandatory
prepayment by ShaMaran on the occurrence of certain specified events, including if (i) the ownership in the Atrush
Block is reduced to below 20.10% or (ii) an event of default occurs under the bond agreement. Following an early
redemption after the occurrence of a mandatory prepayment event, it is possible that ShaMaran will not have
sufficient funds to make the required redemption of the bonds which could, among other things, result in an event
of default under the bond agreement.
FORWARD LOOKING INFOMATION
This report contains forward-looking information and forward-looking statements. Forward-looking information
concerns possible events or financial performance that is based on management’s assumptions concerning
anticipated developments in the Company’s operations; the adequacy of the Company’s financial resources; financial
projections, including, but not limited to, estimates of capital and operating costs, production rates, commodity
prices, exchange rates, net present values; and other events and conditions that may occur in the future. Information
concerning the interpretation of drill results and reserve estimates also may be deemed to be forward-looking
information, as it constitutes a prediction of what might be found to be present if a project is actually developed.
Forward-looking statements are statements that are not historical and are frequently, but not always, identified by
the words such as “expects,” “anticipates,” “believes,” “intends,” “estimates,” “potential,” “possible,” “outlook”,
“budget” and similar expressions, or statements that events, conditions or results “will,” “may,” “could,” or “should”
occur or be achieved. Forward-looking statements are statements about the future and are inherently uncertain, and
actual achievements of the Company or other future events or conditions may differ materially from those reflected
in the forward-looking statements due to a variety of risks, uncertainties and other factors, including, without
limitation, those described in this MD&A.
24
The Company’s forward-looking information and forward-looking statements are based on the beliefs, expectations
and opinions of management on the date the statements are made. Management is regularly considering and
evaluating assumptions that will impact on future performance. Those assumptions are exposed to generic risks and
uncertainties as well as risks and uncertainties that are specifically related to the Company’s operations.
The Company cautions readers regarding the reliance placed by them on forward‐looking information as by its nature,
it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and
uncertainties, which could cause actual results to differ materially from those anticipated by the Company.
Except as required by applicable securities legislation the Company assumes no obligation to update its forward-
looking information and forward-looking statements in the future. For the reasons set forth above, investors should
not place undue reliance on forward-looking information and forward-looking statements.
Reserves and resources: 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.
ADDITIONAL INFORMATION
Additional information related to the Company, including its Annual Information Form, is available on SEDAR at
www.sedar.com and on the Company’s web-site at www.shamaranpetroleum.com .
The Company plans to publish on May 8, 2019 its financial statements for the three months ended March 31, 2019.
25
ShaMaran Petroleum Corp.
Audited Consolidated Financial Statements
For the year ended December 31, 2018
26
Independent auditor’s report
To the Shareholders of ShaMaran Petroleum Corp.
Our opinion
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the
financial position of ShaMaran Petroleum Corp. and its subsidiaries, (together, the Company) as at December 31,
2018 and 2017, and its financial performance and its cash flows for the years then ended in accordance with
International Financial Reporting Standards (IFRS).
What we have audited
The Company’s consolidated financial statements comprise:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
the consolidated statement of comprehensive income for the years ended December 31, 2018 and 2017;
the consolidated balance sheet as at December 31, 2018 and 2017;
the consolidated statements of changes in equity for the years then ended;
the consolidated statement of cash flows for the years then ended; and
the notes to the consolidated financial statements, which include a summary of significant accounting
policies.
Basis for opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities
under those standards are further described in the Auditor’s responsibilities for the audit of the consolidated
financial statements section of our report.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our
opinion.
Independence
We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of
the consolidated financial statements in Canada. We have fulfilled our other ethical responsibilities in accordance
with these requirements.
Other information
Management is responsible for the other information. The other information comprises the information, other
than the consolidated financial statements and our auditor’s report thereon, included in or filed on the same
date as the annual report, which includes the Management Discussion & Analysis and Annual Information Form.
PricewaterhouseCoopers SA, Avenue Giuseppe-Motta 50 CH-1211 Genève 2, Switzerland
Telephone: +41 58 792 91 00, Facsimile: +41 58 792 91 10, www.pwc.ch
PricewaterhouseCoopers SA is a member of the global PricewaterhouseCoopers network of firms, each of which is a separate and independent
legal entity.
27 Our opinion on the consolidated financial statements does not cover the other information and we do not and will
not express an opinion or any form of assurance conclusion thereon.
In connection with our audit of the consolidated financial statements, our responsibility is to read the other
information identified above and, in doing so, consider whether the other information is materially inconsistent
with the consolidated financial statements or our knowledge obtained in the audit, or otherwise appears to be
materially misstated.
If, based on the work we have performed on the other information, we conclude that there is a material
misstatement of this other information, we are required to report that fact. We have nothing to report in this
regard.
Responsibilities of management and those charged with governance for the consolidated
financial statements
Management is responsible for the preparation and fair presentation of the consolidated financial statements in
accordance with IFRS, and for such internal control as management determines is necessary to enable the
preparation of consolidated financial statements that are free from material misstatement, whether due to fraud
or error.
In preparing the consolidated financial statements, management is responsible for assessing the Company’s
ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the
going concern basis of accounting unless management either intends to liquidate the Company or to cease
operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company’s financial reporting process.
Auditor’s responsibilities for the audit of the consolidated financial statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole
are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes
our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in
accordance with Canadian generally accepted auditing standards will always detect a material misstatement when
it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the
aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of
these consolidated financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional
judgment and maintain professional skepticism throughout the audit. We also:
(cid:120)
Identify and assess the risks of material misstatement of the consolidated financial statements, whether due
to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence
that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material
misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve
collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
28 (cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
Obtain an understanding of internal control relevant to the audit in order to design audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness
of the Company’s internal control.
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates
and related disclosures made by management.
Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based
on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that
may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a
material uncertainty exists, we are required to draw attention in our auditor’s report to the related
disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our
opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report.
However, future events or conditions may cause the Company to cease to continue as a going concern.
Evaluate the overall presentation, structure and content of the consolidated financial statements, including
the disclosures, and whether the consolidated financial statements represent the underlying transactions
and events in a manner that achieves fair presentation.
Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business
activities within the Company to express an opinion on the consolidated financial statements. We are
responsible for the direction, supervision and performance of the group audit. We remain solely responsible
for our audit opinion.
We communicate with those charged with governance regarding, among other matters, the planned scope and
timing of the audit and significant audit findings, including any significant deficiencies in internal control that we
identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant ethical
requirements regarding independence, and to communicate with them all relationships and other matters that
may reasonably be thought to bear on our independence, and where applicable, related safeguards.
The engagement partner on the audit resulting in this independent auditor’s report is Luc Schulthess.
PricewaterhouseCoopers SA
March 8, 2019
CoCoCoCoColililililinnnn n JoJoJoJoJohnhnhnhnhnsososososonnnnn
Colin Johnson
29 SHAMARAN PETROLEUM CORP.
Consolidated Statement of Comprehensive Income
(Expressed in thousands of United States dollars, except for per share data)
___________________________________________________________________________
Note
For the year ended December 31,
2017
2018
Revenues
Cost of goods sold:
Lifting costs
Other costs of production
Depletion
Gross margin on oil sales
General and administrative expense
Depreciation and amortisation expense
Share based payments expense
Income / (loss) from operating activities
Finance income
Finance cost
Net finance cost
Income / (loss) before income tax expense
Income tax expense
Income / (loss) for the year
Other comprehensive income
Items that may be reclassified to profit or loss:
Currency translation differences
Items that will not be reclassified to profit or loss:
Re-measurements on defined pension plan
Total other comprehensive income
Total comprehensive income / (loss) for the year
6
7
7
7
8
9
10
20
69,600
(12,047)
(1,854)
(28,171)
27,528
(4,564)
(8)
-
22,956
2,091
(23,114)
(21,023)
1,933
(64)
1,869
18
357
375
2,244
17,689
(5,547)
(834)
(7,628)
3,680
(4,511)
(26)
(11)
(868)
1,649
(12,195)
(10,546)
(11,414)
(85)
(11,499)
31
(13)
18
(11,481)
Loss in dollars per share:
Basic and diluted
-
(0.01)
The accompanying Notes are an integral part of these consolidated financial statements.
30
SHAMARAN PETROLEUM CORP.
Consolidated Balance Sheet
(Expressed in thousands of United States dollars)
___________________________________________________________________________
Note
As at December 31,
2018
2017
Assets
Non-current assets
Property, plant and equipment
Intangible assets
Loans and receivables
Current assets
Cash and cash equivalents, restricted
Cash and cash equivalents, unrestricted
Loans and receivables
Other current assets
Total assets
Liabilities and equity
Current liabilities
Accrued interest expense on bonds
Accounts payable and accrued expenses
Current tax liabilities
Borrowings
Non-current liabilities
Borrowings
Provisions
Pension liability
Total liabilities
Equity
Share capital
Share based payments reserve
Cumulative translation adjustment
Accumulated deficit
Total equity
Total liabilities and equity
11
12
13
16
13
14
16
15
16
16
17
20
18
195,908
67,829
25,184
288,921
67,884
24,586
36,099
2,286
130,855
419,776
14,080
3,875
16
-
17,971
236,717
9,559
1,330
247,606
265,577
637,538
6,495
(12)
(489,822)
154,199
419,776
184,921
89,119
44,696
318,736
2,162
3,094
32,277
212
37,745
356,481
2,799
4,827
-
185,692
193,318
-
9,427
1,781
11,208
204,526
637,538
6,495
(30)
(492,048)
151,955
356,481
The accompanying Notes are an integral part of these consolidated financial statements.
Signed on behalf of the Board of Directors:
/s/Terry Allen
Terry L. Allen, Director
/s/Keith Hill
Keith C. Hill, Director
31
SHAMARAN PETROLEUM CORP.
Consolidated Statement of Changes in Equity
(Expressed in thousands of United States dollars)
______________________________________________________________________________
Share based
payments
reserve
Share
capital
Cumulative
translation
adjustment
Accumulated
deficit
Note
Total
Balance at January 1, 2017
611,179
6,484
(61)
(480,536)
137,066
Total comprehensive loss for the year:
Loss for the year
Other comprehensive income / (loss)
Transactions with owners in their capacity as owners:
Share based payments expense
Shares issued on private placement
Transaction costs
18
18
-
-
-
-
27,281
(922)
26,359
-
-
-
11
-
-
11
-
31
31
-
-
-
-
(11,499)
(13)
(11,512)
(11,499)
18
(11,481)
-
-
-
-
11
27,281
(922)
26,370
Balance at December 31, 2017
637,538
6,495
(30)
(492,048)
151,955
Total comprehensive income for the year:
Income for the year
Other comprehensive income
-
-
-
-
-
-
-
18
18
1,869
357
2,226
1,869
375
2,244
Balance at December 31, 2018
637,538
6,495
(12)
(489,822)
154,199
The accompanying Notes are an integral part of these consolidated financial statements.
32
SHAMARAN PETROLEUM CORP.
Consolidated Statement of Cash Flows
(Expressed in thousands of United States dollars)
___________________________________________________________________________
Note
For the year ended December 31,
2017
2018
Operating activities
Income / (loss) for the year
Adjustments for:
Depreciation, depletion and amortisation expense
Borrowing costs – net of amount capitalised
Re-measurements on defined pension plan
Foreign exchange loss
Unwinding discount on decommissioning provision
Share based payments expense
Interest income
Changes in current tax liabilities
Changes in pension liability
Changes in accounts receivables on Atrush oil sales
Changes in accounts payable and accrued expenses
Changes in other current assets
Net cash inflows from / (outflows to) operating activities
Investing activities
Loans and receivables – payments received
Interest received on cash deposits
Loans and receivables – payments issued
Purchases of intangible assets
Purchase of property, plant and equipment
Net cash inflows from / (outflows to) investing activities
Financing activities
Net proceeds received on bonds issued
Proceeds from shares issued
Share issue related transaction costs
Payments to bondholders - interest and call premiums
Cash paid out on bonds retired
Net cash inflows from financing activities
9
8
8
16
16
16
Effect of exchange rate changes on cash and cash equivalents
Change in cash and cash equivalents
Cash and cash equivalents, beginning of the year
Cash and cash equivalents, end of the year*
*Inclusive of restricted cash
16
1,869
28,179
23,084
357
26
5
-
(2,091)
16
(438)
(574)
(952)
(2,074)
47,407
18,029
720
(394)
(632)
(12,259)
5,464
100,376
-
-
(15,575)
(50,437)
34,364
(21)
87,214
5,256
92,470
67,884
The accompanying Notes are an integral part of these consolidated financial statements.
(11,499)
7,654
12,089
(13)
102
4
11
(1,649)
-
37
(13,957)
(1,607)
12
(8,816)
2,806
107
(10,914)
(82)
(8,621)
(16,704)
-
27,281
(922)
-
-
26,359
1
840
4,416
5,256
2,162
33
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
1. General information
ShaMaran Petroleum Corp. (“ShaMaran” and together with its subsidiaries the “Company”) is incorporated under the
Business Corporations Act, British Columbia, Canada. The address of the registered office is 25th Floor, 666 Burrard
Street, Vancouver, British Columbia V6C 2X8. The Company’s shares trade on the TSX Venture Exchange and NASDAQ
Stockholm First North Exchange (Sweden) under the symbol “SNM”.
The Company is engaged in the business of oil and gas exploration and development and is currently in the first phase
of the development program in respect of the Atrush Block production sharing contract (“Atrush PSC”) related to a
petroleum property located in the Kurdistan Region of Iraq (“Kurdistan”). Oil production on the Atrush Block
commenced on July 3, 2017.
2. Basis of preparation and going concern
a. Basis of preparation
These consolidated financial statements have been prepared in accordance with International Financial Reporting
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and the IFRS Interpretations
Committee that are effective beginning on January 1, 2018, under the historical cost convention. The significant
accounting policies of the Company have been applied consistently throughout the year. The policies applied in these
consolidated financial statements are based on IFRS which were outstanding and effective as of March 7, 2019, the
date these consolidated financial statements were approved and authorised for issuance by the Company’s board of
directors (“the Board”).
b. Going concern
These consolidated financial statements have been prepared on the going concern basis which assumes that the
Company will be able to realise its assets and liabilities in the normal course of business as they come due in the
foreseeable future.
3. Significant accounting policies
(a) Basis of consolidation
The consolidated financial statements incorporate the financial statements of the Company and its subsidiaries,
entities controlled by the Company which apply accounting policies consistent with those of the Company. Control is
achieved where the Company has the power to govern the financial and operating policies of an investee entity to
obtain benefits from its activities. Subsidiaries are fully consolidated from the date on which control is obtained by
the Company and are de-consolidated from the date that control ceases.
Intercompany balances and unrealised gains and losses on intercompany transactions are eliminated upon
consolidation.
34
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
(b)
Interest in joint operations
A joint operation is a contractual arrangement whereby the Company and other parties undertake an economic
activity that is subject to joint control.
Where the Company undertakes its activities under joint operation arrangements directly, the Company’s share of
jointly controlled operations and any liabilities incurred jointly with other joint operations are recognised in the
financial statements of the relevant company and classified according to their nature.
Liabilities and expenses incurred directly in respect of interests in jointly controlled operations are accounted for on
an accrual basis. Income from the sale or use of the Company’s share of the output of jointly controlled operations
and its share of the joint operations are recognised when it is probable that the economic benefit associated with the
transactions will flow to/from the Company and the amount can be reliably measured.
(c) Business combinations
The acquisition method of accounting is used to account for business combinations. The consideration transferred is
measured at the aggregate of the fair values at the date of acquisition of assets given, liabilities incurred or assumed
and equity instruments issued by the Company in exchange for control of the acquiree. Acquisition related costs are
expensed as incurred. The identifiable assets, liabilities and contingent liabilities that meet the conditions for
recognition under IFRS 3 Business Combinations are recognised at their fair value at the acquisition date.
If the Company acquires control of an entity in more than one transaction the related investment held by the Company
immediately before the last transaction when control is acquired is considered sold and immediately repurchased at
the fair value of the investment on the date of acquisition. Any difference between the fair value and the carrying
amount of the investment results in income or loss recognised in the statement of comprehensive income.
(d) Foreign currency translation
Functional and presentation currency
Items included in the financial statements of each of the Company’s subsidiaries are measured using the currency of
the primary economic environment in which the subsidiary operates (the “functional currency”). The functional and
presentation currency of the Company is the United States dollar (“USD”).
The results and financial position of subsidiaries that have a functional currency different from the presentation
currency are translated into the presentation currency as follows:
▪ Assets and liabilities are translated at the closing exchange rate at the date of that balance sheet.
▪
Income and expenses are translated at the average exchange rate for the period in which they were incurred as a
reasonable approximation of the cumulative effect of rates prevailing on transaction dates.
▪ All resulting exchange differences are recognised in other comprehensive income as part of the cumulative
translation reserve.
Transactions and balances
Transactions in currencies other than the functional currency are recorded in the functional currency at the exchange
rates prevailing on the dates of the transactions or valuation where items are re-measured. At each balance sheet
date, monetary assets and liabilities that are denominated in foreign currencies are translated at the rates prevailing
at the balance sheet date. Exchange differences are recognised in the statement of comprehensive income during the
period in which they arise.
35
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
(e) Exploration and evaluation costs and other intangible assets
Exploration and evaluation assets
The Company applies the full cost method of accounting for exploration and evaluation (“E&E”) costs in accordance
with the requirements of IFRS 6 Exploration for and Evaluation of Mineral Resources. All costs of exploring and
evaluating oil and gas properties are accumulated and capitalised to the relevant property contract area and are
tested on a cost pool basis as described below.
Pre-license costs:
Costs incurred prior to having obtained the legal rights to explore an area are expensed directly to the statement of
comprehensive income.
Exploration and evaluation costs:
All E&E costs are initially capitalised as E&E assets and include payments to acquire the legal right to explore, costs of
technical services and studies, seismic acquisition, exploratory drilling and testing.
Tangible assets used in E&E activities such as the Company’s vehicles, drilling rigs, seismic equipment and other
property, plant and equipment (“PP&E”) used by the Company’s exploration function are classified as PP&E. To the
extent that such tangible assets are consumed in exploring and evaluating a property the amount reflecting that
consumption is recorded as part of the cost of the intangible asset. Such intangible costs include directly attributable
overhead including the depreciation of PP&E utilised in E&E activities together with the cost of other materials
consumed during the E&E phases such as tubulars and wellheads.
E&E costs are not depreciated prior to the commencement of commercial production.
Treatment of E&E assets at conclusion of appraisal activities:
E&E assets are carried forward until commercial viability has been established for a contractual area which normally
coincides with the commencement of commercial production. The E&E assets are then assessed for impairment and
the carrying value after any impairment loss is then reclassified as oil and gas assets within PP&E. Until commercial
viability has been established E&E assets remain capitalised at cost and are subject to the impairment test set out
below.
Other intangible assets
Other intangible assets are carried at measured cost less accumulated amortisation and any recognised impairment
loss and are amortised on a straight-line basis over their expected useful economic lives as follows:
▪ Computer software and associated costs
3 years
(f) Property, plant and equipment
Oil and gas assets
Oil and gas assets comprise of development and production costs for areas where technical feasibility and commercial
viability have been established and include any E&E assets transferred after conclusion of appraisal activities as well
as costs of development drilling, completion, gathering and production infrastructure, directly attributable overheads,
borrowing costs capitalised and the cost of recognising provisions for future restoration and decommissioning. Oil
and gas costs are accumulated separately for each contract area.
Depletion of oil and gas assets:
Oil and gas assets are depleted using the unit of production method based on proved and probable reserves using
estimated future prices and costs and accounting for future development expenditures necessary to bring those
reserves into production. The reserves correspond to the Company’s entitlement to oil under the terms of the PSC.
Changes to depletion rates due to changes in reserve quantities and estimates of future development expenditure
are reflected prospectively.
36
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Other property, plant and equipment
Other property, plant and equipment include expenditures that are directly attributable to the acquisition of an asset.
Subsequent costs are included in the assets’ carrying value or recognised as a separate asset as appropriate only when
it is probable that future economic benefits associated with the item will flow to the Company and the cost can be
measured reliably.
Repairs and maintenance costs are charged to the statement of comprehensive income during the period in which
they are incurred.
The carrying amount of an item of PP&E is derecognised on disposal or when no future economic benefits are
expected from its use or disposal. The gain or loss arising on the disposal or retirement of an asset is determined as
the difference between the sales proceeds and the carrying amount of the asset and is recognised in the statement
of comprehensive income during the period.
Other property, plant and equipment assets are carried at cost less accumulated depreciation and any recognised
impairment loss and are depreciated on a straight-line basis over their expected useful economic lives as follows:
▪ Furniture and office equipment
▪ Computer equipment
5 years
3 years
(g)
Impairment of non-financial assets
E&E assets and oil and gas assets are assessed for impairment when facts and circumstances suggest that the carrying
amount may exceed its recoverable amount. Such indicators include:
▪ The period for which the Company has the right to explore in the specific area has expired during the period or
will expire in the near future and is not expected to be renewed.
▪ Substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is
neither budgeted nor planned.
▪ Exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable
quantities of mineral resources and the Company has decided to discontinue such activities in the specific area.
▪ Sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying
amount of either of the E&E or the oil and gas assets is unlikely to be recovered in full from successful development
or by sale.
▪ Extended decreases in prices or margins for oil and gas commodities or products.
▪ A significant downwards revision in estimated volumes or an upward revision in future development costs.
For impairment testing the assets are aggregated into cash generating unit (“CGU”) cost pools based on their ability
to generate largely independent cash flows. The recoverable amount of a CGU is the greater of its fair value less costs
to sell and its value in use. Fair value is determined to be the amount for which the asset could be sold in an arm’s
length transaction. Value in use is determined by estimating the present value of the future net cash flows expected
to be derived from the continued use of the asset or CGU.
Where conditions giving rise to the impairment subsequently reverse the effect of the impairment charge is also
reversed as a credit to the statement of comprehensive income net of any depreciation that would have been charged
since the impairment.
(h) Financial instruments
Financial assets and liabilities are recognised in the Company’s balance sheet when the Company becomes a party to
the contractual provisions of the instrument. Financial assets are derecognised when the contractual rights to cash
flows from the assets expire or the Company transfers the financial asset and substantially all the risks and rewards
of ownership. The Company derecognises financial liabilities when the Company’s obligations are discharged,
cancelled or expire.
37
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Classification and measurement
The Company classifies its financial assets and liabilities at initial recognition in the following categories:
▪ Financial assets and liabilities at fair value through profit or loss are those assets and liabilities acquired principally
for selling or repurchasing in the short-term and are recognised at fair value. Transaction costs are expensed in
the statement of comprehensive income and gains or losses arising from changes in fair value are also presented
in the statement of comprehensive income within other gains and losses in the period in which they arise. Financial
assets and liabilities at fair value through profit or loss are classified as current except for the portion expected to
be realised or paid beyond twelve months of the balance sheet date, which is classified as non-current.
▪ Financial assets carried at amortised cost comprise of loans, receivables and cash and cash equivalents with fixed
or determinable payments that are not quoted on an active market and are generally included within current
assets due to their short-term nature and are classified as financial assets when the Company has a right to cash
collection. If collection of the amounts is expected in one year or less they are classified as current assets. If not,
they are presented as non-current assets. Loans and receivables are initially recognised at fair value and are
subsequently measured at amortised cost using the effective interest method less any provision for impairment.
▪ Financial liabilities at amortised cost comprise of trade and other payables and are initially recognised at the fair
value of the amount expected to be paid and are subsequently measured at amortised cost using the effective
interest rate method. Financial liabilities are classified as current liabilities unless the Company has an
unconditional right to defer settlement for at least 12 months after the balance sheet date.
(i) Cash and cash equivalents
Cash and cash equivalents are comprised of cash on hand and demand deposits and other short-term liquid
investments that are readily convertible to a known amount of cash within three months or less from the acquisition
date. Restricted cash is cash held in a trust account for a specific purpose and is therefore not available for general
business use. Additional disclosure related to the Company’s restricted cash is included in Note 16.
(j) Borrowings
Borrowings are recognised initially at fair value, net of any transaction costs incurred. Borrowings are subsequently
carried at amortised cost using the effective interest rate method.
General and specific borrowing costs directly attributable to the acquisition or construction of qualifying assets are
capitalised together with the qualifying assets. Once a qualified asset is fully prepared for its intended use and is
producing borrowing costs are no longer capitalised. All other borrowing costs are recognised in profit or loss in the
period in which they are incurred.
(k) Taxation
The income tax expense comprises current income tax and deferred income tax.
The current income tax is the expected tax payable on the taxable income for the period. It is calculated based on the
tax laws enacted or substantively enacted at the balance sheet date and includes any adjustment to tax payable in
respect of previous years.
Deferred income tax is the tax recognised in respect of temporary differences between the carrying amounts of assets
and liabilities in the financial statements and the corresponding tax bases and is accounted for using the balance sheet
liability method. Deferred income tax liabilities are generally recognised for all taxable temporary differences and
deferred income tax assets are recognised to the extent that it is probable that taxable profits will be available against
which deductible temporary differences can be utilised. Deferred income tax is not recorded if it arises from the initial
recognition of an asset or liability in a transaction other than a business combination that, at the time of the
transaction, affects neither the accounting profit nor loss.
Deferred income tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries
and associates and interests in joint ventures except where the Company can control the reversal of the temporary
difference and it is probable that the temporary difference will not reverse in the foreseeable future.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it
is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.
38
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Deferred income tax is calculated at the tax rates that are expected to apply in the year when the deferred tax liability
is settled or the asset is realised. Deferred tax is charged or credited in the statement of comprehensive income except
when it relates to items charged or credited directly to equity in which case the deferred tax is also recognised directly
in equity. Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax
assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and
the Company intends to settle its current tax assets and liabilities on a net basis.
Income tax arising from the Company’s activities under production sharing contracts is settled by the KRG at no cost
and on behalf of the Company. However, the Company is not able to measure with sufficient accuracy the tax that
has been paid on its behalf and consequently revenue is not reported gross of income tax paid.
(l) Provisions
Provisions are recognised when the Company has a present obligation, legal or constructive, due to a past event when
it is probable that the Company will be required to settle the obligation and a reliable estimate can be made of the
obligation.
The amount recognised as a provision is the best estimate of the consideration required to settle the present
obligation at the balance sheet date, accounting for the risks and uncertainties surrounding the obligation. When a
provision is measured using the cash flow estimates to settle the present obligation its carrying amount is the present
value of those cash flows.
Decommissioning and site restoration
Provisions for decommissioning and site restoration are recognised when the Company has a present legal or
constructive obligation to dismantle and remove production, storage and transportation facilities and to carry out site
restoration work. The provision is calculated as the net present value of the Company’s share of the expenditure
expected to be incurred at the end of the producing life of each field using a discount rate that reflects the market
assessment of the time value of money at that date. Unwinding of the discount on the provision is charged to the
statement of comprehensive income within finance costs during the period. The amount recognised as the provision
is included as part of the cost of the relevant asset and is charged to the statement of comprehensive income in
accordance with the Company’s policy for depreciation and amortisation.
Changes in the estimated timing of decommissioning and site restoration cost estimates are dealt with prospectively
by recording an adjustment to the provision and a corresponding adjustment to the relevant asset.
(m) Pension obligations
The Company’s Swiss subsidiary, ShaMaran Services SA, has a defined benefit pension plan that is managed through
a private pension plan. Independent actuaries determine the cost of the defined benefit plan on an annual basis, and
ShaMaran Services SA pays the annual insurance premium. The pension plan provides benefits coverage to the
employees of ShaMaran Services SA in the event of retirement, death or disability. ShaMaran Services SA and its
employees jointly finance retirement and risk benefits. Employees of ShaMaran Services SA pay 40% of the savings
contributions, of the risk contributions and of the cost contributions and ShaMaran Services SA contributes the
difference between the total of all required pension plan contributions and the total of all employees’ contributions.
(n) Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issue of new shares or share
options are shown in equity as a deduction, net of tax, from the proceeds.
(o) Share-based payments
The Company issues equity-settled share-based payments to certain directors, employees and third parties. The fair
value of the equity settled share-based payments is measured at the date of grant. The total expense is recognised
over vesting period, which is the period over which all conditions to entitlement are to be satisfied. The cumulative
expense recognised for equity-settled share-based payments at each balance sheet date represents the Company’s
best estimate of the number of equity instruments that will ultimately vest. The charge or credit for the period and
the corresponding adjustment to contributed surplus during the period represents the movement in the cumulative
expense recognised for all equity instruments expected to vest. The fair value of equity-settled share-based payments
is determined using the Black-Scholes option pricing model.
39
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
(p) Revenue recognition
Sales of oil Production:
Revenue for sales of oil is recognised when the significant risks and rewards of ownership are deemed to have been
transferred to the KRG, the amount can be measured reliably and it is assessed as probable that economic benefit
associated with the sale will flow to the Company. This occurs when oil reaches the delivery point at the Atrush Block
boundary in route to the KRG’s main export pipeline.
Revenue is recognised at fair value which is comprised of the Company’s entitlement production due under the terms
of the Atrush Joint Operating Agreement and the Atrush PSC which has two principal components: cost oil, which is
the mechanism by which the Company recovers qualifying costs it has incurred in exploring and developing an asset,
and profit oil, which is the mechanism through which profits are shared between the Company, its partners and the
KRG. The Company pays capacity building payments on profit oil, which are due for payment once the Company has
received the related profit oil proceeds. Profit oil revenue is reported net of any related capacity building payments.
The Company’s oil sales are made to the KRG under the terms of a sales agreement which allows for Atrush oil volumes
to be sold to the KRG at the Atrush Block boundary at a discount to the Dated Brent oil price for estimated oil quality
adjustments and all local and international transportation costs.
Interest income:
Interest income is recognised when it is probable that the economic benefits associated with the transaction will flow
to the entity and the amount of the income can be measured reliably. Interest income is recognised using the effective
interest method. The effective interest rate exactly discounts estimated future cash payments or receipts through the
expected life of the financial instrument or, when appropriate, a shorter period to the net carrying amount of the
financial asset or financial liability.
(q) Changes in accounting policies
i. IFRS 15, Revenue from Contracts with Customers
The Company adopted IFRS 15 effective January 1, 2018 and applied it on a retrospective basis. The application of
IFRS 15 has not resulted in any differences between the previous carrying amounts and the carrying amounts at the
date of initial application of IFRS 15.
Revenue from Contracts with Customers is recognized when a customer obtains control of the promised asset and
the Company satisfies its performance obligation. Revenue is allocated to each performance obligation. The Company
considers the terms of the contract in determining the transaction price. The transaction price is based upon the
amount the entity expects to be entitled to in exchange for the transferring of promised goods. The Company earns
revenue from oil sales made to the KRG under the sales agreement between the KRG and the Atrush joint venture
partners.
The Company satisfies its performance obligations for its oil sales based upon specified sales agreement terms which
are that Atrush oil volumes are sold to the KRG at the Atrush Block boundary at a discount to the Dated Brent oil price
for estimated oil quality adjustments and all local and international transportation costs. Revenue from oil sales is
recorded based on the sales agreement terms at the time the oil is delivered to the Atrush Block boundary. The
Company typically receives payment within three months of delivery.
The Company has assessed the impact of IFRS 15 – Revenue from Contracts with Customers. IFRS 15 requires a 5-step
approach, which is definition of the customer, performance obligations, price, allocation of price into performance
obligations and recognising the revenue when the conditions are met. The Company’s single performance obligation
in its contract with its customer is the delivery of crude oil at a pre-determined netback adjustment to Dated Brent
and the control is transferred to the buyer at the metering point when the revenue is recognised. Therefore, there is
no material impact related to the adoption of IFRS 15.
ii. IFRS 9, Financial Instruments
The Company adopted IFRS 9 effective January 1, 2018 and applied it on a retrospective basis. The application of IFRS
9 has not resulted in any differences between the previous carrying amounts and the carrying amounts at the date of
initial application of IFRS 9.
40
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Financial instruments are recognized on the consolidated balance sheet on the trade date, the date on which the
Company becomes a party to the contractual provisions of the financial instrument. The Company classifies its
financial instruments in the following categories:
Financial Assets at Amortized Cost – Assets that are held for collection of contractual cash flows where those cash
flows represent solely payments of principal and interest are measured at amortized cost. This includes the Company’s
loans and receivables which consist of fixed or determined cash flows related solely to principal and interest amounts
or contractual sales of oil. The Company’s intent is to hold these receivables until cash flows are collected. Financial
assets at amortised cost are recognized initially at fair value, net of any transaction costs incurred and subsequently
measured at amortized cost using the effective interest method. The Company recognizes a loss allowance for any
expected credit losses on a financial asset that is measured at amortized cost.
Financial Assets at Fair Value through Profit or Loss (“FVTPL”) – Financial assets measured at FVTPL are assets which
do not qualify as financial assets at amortized cost or at fair value through other comprehensive income. The Company
does not currently have any financial assets measured at FVTPL.
Financial Liabilities at Amortized Cost – Financial liabilities are measured at amortized cost using the effective interest
method, unless they are required to be measured at FVTPL, or the Company has opted to measure them at FVTPL.
Borrowings and accounts payable are recognized initially at fair value, net of any transaction costs incurred, and
subsequently at amortized cost using the effective interest method.
Financial Liabilities at FVTPL – Financial liabilities measured at FVTPL are liabilities which include embedded
derivatives and cannot be classified as amortized cost. The Company does not currently have any financial liabilities
measured at FVTPL.
The Company derecognizes financial assets only when the contractual rights to cash flows from the financial assets
expire, or when it transfers the financial assets and substantially all the associated risks and rewards of ownership.
Gains and losses on derecognition are generally recognized in the consolidated statement of income.
The Company derecognizes financial liabilities only when its obligations under the financial liabilities are discharged,
cancelled or expelled. The difference between the carrying amount of the financial liability derecognized and the
consideration paid and payable, including any non‐cash assets transferred or liabilities assumed, is recognized in the
consolidated statement of income.
Impairment of financial assets
IFRS 9 also introduces a new model for the measurement of impairment of financial assets based on expected credit
losses which replaces the incurred losses impairment model applied under IAS 39. Under this new model, the
Company’s loans and receivables are considered collectible as in line with agreements relating to the Company’s
interest in the Atrush Block oil and gas asset; therefore, these financial assets are not considered to have a significant
financing component and a lifetime expected credit loss (“ECL”) is measured at the date of initial recognition of the
loans and receivables. ECL allowances have not been recognized for cash and cash equivalents and deposits due to
the virtual certainty associated with their collectability. The Company’s loans and receivables are subject to the
expected credit loss model under IFRS 9. For its loans and receivables, the Company applies the simplified approach
to providing for expected credit losses prescribed by IFRS 9, which requires the use of the lifetime expected loss
provision for all trade receivables. In estimating the lifetime expected loss provision, the Company considered
historical industry default rates as well as the history of its customer. There were no material adjustments to the
carrying value of any of the Company’s financial instruments following the adoption of IFRS 9. Additional disclosure
related to the Company’s financial assets is included in Note 13.
Other standards, amendments, and interpretations, which are effective for the financial year beginning on January 1,
2018, have been assessed and do not have a material impact to the Company.
(r) Accounting standards issued but not yet applied
New accounting standards which will come into effect for annual periods beginning on or after January 1, 2019 are
discussed below.
IFRS 16: Leases will replace IAS 17 Leases and requires assets and liabilities arising from all leases, with some
exceptions, to be recognized on the balance sheet. The new standard will be effective for annual periods beginning
on or after January 1, 2019. The Company currently has no outstanding leases.
41
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
There are no other standards that are not yet effective and that would be expected to have a material impact on the
entity in the current or future reporting periods and on foreseeable future transactions
4.
Critical accounting judgments and key sources of estimation uncertainty
In the application of the Company’s accounting policies, which are described in Note 3, management has made
judgments, estimates and assumptions about the carrying amounts of the assets, liabilities, revenues, expenses and
related disclosures. These estimates and associated assumptions are based on historical experience, current trends
and other factors that management believes to be relevant at the time these consolidated financial statements were
prepared. Actual results may differ as future events and their effects cannot be determined with certainty and such
differences could be material. Management reviews the accounting policies, underlying assumptions, estimates and
judgments on an on-going basis to ensure that the financial statements are presented fairly in accordance with IFRS.
The following are the critical judgments and estimates that management has made in the process of applying the
Company’s accounting policies in these consolidated financial statements:
(a) Revenue Recognition
As explained in Note 3(p) the Company recognises revenues when oil reaches the delivery point at the Atrush Block
boundary on the basis that control is deemed to have passed to the buyer and that the transaction price has been
agreed upon. The conclusion that the economic benefits will flow to the Company at this point is based on
management’s evaluation of the reliability of the KRG’s payments to the international oil companies operating in
Kurdistan in exchange for their oil deliveries. Since the KRG’s announcement in February 2016 of its intention to apply
the PSC terms Kurdistan oil exporters have reported regular payments for Kurdish oil sales. Payments commenced in
October 2017 for the Company’s share of Atrush oil sales and have continued each month thereafter.
(b) Oil and gas reserves and resources
The business of the Company is the exploration and development of oil and gas reserves in Kurdistan. Estimates of
commercial oil and gas reserves are used in the calculations for impairment, depreciation and amortisation and
decommissioning provisions. Changes in estimates of oil and gas reserves resulting in different future production
profiles will affect the discounted cash flows used for impairment purposes, the anticipated date of site
decommissioning and restoration and the depreciation charges based on the unit of production method.
In February 2019 the Company received an independent reserves and resources report from McDaniel & Associates
Consultants Ltd. (“McDaniel”) which estimates the Proven plus Probable Gross Oil Reserves for the Atrush Block as of
December 31, 2018, after accounting for Atrush 2018 production have increased by 11%, from 102.7 million barrels
of oil (“MMbbls”) at the end of 2017 to 106 MMbbls at the end of 2018. McDaniel’s estimate of contingent resources
has decreased from 296 MMbbls at the end of 2017 to 268 MMbbls at the end of 2018, due principally to the
reclassification of contingent resources to reserves during the year.
(c) Loans and receivables
The Company has reported loans and receivables of $61.2 million comprised of the Company’s share of Atrush oil
sales and loans made to the KRG relating to its share of Atrush exploration, development and Feeder Pipeline costs.
The current portion of loans is based on a contractual repayment schedule which commenced in the fourth quarter
of 2017. The recovery of these amounts depends on several factors, including: the continued production and exports
of petroleum from the Atrush Block; oil price, and; the financial environment in Kurdistan and the financial budget of
the KRG. Since February 1, 2016, when the KRG announced an interim measure whereby monthly payments to IOCs
would be made based on an agreed mechanism, the KRG has established a consistent record of delivering regular
monthly payments to IOCs for their entitlement revenues in respect of monthly petroleum production.
In the year 2019 up to the date these financial statements were approved the Company received a total of $14 million
in payments relating to the loans and receivables balances outstanding at December 31, 2018. Under the terms of the
relevant agreements the loans and receivable balances are recoverable in several ways including by cash settlement
and or through payment in kind of petroleum production.
Refer also to Note 13.
42
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
(d)
Impairment of assets
IAS 36 Impairment of Assets and IFRS 6 Exploration of and Evaluation of Mineral Resources require that a review for
impairment be carried out if events or changes in circumstances indicate that the carrying amount of an asset may
not be recoverable. As described in Notes 3(g) and 3(h) management has considered whether there is any objective
evidence to indicate that the carrying value of any of its Atrush related assets as at the balance sheet date were
impaired and has concluded that facts and circumstances do not suggest that the carrying amount exceeds its
recoverable amount. In reaching its conclusion management has considered a number of factors which could impact
the ability of the assets to generate future cash flows including the following key items:
• Reserves: there has been an increase, taking into account 2018 production, in the Company’s share of the
latest estimated proved and probable reserves for Atrush and the related production curve estimates as
determined by McDaniel.
•
• NPV calculations: the net present value of the Company’s share of 2P reserves, as determined by McDaniel
and based on a forecasted Brent oil price, supports the book value of oil and gas assets included in property
plant and equipment.
Costs per barrel: the forecasted costs per barrel required to recover the Atrush oil reserves have remained
consistent to last year;
Cash collection: the collectability of cash for future sales of Atrush oil which has remained stable since
production commenced.
•
• Market: there continues to be an active market and capacity for Atrush oil sales as demonstrated by the
•
current and future expected levels of oil exports from Kurdistan.
Independent valuations: the average fair value of the Atrush asset as published by independent market
brokers, Pareto Securities AB and SpareBank 1, support the carrying values of the Atrush oil and gas assets.
Refer also to Notes 11, 12 and 13.
(e) Decommissioning and site restoration provisions
The Company recognises a provision for decommissioning and site restoration costs expected to be incurred to
remove and dismantle production, storage and transportation facilities and to carry out site restoration work. The
provisions are estimated taking into consideration existing technology and current prices after adjusting for expected
inflation and discounted using rates reflecting current market assessments of the time value of money and where
appropriate, the risks specific to the liability. The Company makes an estimate based on its experience and historical
data. Refer also to Note 17.
5.
Business and geographical segments
The Company operates in one business segment, the exploration and development of oil and gas assets, in one
geographical segment, Kurdistan. As a result, in accordance with IFRS 8 Operating Segments, the Company has
presented its financial information collectively for one operating segment.
6. Revenues
Revenues relate entirely to the Company’s entitlement share of oil from Atrush sold to the KRG during the year.
Production from the Atrush field was delivered to the KRG’s Feeder Pipeline at the Atrush block boundary for onward
export through Ceyhan, Turkey. Gross exported oil volumes from Atrush in 2018 were 8.1MMbbls (2017: 3.3MMbbls)
and the Company’s entitlement share was approximately 1.3MMbbls (2017: 0.4MMbbls) which were sold with an
average netback price of $54.52 per barrel (2017: $44.38). ShaMaran’s oil entitlement share is based on PSC terms
covering allocation of profit oil and cost oil, capacity building bonuses owed to the KRG and a priority arrangement
for sharing initial exploration cost oil and on export prices. Export prices are based on Dated Brent oil price with a
discount for estimated oil quality adjustments and all local and international transportation costs.
Refer also to Note 13.
43
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
7.
Cost of goods sold
Lifting costs are comprised of the Company’s share of expenses related to the production of oil from the Atrush Block
including operation and maintenance of wells and production facilities, insurances, and the operator’s related support
costs. Other costs of production include the Company’s share of production bonuses paid to the KRG and its share of
other costs prescribed under the Atrush PSC.
Oil and gas assets are depleted using the unit of production method based on proved and probable reserves using
estimated future prices and costs and accounting for future development expenditures necessary to bring those
reserves into production.
8.
Finance income
Interest on Atrush Development Cost Loan
Interest on Atrush Feeder Pipeline Cost Loan
Interest on deposits
Total finance income
For the year ended December 31,
2017
2018
836
535
720
2,091
1,042
500
107
1,649
Refer to Note 13 for further information on interest on the Atrush Development Cost Loan and the Feeder Pipeline
Cost Loan. Interest on deposits represents bank interest earned on cash, investments and restricted cash held in
interest bearing term deposits.
9.
Finance cost
Interest charges on bonds at coupon rate
Call premiums on early retirement of bonds
Amortisation of bond transaction costs
Total borrowing costs
Foreign exchange loss
Unwinding discount on decommissioning provision
Total finance costs before borrowing costs capitalised
Borrowing costs capitalised
Finance cost
For the year ended December 31,
2017
2018
25,428
1,427
1,087
27,942
26
5
27,973
(4,859)
23,114
20,018
-
841
20,859
102
4
20,965
(8,770)
12,195
On July 5, 2018 the Company completed refinancing its bonds which increased total bonds outstanding to $240 million
from the $186 million outstanding prior to the refinancing and increased the interest coupon from 11.5% to 12%.
Certain call premiums of approximately $1.4 million were paid by the Company to early retire the bonds issued under
the previous bond agreements.
Borrowing costs directly attributable to the acquisition and preparation of Atrush development assets for their
intended use have been capitalised together with the related Atrush oil and gas assets. All other borrowing costs are
recognised in profit or loss in the period in which they are incurred. A significant number of development projects
have been completed for their intended use, therefore the capitalisation of the related borrowing costs has ceased
leading to less borrowing costs being capitalised.
Refer also to Notes 11 and 16.
44
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
10. Taxation
(a)
Income tax expense
The income tax expense reflects an effective tax rate which differs from Canadian Federal and Provincial statutory tax
rates. The main differences are as follows:
Income / (loss) from continuing operations before income tax
Corporate income tax rate
Computed income tax expense / (recovery)
Increase / (decrease) resulting from:
Foreign tax rate differences
Effect of changes in tax rates
Effect of changes in foreign exchange rates
Decrease in deferred tax assets
Share issuance costs charged to share capital
Non-deductible compensation expense
Non-deductible losses on foreign operations
Non-taxable foreign exchange gain
Other expense
Income tax expense
For the year ended December 31,
2017
2018
1,933
27.0%
522
(1,213)
(243)
(57)
1,027
-
-
-
3
25
64
(11,414)
26.0%
(2,968)
646
-
(107)
344
(244)
3
2,311
1
99
85
The Company’s income tax expense relates to a provision, in the line ‘Foreign tax rate differences’, for income tax on
service income generated in Switzerland and is calculated at the effective tax rate of 24% prevailing in this jurisdiction.
(b)
Tax losses carried forward
The Company has tax losses and costs which are available to apply to future taxable income as follows:
As at December 31,
Canadian losses from operations
Canadian exploration expenses
Canadian unamortised share issue costs
Dutch losses from operations
U.S. Federal losses from operations
U.S. Federal tax basis in excess of carrying values of properties
Total tax losses carried forward
2018
36,310
2,486
829
161,288
173,320
3,654
377,887
2017
20,100
2,443
1,267
177,633
173,319
3,654
378,416
The Canadian losses from operations may be used to offset future Canadian taxable income and will expire over the
period from 2026 to 2038. The Canadian exploration expenses may be carried forward indefinitely to offset future
taxable Canadian income. Canadian unamortised share issue costs may offset future taxable Canadian income of years
2019 to 2021. The Dutch losses from operations may be used to offset future Dutch taxable income and will expire
over the period from 2019 to 2027, with the majority expiring in 2020. The U.S. Federal losses are available to offset
future taxable income in the United States through 2032.
The Company has not recognised any deferred tax assets amounting to approximately $91 million (2017: $104 million)
as it is not probable that these amounts will be realised.
45
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
11.
Property, plant and equipment
At January 1, 2017
Cost
Accumulated depreciation
Net book value
For the year ended December 31, 2017
Opening net book value
Additions
Depletion and depreciation expense
Net book value
At December 31, 2017
Cost
Accumulated depletion and depreciation
Net book value
For the year ended December 31, 2018
Opening net book value
Additions
Reclass from intangible E&E asset
Depletion and depreciation expense
Net book value
At December 31, 2018
Cost
Accumulated depletion and depreciation
Net book value
Oil and gas
assets
Computer
equipment
Furniture
and office
equipment
174,780
(138)
174,642
174,642
17,903
(7,627)
184,918
192,683
(7,765)
184,918
184,918
17,356
21,794
(28,171)
195,897
231,833
(35,936)
195,897
253
(237)
16
16
3
(16)
3
266
(263)
3
3
11
-
(4)
10
274
(264)
10
150
(150)
-
-
-
-
-
156
(156)
-
-
1
-
-
1
156
(155)
1
Total
175,183
(525)
174,658
174,658
17,906
(7,643)
184,921
193,105
(8,184)
184,921
184,921
17,368
21,794
(28,175)
195,908
232,263
(36,355)
195,908
The net book value of PP&E is principally comprised of development costs related to the Company’s share of Atrush
PSC proved and probable reserves, as estimated by McDaniel, less the cumulative depletion costs corresponding to
commercial production. During the year 2018 movements in PP&E were comprised of additions of $17.4 million (year
2017: $17.9 million), depletion and depreciation expense of $28.2 million (year 2017: $7.6 million) and a reclass to
PP&E from E&E of $21.8 million (year 2017: $nil) which resulted in a net increase of $11.0 million to the net book
value of PP&E assets. Net additions in 2018 included capitalised borrowing costs of $5.0 million (year 2017: $8.8
million). During the year 2018 plans were approved to produce and sell heavy oil which has resulted in the reclass to
PP&E of heavy oil related project costs.
Refer also to Notes 9, 12, 16 and 23.
46
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
12.
Intangible assets
At January 1, 2017
Cost
Accumulated amortisation
Net book value
For the year ended December 31, 2017
Opening net book value
Additions
Disposals
Amortisation expense
Net book value
At December 31, 2017
Cost
Accumulated amortisation
Net book value
For the year ended December 31, 2018
Opening net book value
Additions
Reclass to PP&E
Amortisation expense
Net book value
At December 31, 2018
Cost
Accumulated amortisation
Net book value
Exploration and
evaluation assets
Other intangible
assets
88,972
-
88,972
88,972
141
-
-
89,113
89,113
-
89,113
89,113
506
(21,794)
-
67,825
67,825
-
67,825
314
(279)
35
35
2
(21)
(10)
6
307
(301)
6
6
3
-
(5)
4
307
(303)
4
Total
89,286
(279)
89,007
89,007
143
(21)
(10)
89,119
89,420
(301)
89,119
89,119
509
(21,794)
(5)
67,829
68,132
(303)
67,829
The net book value of intangible assets is principally comprised of exploration and evaluation (“E&E”) assets which
represent the Atrush Block exploration and appraisal costs related to the Company’s share of Atrush Block contingent
resources as estimated by McDaniel. During the year 2018 movements in intangible assets were comprised of net
additions of $509 thousand (year 2017: $143 thousand), depreciation of $5 thousand (year 2017 $10 thousand) and
a reclass of $21.8 million (year 2017: $nil) from E&E to PP&E resulting in a net decrease to intangible assets of $21.3
million. Net additions in 2018 included the reversal of borrowing costs of $123 thousand (year 2017: $16 thousand).
Refer also to Notes 11, 16 and 23.
47
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
13.
Loans and receivables
In November 2016 the Company entered into certain agreements with the KRG and other Atrush contractors for the
reimbursement by the KRG to the Atrush contractors of certain Atrush exploration and development costs and
pipeline costs incurred by KRG in the years 2013 through 2017 which were funded by the Atrush contractors. The
Atrush Exploration Costs receivables, which relate to a share of the KRG’s development costs carried by ShaMaran
prior to the year 2016 and deemed to be exploration costs under the Atrush PSC, are repaid through an accelerated
petroleum cost recovery arrangement. The Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost Loan
are being repaid with interest at 7% per annum in 24 equal monthly instalments ending in October 2019. The Company
was owed amounts for its entitlement share of oil deliveries made to the KRG during the last three months of the year.
At year end the Company had loans and receivables outstanding as follows:
Atrush Exploration Costs receivable
Accounts receivable on Atrush oil sales
Atrush Development Cost Loan
Atrush Feeder Pipeline Cost Loan
Total loans and receivables
- Current portion
- Non-current portion
As at December 31,
2018
2017
34,898
14,531
7,136
4,718
61,283
36,099
25,184
37,247
13,957
16,018
9,751
76,973
32,277
44,696
In the year 2018 the Company received principal plus interest payments totalling $11.3 million for Atrush
Development Cost Loan and $6.9 million for the Atrush Feeder Pipeline Cost Loan, as well as $2.3 million of Atrush
Exploration Cost receivables. The Company has assessed the need for an impairment analysis and determined none
to be necessary. Therefore no impairments have been recorded.
In the year 2019 up to when these financial statements were approved the Company received $14.0 million in total
payments for loans and receivables balances outstanding at December 31, 2018, comprised of $10.9 million in total
payments for its entitlement share of oil sales for the months of October and November 2018, $2.6 million for Atrush
Development Cost Loan and Atrush Feeder Pipeline Cost Loan balances outstanding and $0.5 million in
reimbursements of the Atrush Exploration Costs receivable.
Refer also to Notes 6 and 8.
14.
Other current assets
Deposit on purchase of additional Atrush interest
Prepaid expenses
Other receivables
Total other current assets
As at December 31,
2018
2017
2,000
176
110
2,286
-
160
52
212
During the year 2018 a deposit of $2.0 million was paid to Marathon Oil KDV B.V. towards the price of acquiring an
additional 7.5% interest in the Atrush PSC (“the Acquisition”) as announced by the Company on December 27, 2018.
At the date these financial statements were approved certain conditions to closing remained outstanding. The
Company currently holds a 20.1% interest in the Atrush PSC.
48
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
15.
Accounts payable and accrued expenses
Payables to joint operations partner
Accrued expenses
Trade payables
Total accounts payable and accrued expenses
16.
Borrowings
As at December 31,
2018
2,734
859
282
3,875
2017
4,365
91
371
4,827
On July 5, 2018 the Company issued $240 million of senior unsecured bonds (“the ShaMaran bonds”). The ShaMaran
bonds have a five-year maturity without amortization and carry 12% fixed semi-annual coupon. Holders of $136
million of the $186.4 million of previously outstanding bonds (“GEP bonds”) of General Exploration Partners, Inc.
(“GEP”), a wholly owned subsidiary of the Company, agreed to early redeem their bonds in exchange for receiving an
equivalent amount of ShaMaran bonds. As a result the Company received $104 million ($100.4 million net of related
transaction costs) of cash proceeds from the ShaMaran bond issue. An amount of $50.4 million of the cash proceeds,
with an additional $3 million of the Company’s cash, have been used to early retire the remaining GEP bonds and the
remaining $53 million of the cash proceeds were held by the Company in an escrow account pledged to the
bondholders (the “Marathon Pledged Account”) on the balance sheet date, pending release to the Company upon the
closing of the purchase by the Company of an additional interest in the Atrush asset under terms prescribed in the
bond agreement. On December 31, 2018 in accordance with the terms of the ShaMaran bonds the Company
contributed $14.4 million, representing one semi-annual interest payment, to a Debt Service Retention Account
(“DSRA”) and pledged to the bondholders as security for the Company’s obligations under the ShaMaran bonds. The
amounts on deposit in the Marathon Pledged Account and the DSRA resulted in total restricted cash of $67.9 million
on the balance sheet date, which includes interest earned of $484 thousand.
The movements in borrowings are explained as follows:
Opening balance
Bond issued – net of transaction costs
Interest charges at coupon rate
Call premiums on early retirement of bonds
Amortisation of bond transaction costs
Bonds issued as interest payments
Payment to Bondholders – interest and call premiums
Bonds retired
Ending balance
- Current portion: accrued bond interest expense
- Current portion: borrowings
- Non-current portion: borrowings
For the year ended December 31,
2017
2018
188,491
236,361
25,428
1,427
1,087
-
(15,575)
(186,422)
250,797
14,080
-
236,717
167,632
-
20,018
-
841
19,721
(19,721)
-
188,491
2,799
185,692
-
49
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
The Company has complied with the financial covenants within its bond agreements during the years 2018 and 2017.
The contractual obligations under the ShaMaran Bonds, prior to the amendments to the bond agreement discussed
under the “Events After the Reporting Period” section below, are comprised of the repayment of principal and interest
expense based on undiscounted cash flows at payment date, reflect a step up in bond coupon interest to 13% and the
repayment in February 2019 of $50.6 million of bond principal plus interest both resulting from not having closed the
Marathon Acquisition by February 5, 2019 (the Marathon transaction longstop date”) and leaving $190 million of
bonds outstanding thereafter, and contributing one further payment to the DSRA before July 2019 to bring the
balance to the required one year of bond interest by that time, are as follows:
Less than one year
Between one and two years
Between three and five years
Total
For the year ended December 31,
2018
2017
76,350
37,800
238,000
352,150
207,860
-
207,860
At the date of these financial statements the above noted schedule of contractual obligations are no longer applicable.
Events after the reporting period
On January 5, 2019 the Company issued the first semi-annual interest payment to ShaMaran bondholders in the
amount of $14.4 million.
•
•
On February 1, 2019, bondholders approved of certain amendments to the ShaMaran Bonds agreement as follows:
•
funds on deposit in the DSRA may be used by the Company to fund the Acquisition and for general corporate
purposes;
funds in the Marathon Pledged Account will be used by the Company to prepay $50 million of ShaMaran Bonds
plus accrued interest;
the Company will reduce the aggregate outstanding amount of the Bond Issue to a maximum of $175 million on
or before July 2020;
in case the Acquisition is not closed by July 4, 2019 there will be a one-time step up in bond coupon interest by
1% per annum; and
the Liquidity Guarantee will remain in force until the Company has funded the DSRA with 12 months of bond
coupon interest.
•
•
On February 8, 2019, the Company repaid $50 million of ShaMaran Bonds and $550 thousand of related accrued
interest. At the date the financial statements were approved there were $190 million of ShaMaran Bonds
outstanding.
Nemesia S.à.r.l. (“Nemesia”), a company controlled by a trust settled by the estate of the late Adolf H. Lundin, agreed
to guarantee the Company’s obligations under the ShaMaran Bonds agreement up to an amount of $22.8 million (the
“Liquidity Guarantee”) representing one year of coupon interest of $190 million of ShaMaran Bonds now outstanding.
In exchange for providing the Liquidity Guarantee the Company issued Nemesia 2,000,000 common shares of
ShaMaran. In case of a draw down on the Liquidity Guarantee, the Company is required to issue to Nemesia a further
50,000 shares of ShaMaran for each $500 thousand drawn down per month until the drawn amount is repaid.
Nemesia are a related party after this event in 2019.
The remaining contractual obligations under the amended ShaMaran Bonds at the date these financial statements
were approved on March 7, 2019, which are comprised of the repayment of principal and interest expense based on
undiscounted cash flows at payment date, reflect the repayment of $50.6 million of principal and interest on February
8, 2019, and are based on the current $190 million of bonds outstanding thereafter until a further reduction in
ShaMaran Bonds outstanding to $175 million is completed in July 2020, are as follows:
March 8 to December 31, 2019
Year ended December 31, 2020
Three years ended December 31, 2023
Total
Refer also to Notes 9, 11, 21 and 25.
11,400
37,800
238,000
287,200
50
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
17.
Provisions
The provision relates to the Company’s share of future decommissioning and site restoration costs in respect of the
Company’s 20.1% interest in the Atrush Block and assumes these works will commence in the year 2032. The
estimated costs have been discounted to net present value using a Bank of Canada long term bond yield rate of 2.18%
(2017 year-end: 2.26%) and an inflation rate of 1.91% (2017 year-end: 2.11%).
Opening balance
Changes in estimates and obligations incurred
Changes in discount and inflation rates
Unwinding discount on decommissioning provision
Total decommissioning and site restoration provisions
18.
Share capital
As at December 31,
2018
9,427
290
(163)
5
9,559
2017
8,869
425
129
4
9,427
The Company is authorised to issue an unlimited number of common shares with no par value. The Company’s issued
share capital is as follows:
At January 1, 2017
Shares issued on private placement
Transaction costs on private placement
At December 31, 2017
At December 31, 2018
Refer also to Note 16 and 25.
Earnings per share
The earnings per share amounts were as follows:
Number of shares
Share capital
1,798,631,534
360,000,000
-
2,158,631,534
2,158,631,534
611,179
27,281
(922)
637,538
637,538
For the year ended December 31,
2017
2018
Net income / (loss), in dollars
Weighted average number of shares outstanding during the year
Weighted average diluted number of shares outstanding during the year
Basic and diluted income / loss per share, in dollars
1,869,000
2,158,631,534
2,183,631,534
-
(11,499,000)
2,129,042,493
2,157,207,493
(0.01)
51
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
19.
Share based payments expense
The Company has established share unit plans and a share purchase option plan whereby a committee of the
Company’s Board may, from time to time, grant up to a total of 10% of the issued share capital to directors, officers,
employees or consultants. The number of shares issuable under these plans at any specific time to any one recipient
shall not exceed 5% of the issued and outstanding common shares of the Company. Under the share unit plans the
Company may grant performance share units (“PSU”), restricted share units (“RSU”) or deferred share units (“DSU”).
PSU grants may be awarded annually to employees, directors or consultants (“Participants”) based on the fulfilment
of defined Company and individual performance parameters. RSU grants may be awarded to Participants annually
based on the fulfilment of defined Company performance parameters. RSUs and PSUs will vest based on the
conditions described in the relevant grant agreement and, in any case, no later than the end of the third calendar year
following the date of the grant. DSU’s may be awarded annually to non-employee directors of the Company based
on the performance of the Company and vest immediately at the time of grant; however DSUs may not be redeemed
until a minimum period of three months has passed following the end of service as a director of the Company. The
share unit plans provide for redemption of the share units by way of payment in cash, shares or a combination of cash
and shares. Under the option plan the term of any options granted under the option plan will be fixed by the Board
and may not exceed five years from the date of grant. A four month hold period may be imposed by the stock exchange
from the date of grant. Vesting terms are at the discretion of the Board. All issued share options have terms of five
years and vest over two years from grant date. The exercise prices reflect trading values of the Company’s shares at
grant date.
Movements in the Company’s outstanding share options are explained as follows:
Number of
share options outstanding
Weighted average
exercise price
CAD
At January 1, 2017
Change in the year 2017
At December 31, 2017
Expired in the year 2018
At December 31, 2018
Share options exercisable:
At December 31, 2017
At December 31, 2018
Weighted average remaining contractual life of options:
At December 31, 2017
At December 31, 2018
28,165,000
-
28,165,000
(3,165,000)
25,000,000
28,165,000
25,000,000
1.91 years
1.05 years
0.13
-
0.13
0.28
0.12
0.13
0.12
The Company recognises compensation expense on share options granted to both employees and non-employees
using the fair value method at the date of grant, which the Company records as an expense. The share-based
payments expense is calculated using the Black-Scholes option pricing model.
Option pricing models require the input of highly subjective assumptions including the expected price volatility.
Changes in the subjective input assumptions can materially affect the fair value estimate and therefore the existing
models do not necessarily provide a reliable single measure of the fair value of the Company’s share options.
There were no options granted during the year 2018. Share based payments expense for the year ended December
31, 2018 was $nil (2017: $11 thousand). There were no grants of share units at the balance sheet date.
52
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
20.
Pension liability
The Company operates a pension plan in Switzerland that is managed through a private pension plan and accounts
for its pension plan in accordance with IAS 19. The amount recognized in the balance sheet associated with the Swiss
pension plan is as follows:
Present value of defined benefit obligation
Fair value of plan assets
Pension liability
For the year ended December 31,
2017
2018
7,376
(6,046)
1,330
8,082
(6,301)
1,781
The movement in the defined benefit obligation over the year is as follows:
As at December 31,
2018
Opening balance
Additional contributions paid by employees
Current service cost
Ordinary contributions paid by employees
Interest expense on defined benefit obligation
Administration costs
Foreign exchange (gain)/ loss
Past service cost
Actuarial (gain)/ loss on defined benefit obligation
Benefits paid from plan assets
Defined benefit obligation, ending balance
8,082
583
172
106
56
4
(67)
(111)
(315)
(1,134)
7,376
2017
7,304
217
172
110
49
5
327
-
32
(134)
8,082
The weighted average duration of the defined benefit obligation is 15.98 years. There is no maturity profile since the
average remaining life before active employees reach final age according to the plan is 10.1 years.
The movement in the fair value of the plan assets over the year is as follows:
Opening balance
Additional contributions paid by employees
Ordinary contributions paid by employer
Ordinary contributions paid by employees
Interest income on plan assets
Return on plan assets excluding interest income
Foreign exchange (loss)/gain
Benefits paid from plan assets
Fair value of plan assets, ending balance
As at December 31,
2018
6,301
583
159
106
44
42
(55)
(1,134)
6,046
2017
5,634
217
165
110
38
18
253
(134)
6,301
The plan assets are under an insurance contract comprised entirely of free funds and reserves, such as fluctuation
reserves and employer contribution reserves, for which there is no quoted price in an active market.
The amount recognized in the income statement associated with the Company’s pension plan is as follows:
Current service cost
Interest expense on defined benefit obligation
Administration costs
Interest income on plan assets
Past service cost
Total expense recognised
For the year ended December 31,
2017
2018
172
56
4
(44)
(111)
77
172
49
5
(38)
-
188
53
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
The expense associated with the Company’s pension plan of $77 thousand was included within general and
administrative expenses. The Company also recognised in other comprehensive income a $357 thousand net actuarial
gain on defined benefit obligations and pension plan assets.
The principal actuarial assumptions used to estimate the Company’s pension obligation are as follows:
Discount rate
Inflation rate
Future salary increases
Future pension increases
Retirement ages, male (‘M’) and female (‘F’)
For the year ended December 31,
2017
2018
0.85%
1.00%
1.00%
0.00%
M65/F64
0.70%
1.00%
1.00%
0.00%
M65/F64
Assumptions regarding future mortality are set based on actuarial advice in accordance with the BVG 2015 GT
generational published statistics and experience in Switzerland. The discount rate is determined by reference to the
yield on high-quality corporate bonds. The rate of inflation is based on the expected value of future annual inflation
adjustments in Switzerland. The rate for future salary increases is based on the average increase in the salaries paid
by the Company, and the rate of pension increases is based on the annual increase in risk, retirement and survivors’
benefits. Contributions to the Company’s pension plan during 2019 are expected to total $0.3 million.
The sensitivity of the defined benefit obligation to changes in the weighted principal assumptions is:
Discount rate
Salary growth rate
Life expectancy
Change in assumption
0.50%
0.50%
One year
Increase in assumption Decrease in assumption
Increase by 8.4%
Decrease by 0.2%
Decrease by 2.0%
Decrease by 7.4%
Increase by 0.2%
Increase by 1.9%
The above sensitivity analyses are based on a change in an assumption while holding all other assumptions constant.
In practice, this is unlikely to occur, and changes in some of the assumptions may be correlated. When calculating the
sensitivity of the defined benefit obligation to significant actuarial assumptions, the same method has been applied
as when calculating the pension liability recognized within the consolidated balance sheet. There have been no
changes to the sensitivity analysis method this year.
54
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
21.
Financial instruments
Financial assets
The financial assets of the Company on the balance sheet dates were as follows:
Cash and cash equivalents, restricted ²
Cash and cash equivalents, unrestricted ²
Loans and receivables ²
Other receivables ²
Total financial assets
Carrying and fair values ¹
At December 31, 2018 At December 31, 2017
67,884
24,586
26,385
110
118,965
2,162
3,094
39,726
52
45,034
Financial assets classified as other receivables are initially recognised at fair value and are subsequently measured at
amortised cost using the effective interest method less any provision for impairment.
Financial liabilities
The financial liabilities of the Company on the balance sheet dates were as follows:
Borrowings ³
Accrued interest on bonds
Accounts payable and accrued expenses ²
Current tax liabilities
Total financial liabilities
Fair value
hierarchy ⁴
Level 2
Carrying values
At December 31, 2018 At December 31, 2017
236,717
14,080
3,875
16
254,688
185,692
2,799
4,827
-
193,318
Financial liabilities are initially recognised at the fair value of the amount expected to be paid and are subsequently
measured at amortised cost using the effective interest rate method.
¹ The carrying amount of the Company’s financial assets approximate their fair values at the balance sheet dates.
² No valuation techniques have been applied to establish the fair value of these financial instruments as they are either
cash and cash equivalents, correspond to payment terms fixed by contract or, due to the short-term nature, are readily
convertible to or settled with cash and cash equivalents.
³ The fair value of the Company’s borrowings at the balance sheet date was $240 million (December 31, 2017: $151.8
million). The fair value has been determined based on quoted market prices of similar bonds held by similar companies
within the industry.
⁴ Fair value measurements
IFRS 13 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date and establishes a fair value hierarchy of three
levels to classify the inputs to valuation techniques used to measure fair value:
▪
▪
Level 1: fair value measurements are based on unadjusted quoted market prices;
Level 2: fair value measurements are based on valuation models and techniques where the significant inputs are
derived from quoted prices or indices;
Level 3: fair value measurements are derived from valuation techniques that include inputs that are not based on
observable market data.
▪
55
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Capital risk management
The Company manages its capital to ensure that entities within the Company will be able to continue as a going
concern, while maximising return to shareholders. The capital structure of the Company consists of cash and cash
equivalents and equity, comprising issued share capital, reserves and retained earnings as disclosed in the
consolidated statement of changes in equity. The Company had debt relating to borrowings and accrued interest of
$250.8 million as at December 31, 2018 (2017: $188.5 million). Refer also to Note 16.
Financial risk management objectives
The Company’s management monitors and manages the Company’s exposure to financial risks facing the operations.
These financial risks include market risk (including commodity price, foreign currency and interest rate risks), credit
risk and liquidity risk.
The Company does not presently hedge against these risks as the benefits of entering into such agreements is not
considered to be significant enough as to outweigh the significant cost and administrative burden associated with
such hedging contracts.
Commodity price risk
The prices that the Company receives for its oil and gas production may have a significant impact on the Company’s
revenues and cash flows provided by operations. World prices for oil and gas are characterised by significant
fluctuations that are determined by the global balance of supply and demand and worldwide political developments
and, in particular, the price received for the Company’s oil and gas production in Kurdistan is dependent upon the
Kurdistan government and its ability to export production outside of Iraq. A decline in the price of ICE Brent Crude oil,
a reference in determining the price at which the Company can sell future oil production, could adversely affect the
amount of funds available for capital reinvestment purposes as well as the Company’s value in use calculations for
impairment test purposes. Refer also to Note 4(d).
The table below summarises the effect that a change in the Dated Brent oil price would have had on the net income
during the year ended December 31, 2018:
Net income reported in the financial statements
Possible shift - (decrease) / increase in Dated Brent oil price in %
Total (decrease) / increase in net income
The Company does not hedge against commodity price risk.
Foreign currency risk
1,869
(10%)
(6,893)
1,869
10%
6,893
The substantial portion of the Company’s operations require purchases denominated in USD, which is the functional
and reporting currency of the Company and the currency in which the Company maintains the substantial portion of
its cash and cash equivalents. Certain of its operations require the Company to make purchases denominated in
foreign currencies, which are currencies other than USD and correspond to the various countries in which the
Company conducts its business, most notably, Swiss Francs (“CHF”) and Canadian dollars (“CAD”). As a result, the
Company holds some cash and cash equivalents in foreign currencies and is therefore exposed to foreign currency
risk due to exchange rate fluctuations between the foreign currencies and the USD. The Company considers its foreign
currency risk is limited because it holds relatively insignificant amounts of foreign currencies at any point in time and
since its volume of transactions in foreign currencies is currently relatively low. The Company has elected not to hedge
its exposure to the risk of changes in foreign currency exchange rates.
The carrying amounts of the Company’s principal monetary assets, liabilities and equity denominated in foreign
currency at the reporting date are as follows:
Assets
December 31,
2018
2017
Liabilities
December 31,
2018
2017
Equity
December 31,
2018
2017
Canadian dollars in thousands (“CAD 000”)
Swiss francs in thousands (“CHF 000”)
31
280
36
83
258
133
68
221
223,146
-
225,318
-
56
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Foreign currency sensitivity analysis
The Company is exposed to movements in CHF and CAD against the USD, the presentational currency of the Company.
Sensitivity analyses have been performed to indicate how the profit or loss would have been affected by changes in
the exchange rates between the USD and CHF and CAD. The analysis below is based on a strengthening of the CHF
and CAD by 1% against the USD in which the Company has assets, liabilities and equity at the end of respective period.
A movement of 1% reflects a reasonably possible sensitivity when compared to historical movements over a three to
five-year timeframe. The sensitivity analysis includes only outstanding foreign currency denominated monetary items
and adjust their translation at the period end for a 1% change in foreign currency rates.
A positive number in the table below indicates an increase in profit where USD weakens 1% against the CHF or CAD
based on the CHF and CAD assets, liabilities and equity held by the Company at the balance sheet dates. For a 1%
strengthening of the USD against the CHF or CAD there would be an equal and opposite impact on the profit or loss.
Statement of comprehensive income - CAD
Statement of comprehensive income - CHF
Interest rate risk
Assets
2018
-
3
Liabilities
Equity
2017
2018
2017
2018
2017
-
1
(1)
(1)
-
(2)
(1,209)
-
(1,442)
-
The Company earns interest income at variable rates on its cash and cash equivalents and is therefore exposed to
interest rate risk due to a fluctuation in short-term interest rates.
The Company’s policy on interest rate management is to maintain a certain amount of funds in the form of cash and
cash equivalents for short-term liabilities and to have the remainder held on relatively short-term deposits.
The Company is highly leveraged though financing at the project level, for the continuation of Atrush project, and at
the corporate level due to the $240 million of bond which have been issued since July 2018. However, the Company
is not exposed to interest rate risks associated with the bonds as the interest rate is fixed.
Interest rate sensitivity analysis:
Based on exposure to the interest rates for cash and cash equivalents at the balance sheet date an increase or
decrease of 0.5% in the interest rate would not have a material impact on the Company’s profit or loss for the year.
An interest rate of 0.5% is used as it represents management’s assessment of the reasonably possible changes in
interest rates.
Credit risk
Credit risk is the risk that a counterparty will default on its contractual obligations resulting in financial loss to the
Company. The Company is primarily exposed to credit risk on its cash and cash equivalents, loans and receivables and
other receivables.
The Company manages credit risk by monitoring counterparty ratings and credit limits and by maintaining excess cash
and cash equivalents on account in instruments having a minimum credit rating of R-1 (mid) or better (as measured
by Dominion Bond Rate Services) or the equivalent thereof according to a recognised bond rating service.
The carrying amounts of the Company’s financial assets recorded in the consolidated financial statements represent
the Company’s maximum exposure to credit risk.
57
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Liquidity risk
Liquidity risk is the risk that the Company will have difficulties meeting its financial obligations as they become due.
In common with many oil and gas exploration companies, the Company raises financing for its exploration and
development activities in discrete tranches to finance its activities for limited periods. The Company seeks to acquire
additional funding as and when required. The Company anticipates making substantial capital expenditures in the
future for the acquisition, exploration, development and production of oil and gas reserves and as the Company’s
project moves further into the development stage, specific financing, including the possibility of additional debt, may
be required to enable future development to take place. The financial results of the Company will impact its access to
the capital markets necessary to undertake or complete future drilling and development programs. There can be no
assurance that debt or equity financing, or future cash generated by operations, would be available or sufficient to
meet these requirements or, if debt or equity financing is available, that it will be on terms acceptable to the Company.
The Company manages liquidity risk by maintaining adequate cash reserves and by continuously monitoring forecast
and actual cash flows. Annual capital expenditure budgets are prepared, which are regularly monitored and updated
as considered necessary. In addition, the Company requires authorisations for expenditure on both operating and
non-operating projects to further manage capital expenditures.
The maturity profile of the Company’s financial liabilities is indicated by their classification in the consolidated balance
sheet as “current” or “non-current”.
22.
Commitments and contingencies
As at December 31, 2018 the outstanding commitments of the Company were as follows:
Atrush Block development and PSC
Office and other
Total commitments
For the year ended December 31,
2019
47,583
39
47,622
2020
120
-
120
2021
Thereafter
120
-
120
1,328
-
1,328
Total
49,151
39
49,190
Amounts relating to Atrush Block development represent the Company’s unfunded paying interest share of 20.1% of
the approved 2019 work program and other obligations under the Atrush PSC.
Under the terms of the Atrush PSC the Company will owe a share of production bonuses payable to the KRG when
cumulative oil production from Atrush reaches production milestones defined in the Atrush PSC as follows: $13.3
million at 25 million barrels (ShaMaran share: $3.6 million); and $23.3 million at 50 million barrels (ShaMaran share:
$6.2 million).
Refer also to Notes 16 and 23.
23.
Interests in joint operations and other entities
Interests in joint operations - Atrush Block Production Sharing Contract
ShaMaran holds a 20.1% direct interest in the Atrush PSC through GEP. TAQA Atrush B.V. is the Operator of the Atrush
Block with a 39.9% direct interest, the KRG holds a 25% direct interest and MOKDV holds a 15% direct interest. TAQA,
the KRG, GEP and MOKDV together are “the Contractors” to the Atrush PSC. Under the terms of the 4th PSC
Amendment and the Facilitation Agreement, which became effective on November 7, 2016, the Non-Government
Contractors paid their pro-rata share of the Feeder Pipeline costs and the KRG’s share of Atrush development costs
up to October 31, 2017, the date when the Final Completion Certificate for the Atrush Feeder Pipeline for the Feeder
Pipeline was issued. These costs are now being reimbursed to the Non-Government Contractors in 24 equal monthly
instalments with the last instalment due to be paid in October 2019.
58
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Under the terms of the Atrush PSC the development period is for 20 years with an automatic right to a five-year
extension and the possibility to extend for an additional five years. All qualifying petroleum costs incurred by the
Contractors shall be recovered from a portion of available petroleum production, defined under the terms of the
Atrush PSC. All modifications to the Atrush PSC are subject to the approval of the KRG. The Company is responsible
for its pro-rata share of the costs incurred in executing the development work program on the Atrush Block which
commenced on October 1, 2013.
Refer also to Notes 13, 22 and 25.
Information about subsidiaries
The consolidated financial statements of the Company include:
Subsidiary
Principal activities
Country of
Incorporation
% equity interest as at
31 Dec 2018
31 Dec 2017
ShaMaran Petroleum Holdings Coöperatief U.A. Oil exploration and production
Oil exploration and production
ShaMaran Ventures B.V.
Oil exploration and production
General Exploration Partners, Inc.
Oil exploration and production
ShaMaran Petroleum B.V.
Technical and admin. services
ShaMaran Services S.A.
Inactive
Bayou Bend Petroleum U.S.A. Ltd
The Netherlands
The Netherlands
Cayman Islands
The Netherlands
Switzerland
United States
100
100
100
100
100
100
100
100
100
100
100
100
24.
Related party transactions
Transactions with corporate entities
Bennett-Jones
Namdo Management Services Ltd.
Lundin Petroleum AB
Total
Purchases of services
during the year
2018
2017
Amounts owing at
December 31,
2017
2018
51
34
104
189
45
50
204
299
-
-
-
-
-
-
18
18
Bennett-Jones is a law firm in which an officer of the Company is a partner and has provided legal services to the
Company. Amounts reported under Bennett Jones are inclusive of services provided to the Company by McCullough
O’Connor Irwin LLP, which merged with Bennett Jones on June 1, 2018, where the same officer of the Company was
previously a partner.
Namdo Management Services Ltd. is a private corporation affiliated with a shareholder of the Company and has
provided corporate administrative support and investor relations services to the Company.
The Company received services from various subsidiary companies of Lundin Petroleum AB (“Lundin”), a shareholder
of the Company until June 21, 2018 when Lundin sold its ShaMaran shares. Lundin charges from January 1 to June 21,
2018 of $104 (year 2017: $204) were comprised of office rental, administrative and building services of $88 (year
2017: $177), technical service costs of $nil (year 2017: $1) and investor relations services of $16 (year 2017: $26).
All transactions with related parties are in the normal course of business and are made on the same terms and
conditions as with parties at arm’s length.
Refer also to Note 25.
59
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2018
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Key management compensation
The Company’s key management was comprised of its directors and executive officers who have been remunerated
as follows:
Management’s salaries
Management’s short-term benefits
Directors’ fees
Management’s pension benefits
Management’s share-based payments
Directors’ share-based payments
Total
For the year ended December 31,
2017
2018
881
464
166
121
-
-
1,632
877
959
81
120
9
3
2,049
Short-term employee benefits include non-equity incentive plan compensation and other short-term benefits. Share-
based payments compensation represents the portion of the Company’s share-based payments expense incurred
during the year attributable to the key management, accounted for in accordance with IFRS 2 ‘Share Based Payments’.
25.
Events after the reporting period
On January 23, 2019, the Company issued to Nemesia 2,000,000 common shares of ShaMaran in accordance with the
terms of the Liquidity Guarantee.
Refer to Note 16, Borrowings, for further information about the developments after the year ending December 31,
2018, regarding the Company’s bonds.
Refer also to Notes 13, 16, 18, 23 and 24.
60
SHAMARAN PETROLEUM CORP.
DIRECTORS
CORPORATE INFORMATION
Keith C. Hill
Director, Chairman
Florida, U.S.A.
Chris Bruijnzeels
Director, President & Chief Executive Officer
CORPORATE OFFICE
885 West Georgia Street
Suite 2000
Vancouver, British Columbia V6C 3E8
Telephone: +1-604-689-7842
Facsimile: +1-604-689-4250
Geneva, Switzerland
Website: www.shamaranpetroleum.com
Brian D. Edgar
Director
Vancouver, British Columbia
Terry L. Allen
Director
Calgary, Alberta
Michael Ebsary
Director
Geneva, Switzerland
OPERATIONS OFFICE
5 Chemin de la Pallanterie
1222 Vésenaz
Switzerland
Telephone: +41-22-560-8600
Facsimile: +41-22-560-8601
BANKER
HSBC Bank Canada
Vancouver, British Columbia
INDEPENDENT AUDITORS
PricewaterhouseCoopers SA
Geneva, Switzerland
TRANSFER AGENT
OFFICERS
Computershare Trust Company of Canada
Brenden Johnstone
Chief Financial Officer
Revelstoke, British Columbia
Kevin E. Hisko
Corporate Secretary
Vancouver, British Columbia
Vancouver, British Columbia
STOCK EXCHANGE LISTINGS
TSX Venture Exchange and
NASDAQ First North Exchange
Trading Symbol: SNM
INVESTOR RELATIONS
Sophia Shane
Vancouver, British Columbia
61