ShaMaran Petroleum Corp.
Annual Report
For the year ended December 31, 2017
SHAMARAN PETROLEUM CORP.
MANAGEMENT DISCUSSION AND ANALYSIS
For the year ended December 31, 2017
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 8, 2018.
The MD&A should be read in conjunction with the audited consolidated financial statements for the year ended
December 31, 2017 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 an oil development and exploration company with a 20.1% direct interest in the Atrush
Block production sharing contract (“Atrush PSC”) relating to a property located in the Kurdistan Region of Iraq
(“Kurdistan”). Atrush is currently in the first phase of the development program (“Phase 1”). Phase 1 of field
development consists of installing and commissioning production facilities with 30,000 barrels of oil per day (“bopd”)
capacity and the drilling and completion of five production wells to supply the production facility. Oil production from
Atrush commenced in July 2017 and the fifth production well was drilled in November 2017.
The oil discovery on the Atrush petroleum property is continuously being appraised. Further phases of development,
including further Phase I drilling will be defined based on production data, appraisal information and economic
circumstances. The Atrush Block is located approximately 85 kilometres northwest of Erbil, the capital of Kurdistan, is
269 square kilometres in area and has oil proven in Jurassic fractured carbonates in the Chiya Khere structure. The
structure is expressed at surface by the Chiya Khere mountain which runs east‐west for approximately 25 kilometres
with an approximate width of 3.5 kilometres.
ShaMaran is a Canadian oil and gas company listed on the TSX Venture Exchange and the NASDAQ Stockholm First
North Exchange (Sweden) under the symbol "SNM".
HIGHLIGHTS AND DEVELOPMENTS
Operations
Oil production on the Atrush Block commenced in July 2017. Average production in the fourth quarter of 2017
was 21,700 barrels of oil per day (“bopd”). To address certain production constraints the facilities were shut down
in the beginning of October. These constraints have now successfully been resolved. In winter months the Atrush
Production Facilities are limited to processing approximately 27,000 bopd of the total 30,000 bopd capacity due
to low ambient temperatures which reduces the amount of heat otherwise available to process the oil to export
specifications.
3.4 million barrels of oil were produced and exported from Atrush for sale to the Kurdistan Regional Government
(“KRG”) during the second half of 2017 resulting in an average production of 18.1 thousand barrels per day. The
Company’s entitlement share1 of 2017 exports was approximately 400 thousand barrels which were sold at an
average netback price2 of $44.38 per barrel of oil. In the fourth quarter of 2017 oil was exported and sold from
Atrush totalling 2.0 million barrels. The Company’s entitlement share of fourth quarter exports was approximately
295 thousand barrels which were sold at an average netback price of $47.0 per barrel of oil.
The Company’s cash inflows from Atrush related activities are comprised of three elements:
o Entitlement share of Atrush PSC profit oil and cost oil: from commencement of exports in July 2017 up to the
date of the MD&A the Company has received payments totalling $8.5 million which reflect its entitlement
share of the $44.2 million in total payments received by the Atrush Non‐Government Contractors from the
KRG for July through November 2017 oil sales.
o Atrush Exploration Costs receivable: over this same period the Company collected a further $458 thousand of
Atrush Exploration Cost receivables from the KRG’s entitlement share of July through November 2017 oil sales.
1 The Company’s entitlement share includes an adjustment for the exploration cost sharing arrangement between TAQA and GEP.
2 This includes a discount to Dated Brent for oil quality and all local and international transportation costs.
1
o The Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost Loan (“the KRG Loans”), In January
2018 the Non‐Government Contractors and the KRG agreed that substantially all the first two instalments on
the KRG Loans, which were due in November and December of 2017, would be offset against amounts owed
to the KRG for security services which they provided for the Atrush operations, and an Atrush production
bonus. The KRG Loan balances collected by the Company under the agreement was $2.6 million. January 2018
and subsequent invoices are expected to be paid in line with the current practice for crude oil sales payments.
The January 2018 invoice is therefore expected to be paid in April 2018.
The Chiya Khere‐7 (“CK‐7”) well, which was spudded on September 17, 2017 reached a final depth of 1,861 metres
in early November 2017. The reservoir section was encountered approximately 114 metres shallower than
prognosis which had a positive impact of the Company’s 2P reserves reported as at December 31, 2017. The well
was drilled on time and under budget.
In February 2018 a new sales agreement was concluded between the Atrush Non‐Government Contractors and
the KRG for the sale of Atrush oil whereby the KRG will buy oil exported from the Atrush field by pipeline at the
Atrush block boundary based upon the Dated Brent oil price minus $15.73 ($16.04 under the previous agreement)
for quality discount and all local and international transportation costs. This discount is based on the same
principles as other oil sales agreements in the Kurdistan Region of Iraq and reflects a better API gravity than was
assumed in the previous sales agreement.
Corporate
On January 30, 2017 the Company completed the issue of 360 million common shares of ShaMaran on a private
placement basis (the “Private Placement”) at a price per share of CAD 0.10 (equal to SEK 0.67) which resulted in
gross proceeds to the Company of $27.3 million ($26.4 million net of transaction related costs). Zebra Holdings
and Investments SARL, Lorito Holdings SARL and Lundin Petroleum BV, the Company’s major shareholders,
subscribed for 43,463,618 shares, 16,984,621 shares and 17,800,000 shares, respectively, in the Private
Placement.
On February 15, 2018 the Company reported estimated reserves and contingent resources for the Atrush field as
at December 31, 2017. Total Field Proven plus Probable (“2P”) Reserves on a property gross basis for Atrush
increased from 85.1 MMbbl reported as at December 31, 2016 to 102.7 MMbbl which, when 2017 Atrush
production of 3.4 MMbbl is included, represents an increase of 25 percent. Total Field Unrisked Best Estimate
Contingent Oil Resources (“2C”)3 on a property gross basis for Atrush was approximately the same as the 2016
estimate at 296 MMbbl. Total discovered oil in place in the Atrush Block is a low estimate of 1.5 billion barrels, a
best estimate of 2.1 billion barrels and a high estimate of 2.9 billion barrels.
OPERATIONS
Following the independence referendum held in Kurdistan on September 25, 2017, operations in the Atrush field in
Kurdistan are continuing in a normal, safe and secure manner. Exports from Atrush are continuing via the Kurdistan
Export Pipeline system.
Construction work and commissioning on the 30,000 bopd Atrush Phase 1 Production Facilities (“Production Facility”),
the pipeline between the Production Facility and the block boundary (the “Spur Pipeline”), the pump station, the
intermediate pigging and pressure reduction station (“IPPR”) and the section of the pipeline from the block boundary
to the tie‐in point on the main export pipeline (“Feeder Pipeline”) necessary for exporting Atrush oil was concluded
in the first half of 2017.
Oil production on the Atrush Block commenced on July 3, 2017. Cumulative production exported from Atrush from
July to December 2017 was 3.4 million barrels of oil. To address certain production constraints the Production Facility
was shut down in early October. Production was resumed thereafter and the Production Facility has since been
operating at 27,000 bopd processing capacity. In the winter months the Atrush Production Facilities are limited due
to low ambient temperatures which reduces the amount of heat otherwise available to process the oil to export
specifications. Despite these limitations operational uptimes of 96.9% in December 2017 has been achieved,
considerably above the 90% uptime previously projected.
3 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
Three producing Atrush wells, Atrush‐2, Chiya Khere‐5 and Chiya Khere‐8 are currently supplying this production.
Following issues related back‐producing drilling fluid lost during drilling operations, the Atrush 4 (“AT‐4”) well has
been successfully cleaned up via temporary facilities. However, productivity following the clean‐up has been less than
expected. The AT‐4 well was drilled in a steeply dipping part of the reservoir and as a result appears to be not
connected to the full reservoir sequence. AT‐4 is currently shut in awaiting a work‐over to install a smaller pump.
CK‐7 was spudded on September 17, 2017 and reached a final depth of 1,861 metres in early November 2017. The
reservoir section was encountered approximately 114 metres shallower than prognosis. Testing and completion of
the well will be performed in 2018 to coincide with installation of flow lines between the Production Facility and the
Chamanke E location were the well is located. CK‐7 was drilled with the Romfor 25 rig and was on time and under
budget. The main objectives of the well are to appraise the commercial potential of the Mus formation, to help reduce
the uncertainty in the location of the medium to heavy oil transition zone and to serve as a further producing well.
A further two appraisal wells have been drilled and tested in the eastern part of the field. Good reservoir
communication has been proven between the east part and the west part of the field. It is planned to conduct an
extended well test in one of the two eastern appraisal wells, Chiya Khere‐6 (“CK‐6”). This will provide important
production information on the heavier part of the oil column. Together with production data from the five
development wells this will allow for defining the next phases of development
Following encouraging production results from the Atrush field after the start of production in July 2017, as well as
the positive drilling results of CK‐7 well, the Company’s independent reserves and resources evaluator, McDaniel &
Associates Consultants Ltd (“McDaniel”) increased the 2P oil reserves estimate to 102.7MMbbl at the end of the year
2017. 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 heavy oil extended well
test planned in 2018 for the CK‐6 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 296 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 heavy oil extended well test planned for the
second half of 2018. McDaniel estimates the chance of developing the 2C contingent oil resources at 80 percent.
OUTLOOK
Operations
Production guidance for Atrush gross in 2018 is 25,000 to 30,000 bopd with lifting costs for the year forecasted at
$6.8/bbl.
Capital expenditure guidance is $19.6 million (20.1% working interest in Atrush) which includes:
o
identify and install additional heat sources ahead of the next winter months;
o continue with program to identify debottleneck opportunities to further increase production capacity beyond
30,000 bopd;
o testing and completion of the CK‐7 well;
o
install the CK‐7 flow line and bring CK‐7 into production;
o drilling, testing and completion of Chiya Khere (“CK‐10”), a sixth development well;
o drilling and completion of Chiya Khere (“CK‐9”), a dedicated water disposal well; and
o conducting extended testing of the CK‐6 well which is located on the eastern side of the Atrush Block and which
is outside the 2P reserve area of Atrush. This would involve the installation of temporary production facilities
near the Chamanke–C well pad and the delivery by truck of oil to the main Phase 1 Production Facilities.
Following the results of the CK‐7 and CK‐10 wells, the extended well testing in CK‐6 and sustained production from
the Phase 1 Production Facilities the Company expects to further assess the significant undeveloped Atrush
resource base with the potential to grow organically to approximately 100,000 bopd production.
3
OWNERSHIP, PRINCIPAL TERMS OF THE ATRUSH PSC
ShaMaran, through its wholly owned subsidiary, GEP, holds 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 holds a 25% direct interest and Marathon Oil KDV B.V. (“MOKDV”) holds 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.
The 4th PSC Amendment and Atrush Facilitation Agreement include the following principal terms:
The KRG acquires a 25% interest in the Atrush PSC effective November 7, 2012, the date of declaration of
commerciality (“DOC date”). As a consequence the respective participating interests in the Atrush PSC are TAQA
at 39.9%, the KRG at 25%, GEP at 20.1% and MOKDV at 15%;
The Non‐Government Contractors will fund the cost of constructing the Feeder Pipeline which will be novated to
the KRG following the commencement of oil exports from Atrush;
All Atrush petroleum costs from the DOC date up to the commencement of oil exports from Atrush, which is
defined as when the Final Completion Certificate for the Atrush Feeder Pipeline (“FCC”) for the Feeder Pipeline is
issued, are to be paid by the Non‐Government Contractors and a defined portion of the KRG’s share of these costs
will be repaid through an accelerated petroleum cost recovery arrangement from the sale of future oil production
from Atrush; and
Feeder Pipeline costs and the balance of the Atrush petroleum costs incurred by the Non‐Government Contractors
on behalf of the KRG that are not covered by the accelerated petroleum cost recovery arrangement will be repaid
by the KRG within 2 years from issuance of the FCC for the Feeder Pipeline. The FCC was subsequently issued on
October 31, 2017.
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.
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%.
4
SELECTED ANNUAL FINANCIAL INFORMATION
The following is a summary of selected annual financial information for the Company:
(In $000, except per share data)
Continuing operations:
Revenues
Cost of goods sold
Service fees income
General and administrative expense
Share based payments expense
Depreciation and amortisation expense
Impairment loss
Finance income
Finance cost
Income tax expense
Loss from continuing operations
Discontinued operations:
Gain on release of excess accrued windup costs
Expenses
Gain from discontinued operations
2017
17,689
(14,009)
‐
(4,511)
(11)
(26)
‐
1,649
(12,195)
(85)
(11,499)
‐
‐
‐
For the year ended December 31,
2016
2015
‐
‐
120
(3,811)
(249)
(45)
‐
484
(5,586)
(69)
(9,156)
‐
‐
‐
‐
‐
‐
(2,359)
(1,210)
(56)
(244,557)
681
(5,321)
(94)
(252,916)
46
(13)
33
Loss for the year
(11,499)
(9,156)
(252,883)
Basic diluted loss in $ per share:
(0.01)
(0.01)
(0.17)
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
2017
184,921
89,119
76,973
5,468
356,481
(185,692)
(18,834)
151,955
As at December 31,
2016
174,658
89,007
53,366
4,640
321,671
(165,129)
(19,476)
137,066
2015
177,044
88,645
‐
32,121
297,810
(148,263)
(19,923)
129,624
Common shares outstanding (x 1,000)
2,158,632
1,798,632
1,579,768
Summary of Principal Changes in Annual Financial Information
The Company has reported in 2017 a net loss of $11.5 million which was primarily driven by finance cost, the
substantial portion of which was expensed borrowing costs on the Company’s bonds, and routine general and
administrative expenses. These charges have been offset by the gross margin on Atrush oil sales, interest income on
Atrush cost loans and interest on cash held in short term deposits. The principal changes in annual financial
information are further explained in the sections below.
5
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 expenses and income items of operations are explained
in detail as follows:
Gross margin on oil sales
In $000
Revenues from Atrush oil sales
Lifting costs
Other costs of production
Depletion costs
Cost of goods sold
Gross margin on oil sales
Three months ended December 31,
2016
2017
Year ended December 31,
2016
2017
13,907
(3,245)
(834)
(5,347)
(9,426)
4,481
‐
‐
‐
‐
‐
‐
17,689
(5,547)
(834)
(7,628)
(14,009)
3,680
‐
‐
‐
‐
‐
‐
Revenues relate to the Company’s entitlement share of oil sales from Atrush for the year. 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. The fair value 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 has 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, 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.
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.
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 volumes from Atrush in 2017 were 3.4 MMbbl and the Company’s
entitlement share was approximately 0.4 MMbbl which were sold with an average netback price of $44.38 per barrel.
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 which
are based on Dated Brent oil price with a discount for estimated oil quality adjustments and all local and international
transportation costs.
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 cost per barrel of oil produced from Atrush was, respectively, $8.09 and $8.27 in the three
and six months ended December 31, 2017. Other costs of production include the Company’s share of production
bonuses paid to the KRG 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, respectively, $19.14 and $18.10 for the three and six months ended
December 31, 2017. Changes to depletion rates resulting from changes in reserve quantities and estimates of future
development expenditure are reflected prospectively and the decrease in the depletion cost in the fourth quarter of
2017 reflects the increase to the Company’s entitlement share of estimated 2P reserves as at December 31, 2017
over the estimated quantities at the end of 2016 (for further information refer to the “Reserves and Resource” section
below).
6
The relatively low gross margin on oil sales in the second half of 2017 is explained by two limiting factors on revenue
entitlements to this point ‐ production for the period was below facility capacity which was in full operation over the
period and disproportionate cost oil revenue was distributed between TAQA and GEP under the JOA4. The result was
that the Company’s share of entitlement revenues in this period were below the Company’s 20.1% participating
interest share and therefore just sufficient to offset the Company’s full working interest share of lifting costs, which
are primarily fixed, and depletion costs, which are driven by entitlement production.
Service fee income
In $000
Service fee income
Three months ended December 31,
2016
2017
Year ended December 31,
2016
2017
‐
‐
‐
120
During the year ended December 31, 2016 the Company has provided technical services to a third‐party petroleum
company. That service was complete in September of 2016.
General and administrative expense
In $000
Salaries and benefits
Management and consulting fees
General and other office expenses
Legal, accounting and audit fees
Listing costs and investor relations
Travel expenses
Advertisements
General and administrative expense
Three months ended December 31,
2016
2017
Year ended December 31,
2016
2017
503
121
106
102
56
43
35
966
512
101
80
16
49
47
‐
805
3,093
372
331
242
286
152
35
4,511
2,360
421
341
269
298
122
‐
3,811
The higher general and administrative expense incurred in the year 2017 relative to the amount incurred in 2016 was
principally due to higher payroll costs relating to salary bonuses incurred by the Company’s Swiss subsidiary which
was offset by lower management and consulting fees, relating to a reduction in service fees in respect of the
Company’s Swiss subsidiary, and the absence of once‐off legal fees incurred last year on bond refinancing.
Share based payments expense
In $000
Three months ended December 31,
2016
2017
Year ended December 31,
2016
2017
Share based payments expense
‐
57
11
249
The share based payments expense results from the vesting of stock options granted in the year 2015. No stock
options were granted in the year ended December 31, 2017 or in the year 2016. 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.
4 TAQA and GEP have 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 receives the initial $10.8 million and GEP receives the next $39.1 million, thereafter cost oil revenues for these two
parties is determined by their relative participating interests in the Arush PSC. The Company’s entitlement share of oil sold in 2017 reflects a
recovery of approximately $9.2 million of the $39.1 million. The Company forecasts that its entitlement to the remaining $29.9 million of priority
recovery will occur in January to April of 2018 assuming average Atrush exports of 27,000 bopd over that period.
7
Depreciation and amortisation expense
In $000
Three months ended December 31,
2016
2017
Year ended December 31,
2016
2017
Depreciation and amortisation expense
‐
11
26
45
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
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
Three months ended December 31,
2016
2017
Year ended December 31,
2016
2017
242
106
13
361
‐
361
406
34
5
445
64
509
1,042
500
107
1,649
‐
1,649
406
34
44
484
‐
484
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 of 2017 represent 7% per annum interest on the entire funded portion of
Atrush Feeder Pipeline costs up to the balance sheet date and on a defined portion of the Atrush development costs
which also bears interest at 7% per annum. 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 and investments held in interest bearing funds. The
increase in interest income reported in the year ended December 31, 2017 relative to the amount reported in 2016
is due to a higher level of interest bearing funds held in 2017.
Finance cost
In $000
Three months ended December 31,
2016
2017
Year ended December 31,
2016
2017
Interest charges on bonds at coupon rate
Amortisation of bond transaction costs
Interest expense on borrowings
Unwinding discount on decommissioning provision
Foreign exchange loss
Total finance costs before borrowing costs capitalised
Borrowing costs reversed from / (capitalised as) E&E
and PP&E assets
Finance cost
5,221
210
5,431
4
83
5,518
284
5,802
4,668
210
4,878
6
‐
4,884
(3,462)
1,422
20,018
841
20,859
4
102
20,965
(8,770)
12,195
17,951
943
18,894
68
‐
18,962
(13,376)
5,586
General and specific borrowing costs directly attributable to the acquisition, exploration and development of Atrush
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. The decrease in 2017 borrowing costs capitalised relative to the
total interest expense on borrowings compared to that of the prior year is due to expensing the pro‐rata portion of
borrowing costs related to Atrush production costs which commenced in July 2017. The Company reversed excess
borrowing costs capitalised up to the end of the third quarter of 2017 which has resulted in a credit to PP&E for the
fourth quarter of this year.
During the year ended December 31, 2017 the Company incurred interest expense relating to its Senior Bonds and
Super Senior Bonds which both carry an 11.5% fixed semi‐annual coupon interest rate. Interest expense on
borrowings increased over the amount reported in 2016 due to the additional bonds outstanding in the year resulting
from the issuance of PIK bonds in 2017. Refer also to the discussion in the section below entitled “Borrowings”.
8
The foreign exchange loss recorded in the year 2017 resulted primarily from holding in the Company’s Swiss subsidiary
net assets denominated in United States dollars while the USD weakened during the period against the Swiss Franc,
the functional currency of the Swiss subsidiary.
Income tax expense
In $000
Three months ended December 31,
2016
2017
Year ended December 31,
2016
2017
Income tax expense
14
14
85
69
Income tax expense relates to provisions for income taxes on service income generated in Switzerland which is
determined on the basis of costs incurred in procuring the services. The increase in tax expense from the amount
reported in 2016 is primarily due to higher taxable income in the Company’s Swiss subsidiary which increased
compared to 2016 because of higher costs of service.
Capital Expenditures on Property Plant & Equipment (“PP&E”)
The net book value of PP&E at December 31, 2017 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, 2017
Office
equipment
Oil and gas
assets
Total
Year ended December 31, 2016
Office
equipment
Oil and gas
assets
Total
Opening net book value
Additions
Transfer to Atrush Development Cost Loan
Transfer to Atrush Expl. Costs receivable
Depletion and depreciation expense
Net book value
174,642
17,903
‐
‐
(7,627)
184,918
16
3
‐
‐
(16)
3
174,658
17,906
‐
‐
(7,643)
184,921
177,000
45,799
(10,682)
(37,475)
‐
174,642
44
1
‐
‐
(29)
16
177,044
45,800
(10,682)
(37,475)
(29)
174,658
During the year of 2017 additions of $17.9 million (year 2016: $45.8 million), which included borrowing costs totalling
$8.8 million (year 2016: $13.1 million), were capitalised to PP&E and depletion of $7.6 million (year 2016: $nil) was
charged to PP&E.
Capital Expenditures on Intangible Assets
The net book value of Intangible assets at December 31, 2017 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
Disposals
Amortisation expense
Net book value
Year ended December 31, 2017
E&E
assets
Software
& Licences
Total
88,972
141
‐
‐
89,113
35
2
(21)
(10)
6
89,007
143
(21)
(10)
89,119
Year ended December 31, 2016
Software
E&E
& Licences
assets
Total
88,594
378
‐
‐
88,972
51
‐
‐
(16)
35
88,645
378
‐
(16)
89,007
During the year of 2017 additions of $143 thousand (2016: $378 thousand), which included borrowing costs of $16
thousand (2016: $277 thousand), were capitalised to E&E assets.
9
Loans and receivables
On November 7, 2016, the 4th PSC Amendment and Atrush Facilitation Agreement were concluded between the Non‐
Government Contractors and the KRG. On the same day TAQA entered into an Engineering, Procurement and
Construction (“EPC”) contract with KAR Company for the construction of the feeder pipeline from the Atrush block
boundary to the tie‐in point with the main Kurdistan export pipeline (the “Feeder Pipeline”).
Under the terms of the 4th PSC Amendment and Atrush Facilitation Agreement:
The KRG acquires a 25% interest in the Atrush PSC effective November 7, 2012, the date of declaration of
commerciality (“DOC date”). Consequently, the respective participating interests in the Atrush PSC are TAQA at
39.9%, the KRG at 25%, GEP at 20.1% and MOKDV at 15%;
All Atrush petroleum costs from the DOC date through the commencement of oil exports from Atrush are paid by
the Non‐Government Contractors and a defined portion of the KRG’s share of these costs are deemed Exploration
Costs as defined in the Atrush PSC and repaid through an accelerated petroleum cost recovery arrangement from
the sale of future oil production from Atrush. This arrangement has resulted in the Atrush Exploration Cost
receivable at year end as reported in the table below; and
The Non‐Government Contractors will fund the cost of constructing the Feeder Pipeline which will be novated to
the KRG following the commencement of oil exports from Atrush. The Feeder Pipeline costs and the balance of
the Atrush petroleum costs incurred by the Non‐Government Contractors on behalf of the KRG excluding the
portion deemed as Exploration Costs will be repaid with interest at 7% per annum by the KRG within 2 years from
October 31, 2017 (respectively, the “Atrush Feeder Pipeline Cost Loan” and the “Atrush Development Cost Loan”).
These arrangements have resulted in loan balances at year end as reported in the table below.
In $000
As at December 31,
Atrush Exploration Costs receivable
Atrush Development Cost Loan
Accounts receivable on Atrush oil sales
Atrush Feeder Pipeline Cost Loan
Total loans and receivables
2017
37,247
16,018
13,957
9,751
76,973
2016
37,475
12,857
‐
3,034
53,366
In the last three months of 2017 the Company received $4.0 million in total payments for its entitlement share Atrush
production for July through September and reimbursement instalments on the Atrush Exploration Costs receivable.
In January 2018 the Non‐Government Contractors and the KRG agreed that substantially all the first two instalments
on the Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost Loan, which were due in November and
December of 2017, would be offset against amounts owed to the KRG for security services, which they provided for
the Atrush operations, and an Atrush production bonus. The total loan balances offset against amounts owed to the
KRG as of the balance sheet date due to the agreement was $2.6 million.
In the year 2018 up to the date these financial statements were approved the Company received a total of $5.1 million
in payments for loans and receivables balances outstanding at December 31, 2017 comprised of $4.8 million in total
payments for its entitlement share of oil sales for the months October and November and $0.3 million in
reimbursements of the Atrush Exploration Costs receivable.
Borrowings
At December 31, 2017 General Exploration Partners, Inc. had outstanding $166.3 million of senior secured bonds
(“Senior Bonds”) and $20.2 million of super senior secured bonds (“Super Senior Bonds”). The Senior Bonds are listed
on the Oslo Børs in Norway under the symbol “GEP01”, have a five‐year maturity from their issuance date of
November 13, 2013 and carry an 11.5% fixed semi‐annual coupon and were used to fund capital expenditures related
to the development of the Atrush Block. The Super Senior Bonds also mature on November 13, 2018, carry an 11.5%
fixed semi‐annual coupon and were used to fund capital expenditures related to the development of the Atrush Block.
GEP has the option to pay in cash or in kind by issuing new bonds (“PIK Bonds”) the remaining coupon interest on
both Senior and Super Senior bonds.
10
All the movements in borrowings during the year were non‐cash and are explained as follows:
In $000
As at December 31,
Opening balance
Interest charges at coupon rate
Bonds issued
Amortisation of bond transaction costs
Super Senior Bonds – net of transaction costs
Senior Bonds exchanged for ShaMaran common shares
Interest payments to bondholders
Ending balance
‐ Current portion: accrued bond interest expense
‐ Current portion: borrowings
‐ Non‐current portion: borrowings
2017
167,632
20,018
19,721
841
‐
‐
(19,721)
188,491
2,799
185,692
‐
2016
150,515
17,951
17,700
943
16,223
(18,000)
(17,700)
167,632
2,503
‐
165,129
The remaining contractual obligations comprising of repayment of principal and interest expense under the Bond
agreements, based on undiscounted cash flows at payment dates and assuming 2018 interest is paid in cash, are as
follows:
Less than one year
Between one and two years
Total
Debt Incurrence Tests
As at December 31,
2017
207,860
‐
207,860
2016
19,722
188,138
207,860
In accordance with the amended terms of GEP’s Senior Bonds and Super Senior Bonds agreements ShaMaran is
required to follow certain debt incurrence tests as follows:
1.
upon incurrence of any new financial indebtedness, other than certain permitted financial indebtedness as
described in the Super Senior Bonds agreement, then ShaMaran’s Book Equity Ratio, which is defined as
shareholders’ equity divided by total assets, shall be minimum 30% immediately thereafter, and
ShaMaran and any of its subsidiaries (together the “Group”) other than GEP, which is not allowed to do so, may
not enter into an agreement to make any acquisitions, merger or any other transactions involving another party
being consolidated into the Group’s accounts, unless such other party has a minimum 30% Book Equity Ratio
prior to such transaction taking place.
2.
Security
The Senior Bonds and Super Senior Bonds hold security jointly with Super Senior Bonds ranking first until these bonds
are repaid in full.
The bonds include an unconditional and irrevocable on‐demand guarantee on a joint and several basis from the
Company and certain of the Company’s direct and indirect subsidiaries and, among other arrangements, agreements
which pledge all of the ordinary shares of GEP and the Company’s Swiss service subsidiary, ShaMaran Services SA, as
security for GEP’s bond related obligations, as well as an internal credit facility agreement among the Company and
certain of its subsidiaries setting out the terms and conditions for intra‐group credit to be made available amongst
the parties.
Under the terms of both bond agreements GEP’s cash accounts are pledged to the bond trustee as security and cash
may be employed only for prescribed purposes, to fund the financing, development and operation of the Atrush Block
and to fund technical, management and administrative services of ShaMaran’s subsidiary companies up to $6 million
per year over the term of the bonds. Of the Company’s $5.3 million of total cash and cash equivalents at December
31, 2017 (2016: $4.4 million) $2.2 million was held in GEP’s restricted accounts (December 31, 2016: $nil).
In the year ended December 31, 2017 PIK Bonds of $17.6 million and $2.1 million were issued under the Senior Bonds
and Super Senior Bonds agreements, respectively, to pay semi‐annual coupon interest which came due in the year
ended December 31, 2017.
11
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
Service fee income
General and admin. expense
Share based payments expense
Depreciation and amortisation
Finance cost
Finance income
Income tax expense
Dec 31
2017
Sep 30
2017
For the quarter ended
Dec 31
2016
Mar 31
2017
Jun 30
2017
Sep 30
2016
Jun 30
2016
Mar 31
2016
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)
‐
‐
‐
(805)
(57)
(11)
(1,422)
509
(14)
‐
‐
90
(695)
(58)
(12)
(1,393)
16
(14)
‐
‐
30
(1,009)
(58)
(11)
(1,443)
12
(15)
‐
‐
‐
(1,302)
(76)
(11)
(1,402)
21
(26)
Net loss
(1,940)
(5,393)
(1,883)
(2,283)
(1,800)
(2,066)
(2,494)
(2,796)
Basic and diluted net
loss in $ per share
(0.001)
(0.002)
(0.001)
(0.001)
(0.001)
(0.001)
(0.001)
(0.002)
Summary of Principal Changes in the Fourth Quarter Financial Information
In the fourth quarter of 2017 production from the Atrush Block and work on the Atrush development program
continued. The net loss was primarily driven by a negative margin on Atrush oil sales resulting principally from six
months of full operating costs during production ramp up, general and administrative expenses and finance cost, the
substantial portion of which were expensed borrowing costs on the Company’s Senior Bonds and Super Senior Bonds.
These expenses have been slightly offset by interest income on Atrush cost loans to the KRG and interest on cash held
in short term deposits.
LIQUIDITY AND CAPITAL RESOURCES
Working capital at December 31, 2017 was negative $155.6 million compared to $3.0 million at December 31, 2016.
As explained in the Company’s cash flow statement during the year 2017 the overall cash position of the Company
increased by $0.8 million compared to a decrease in cash of $27.5 million during the year 2016. The main components
of the movement in funds are discussed in the following paragraphs.
The operating activities of the Company during the year 2017 resulted in a decrease in the cash position of $8.8 million
compared to a decrease of $6.9 million in the cash position in the prior year. The decrease in the cash position is
explained by a net loss of $11.5 million which was offset by $2.68 million of net positive cash adjustments from
working capital items and non‐cash expenses.
Net cash outflows to investing activities in 2017 were $16.7 million compared to cash outflows of $36.8 million last
year. Substantially all the cash outflows to investing activities in 2017 relate to investment in the Atrush Block
development work program, and was comprised of $8.6 million in respect of the Company’s participating interest in
the development program relating to the Atrush PSC and $8.1 million in respect of loans to the KRG to fund a portion
of the Atrush Feeder Pipeline and other Atrush development costs. Offsetting these investment cash outflows were
cash inflows of $2.8 million in loan repayments by the KRG and interest payments on interest bearing cash and
investments.
The Company had net cash inflows of $26.4 million from financing activities in 2017 compared to $16.2 million in the
comparable period in 2016. The cash inflows relate entirely to the issuance of common shares of the Company
pursuant to the Private Placement conducted in January 2017. Refer also to the discussion above under the
“Outstanding Share Data and Stock Options” section of this MD&A.
12
At December 31, 2017 ShaMaran held cash and cash equivalents of $5.3 million, of which an amount of $2.2 million
was restricted under the Company’s bond agreements. Combined cash flows from management forecasts of Atrush
oil sales, spending on Atrush development, bond coupon interest and technical and administrative costs in support
of Atrush operations is projected to result in net cash inflows of $32 million for the 12 months ended December 31,
2018. The oil sales volume assumptions reflect production at a rate of 27,000 barrels of oil per day in 2018, which is
consistent with Atrush production rates up to the date these financial statements were approved, and that all crude
oil produced from Atrush will be delivered, sold and paid for in accordance with the terms of the Atrush PSC and
collected within three months following the month of production. The forecasted revenue cash flows are based on
Dated Brent forward contract prices as of the balance sheet date and a $15.73 discount for transportation costs and
oil quality differentials consistent with the agreement for the sale of Atrush oil exports between the Atrush Non‐
Government Contractors and the KRG. The timing and extent of Atrush development costs is based on the Operator’s
latest forecasts for the Atrush work program while the technical and administrative support costs are management’s
latest estimates for these forthcoming requirements.
The Company is considering alternatives for refinancing its $186 million of outstanding bonds and is confident that it
will secure sufficient funding before the bonds mature in November 2018. Accordingly, the $32 million of projected
2018 cash inflows does not include any cash outflows associated with repayment of the maturing bond principal.
Should there be 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 in the next 12 months to fund the forecasted Atrush operating and
development costs thereafter. Failure to meet development commitments could put the Atrush PSC and the
Company’s bond agreements at risk of forfeiture.
In case the Company could not secure external financing in sufficient amount and in time to meet its obligations as
they come due, the Company may be required to take measures such as divestment of assets and or further
renegotiation of its existing debt. Should this not be successful, there is a risk that the Company would be subject to
a partial or complete reorganization, or that the Company is declared bankrupt. The potential that the Company’s
financial resources are insufficient to fund its appraisal, development and production activities for the next 12
months, particularly in case the Company is unable to finance the maturing bonds when they come due and or there
are any unforeseen delays in receipt of funds from oil sales, indicates a material uncertainty which may cast significant
doubt over the Company’s ability to continue as a going concern.
OUTSTANDING SHARE DATA AND STOCK OPTIONS
On January 30, 2017 the Company completed the issue of 360 million common shares of ShaMaran on a private
placement basis (the “Private Placement”) at a price per share of CAD 0.10 (equal to SEK 0.67) which resulted in gross
proceeds to the Company of $27.3 million ($26.4 million net of transaction related costs). Zebra Holdings and
Investments SARL, Lorito Holdings SARL and Lundin Petroleum BV, the Company’s major shareholders, subscribed for
43,463,618 shares, 16,984,621 shares and 17,800,000 shares, respectively, in the Private Placement.
The Company had 2,158,631,534 outstanding shares at December 31, 2017 and at the date of this MD&A.
At December 31, 2017 there were 28,165,000 stock options outstanding under the Company’s employee incentive
stock option plan, there is no change from the stock options outstanding at December 31, 2016. No stock options
were forfeited or exercised in 2017 (2016: 25,000 expired). There has been no further movement in stock options
from December 31, 2017 to the date of this MD&A.
The Company has no warrants outstanding.
OFF BALANCE SHEET ARRANGEMENTS
The Company has no off‐balance sheet arrangements.
13
RELATED PARTY TRANSACTIONS
In $000
Purchases of services during the year
Amounts owing at December 31,
Lundin Petroleum AB
Namdo Management Services Ltd.
McCullough O’Connor Irwin LLP
Total
2017
2016
2017
2016
204
50
45
299
299
99
44
442
18
‐
‐
18
24
1
‐
25
The Company receives services from various subsidiary companies of Lundin Petroleum AB (“Lundin”), a shareholder
of the Company. Lundin charges during the year ended December 31, 2017 of $204 (2016: $299) were comprised of
office rental, administrative and building services of $177 (2016: $268), investor relations services of $26 (2016: $28)
and technical service costs of $1 (2016: $3).
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.
McCullough O’Connor Irwin LLP is a law firm in which an officer of the Company is a partner and has provided legal
services to the Company.
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
ShaMaran holds a 20.1% direct interest in the Atrush PSC through GEP. TAQA is the Operator with a 39.9% direct
interest, the KRG holds a 25% direct interest and MOKDV holds a 15% direct interest. Under the terms of the 4th PSC
Amendment and the 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 the commencement of oil
exports from Atrush. Thereafter these costs will be reimbursed to the Non‐Government Contractors.
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.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, 2017 the outstanding commitments of the Company were as follows:
In $000
For the year ended December 30,
Atrush Block development
Office and other
Total commitments
2018
32,657
40
32,697
2019
120
‐
120
2020
Thereafter
120
‐
120
1,448
‐
1,448
Total
34,345
40
34,385
Amounts relating to Atrush Block development represent the Company’s unfunded paying interest share of the
approved 2018 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: $8.3
million at 10 million barrels (ShaMaran share: $2.2 million); $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
The Company had no transactions pending at the date of this MD&A. However, as part of its normal business, the
Company continues to evaluate 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.
New Accounting Standards
There are no IFRS or interpretations that have been issued effective for financial years beginning on or after January 1,
2017 that would have a material impact on the Company’s consolidated financial statements.
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 9: Financial Instruments ‐ Classification and Measurement, will replace IAS 39 “Financial Instruments: Recognition
and Measurement”. IFRS 9 introduces a revised model for classification and measurement, a forward‐looking
“expected loss” impairment model and a substantially reformed approach to hedge accounting. IFRS 9 is effective for
annual periods beginning on or after January 1, 2018, with earlier adoption permitted. The Company plans to adopt
the standard beginning January 1, 2018. The Company has reviewed its financial assets and liabilities and has made
the following conclusions from the adoption of the new standard on January 1, 2018:
There will be no impact on the Company’s accounting for financial liabilities, as the new requirements only affect
the accounting for financial liabilities that are designated at fair value through profit or loss and the Group does
not have any such liabilities. The derecognition rules have been transferred from IAS 39 Financial Instruments:
Recognition and Measurement and have not been changed.
The new hedge accounting rules will align the accounting for hedging instruments more closely with risk
management practices. The Company currently has no hedging instruments.
The new impairment model requires the recognition of impairment provisions based on expected credit losses
(ECL) rather than only incurred credit losses as is the case under IAS 39. It applies to financial assets classified at
amortised cost, debt instruments measured at Fair Value through other comprehensive income (FVOCI), contract
assets under IFRS 15, lease receivables, loan commitments and certain financial guarantee contracts. Based on
the assessments undertaken to date, the Company expects that there will be no resulting material changes to
the trade debtor amounts reported in its financial statements.
IFRS 15: Revenue from contracts with customers is the new standard which replaces IAS 18 Revenue and IAS 11
Construction Contracts and provides a five‐step framework for application to customer contracts; identification of
customer contracts, identification of the contract performance obligations, determination of the contract price,
allocation of the contract price to the contract performance obligations, and revenue recognition as performance
obligations are satisfied. A new requirement where revenue is variable stipulates that revenue may only be recognised
to the extent that it is highly probable that significant reversal of revenue will not occur. The Company plans to adopt
the new standard when it comes into effect for reporting periods following January 1, 2018. The Company has
assessed the impact of implementing IFRS 15 and anticipates that it will not have a material effect on its financial
statements
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.
15
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.
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.
16
RESERVES AND RESOURCE ESTIMATES
The Company engaged McDaniel to evaluate 100% of the Company’s reserves and resource data at December 31,
2017. 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, 2017 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, 2017
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)
4,211
2,975
‐
‐
3,026
1,673
282
181
7,237
4,648
12,385
6,347
282
181
745
394
19,622
10,996
1,026
575
12,020
31,641
3,999
14,995
685
236
1,711
811
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, 2017 were estimated to be as
follows, based on a Company working interest of 20.1 percent in the Atrush Block:
Company estimated contingent resources (diluted) (1) (2)(4)(5)
As of December 31, 2017
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
13,627
13,820
15,398
11,056
21,479
45,710
74,948
36,568
5,121
9,426
14,769
471
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 further field appraisal and Phase 1 production performance.
Prospective resources have not been re‐evaluated since December 31, 2013.
17
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 appraisal and development stages and, as such, additional information must be
obtained by further appraisal 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
produce 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.
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.
Loans and receivables comprise of other 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.
18
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.
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.
The Group is highly leveraged though financing at the project level, for the continuation of Atrush project, and at the
corporate level due to GEP’s outstanding Senior Bonds and Super Senior Bonds. However, the Company is not exposed
to interest rate risks associated with the bonds as the interest rate is fixed.
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.
19
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.
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.
Events in Kurdistan since the independence referendum held on September 25, 2017 have reduced the autonomy of
Kurdistan Regional Government in favour of the Iraq federal government, in particular, to control and manage entry
into, and exit from, Kurdistan of people, goods and services. There is a risk that the level of authority of the KRG, and
corresponding systems previously in place, continue to 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.”
20
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 Corporation'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.
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.
21
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 2018 full payments for November 2017 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.
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.
22
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
industry
implemented health, safety and environment policies since
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.
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 development: ShaMaran has conducted oil and gas exploration and development activities in
Kurdistan for approximately seven years. The current operations are in an appraisal and development 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.
23
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. ShaMaran’s operations to date have been primarily financed by debt and equity financing. The
Company’s future operations are dependent upon 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 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.
Uncertainty in financial markets: In the future the Company is expected to require financing to grow its business. The
uncertainty which has periodically affected the financial markets in recent years 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 GEP’s Senior Bonds and Super Senior Bonds
Possible termination of Atrush PSC / bond agreements in event of default scenario: Should GEP default its
obligations under either of the bond agreements GEP 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 GEP
default its obligations under the Atrush PSC and or Atrush JOA, with the effect that these contracts may be terminated
or limited, GEP may also default in respect of its obligations under the bond agreements. 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.
24
Ability to service indebtedness: GEP’s ability to make scheduled payments on or to refinance its obligations under
the bond agreements will depend on GEP’s financial and operating performance which, in turn, will be subject to
prevailing economic and competitive conditions beyond GEP’s control. It is possible that GEP’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 agreements.
Significant operating and financial restrictions: The terms and conditions of the bond agreements contain restrictions
on GEP’s and the Guarantors’ activities which restrictions may prevent GEP and the Guarantors from taking actions
that it believes would be in the best interest of GEP’s business, and may make it difficult for GEP 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 GEP is unable to comply with the
terms of the bond agreements. A breach of any of the covenants and restrictions could result in an event of default
under the bond agreements.
Mandatory prepayment events: Under the terms of the bond agreements the bonds are subject to mandatory
prepayment by GEP on the occurrence of certain specified events, including if (i) the ownership in the Atrush Block is
reduced to below 20.10% (ii) ShaMaran Petroleum Corp. ceases to indirectly own, or ShaMaran Ventures B.V. ceases
to directly own, 100% of the shares in GEP (iii) GEP invests in any assets or enters into any other activities unrelated
to the Atrush PSC or (iv) an event of default occurs under either of the bond agreements. Following an early
redemption after the occurrence of a mandatory prepayment event, it is possible that GEP 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 agreements.
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.
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, 2017, 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.
25
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 .
26
ShaMaran Petroleum Corp.
Audited Consolidated Financial Statements
For the year ended December 31, 2017
27
9 March 2018
Independent Auditor’s Report
To the Shareholders of ShaMaran Petroleum Corp.
We have audited the accompanying consolidated financial statements of ShaMaran Petroleum Corp., which
comprise the Consolidated Balance Sheet as at 31 December 2017 and 31 December 2016 and the Consolidated
Statement of Comprehensive Income, Consolidated Statement of Changes in Equity and Consolidated
Statement of Cash Flows for the years ended 31 December 2017 and 31 December 2016, and the related notes
including a summary of significant accounting policies.
Management’s responsibility for the consolidated financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements
in accordance with International Financial Reporting Standards, 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.
Auditor’s responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We
conducted our audits in accordance with Canadian Generally Accepted Auditing Standards. Those standards
require that we comply with ethical requirements and plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the
assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud
or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s
preparation and fair presentation of the consolidated financial statements 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 entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used
and the reasonableness of accounting estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a
basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the Consolidated
Balance Sheet of ShaMaran Petroleum Corp. as at 31 December 2017 and 31 December 2016 and its financial
performance and its cash flows for the years ended 31 December 2017 and 31 December 2016 in accordance
with International Financial Reporting Standards.
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.
28 Emphasis of matter – going concern
Without qualifying our opinion, we draw attention to Note 2 in the financial statements which describes
matters and conditions that indicate the existence of a material uncertainty that may cast significant doubt
about the corporation's ability to continue as a going concern.
PricewaterhouseCoopers SA
Luc Schulthess
LLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLLucucucucuc ScScScScSSSScSSSSSSSSSS hhuhuhuhuhultltltltlthehehehehessssssssss
Colin Johnson
CoCoCoCoColililililin nnnn JoJoJoJoJohnhnhnhnhnhhhhhhhhhhhhhhhhnnsososososonnnnn
29 SHAMARAN PETROLEUM CORP.
Consolidated Statement of Comprehensive Income
(Expressed in thousands of United States dollars, except for per share data)
______________________________________________________________________________
Revenues
Cost of goods sold:
Lifting costs
Other costs of production
Depletion
Gross margin on oil sales
Service fee income
Share based payments expense
Depreciation and amortisation expense
General and administrative expense
Loss from operating activities
Finance income
Finance cost
Net finance cost
Loss before income tax expense
Income tax expense
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:
Actuarial (loss) / gain on defined pension plan
Total other comprehensive income
Note
6
7
7
7
8
9
10
For the year ended December 31,
2016
2017
17,689
(5,547)
(834)
(7,628)
3,680
‐
(11)
(26)
(4,511)
(868)
1,649
(12,195)
(10,546)
(11,414)
(85)
(11,499)
31
(13)
18
‐
‐
‐
‐
‐
120
(249)
(45)
(3,811)
(3,985)
484
(5,586)
(5,102)
(9,087)
(69)
(9,156)
22
15
37
Total comprehensive loss for the year
(11,481)
(9,119)
Loss in dollars per share:
Basic and diluted
17
(0.01)
(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)
______________________________________________________________________________
As at December 31,
Note
2017
2016
Assets
Non‐current assets
Property, plant and equipment
Intangible assets
Loans and receivables
Current assets
Loans and receivables
Cash and cash equivalents, unrestricted
Cash and cash equivalents, restricted
Other current assets
Total assets
Liabilities and equity
Current liabilities
Borrowings
Accounts payable and accrued expenses
Accrued interest expense on bonds
Non‐current liabilities
Provisions
Pension liability
Borrowings
Total liabilities
Equity
Share capital
Share based payments reserve
Cumulative translation adjustment
Accumulated deficit
Total equity
Total liabilities and equity
11
12
13
13
15
15
14
15
16
19
15
17
184,921
89,119
44,696
318,736
32,277
3,094
2,162
212
37,745
356,481
185,692
4,827
2,799
193,318
9,427
1,781
‐
11,208
204,526
637,538
6,495
(30)
(492,048)
151,955
356,481
174,658
89,007
46,114
309,779
7,252
4,416
‐
224
11,892
321,671
‐
6,434
2,503
8,937
8,869
1,670
165,129
175,668
184,605
611,179
6,484
(61)
(480,536)
137,066
321,671
The accompanying Notes are an integral part of these consolidated financial statements.
Signed on behalf of the Board of Directors:
/s/Ashley Heppenstall
C. Ashley Heppenstall, 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
capital
Share based
payments
reserve
Cumulative
translation
adjustment
Accumulated
deficit
Total
Balance at January 1, 2016
593,179
6,235
(83)
(471,395)
127,936
Total comprehensive loss for the year:
Loss for the year
Other comprehensive income
‐
‐
‐
Transactions with owners in their capacity as owners:
Share based payments expense
Shares issued
‐
18,000
18,000
‐
‐
‐
249
‐
249
‐
22
22
‐
‐
‐
(9,156)
15
(9,141)
‐
‐
‐
(9,156)
37
(9,119)
249
18,000
18,249
Balance at December 31, 2016
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
‐
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
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,
2016
2017
9
Operating activities
Loss for the year
Adjustments for:
Interest expense on borrowings – net
Depreciation, depletion and amortisation expense
Foreign exchange loss
Share based payments expense
Unwinding discount on decommissioning provision
Actuarial (loss) / gain on pension plan
Interest income
Changes in pension liability
Changes in other current assets
Changes in current tax liabilities
Changes in accounts payable and accrued expenses
Changes in accounts receivables on Atrush oil sales
Net cash outflows to operating activities
Investing activities
Loans and receivables – payments received
Interest received on cash deposits
Purchases of intangible assets
Purchase of property, plant and equipment
Loans and receivables – payments issued
Net cash outflows to investing activities
Financing activities
Proceeds from shares issued
Share issue related transaction costs
Proceeds from shares issued
Bond transaction costs
Net cash inflows from financing activities
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
15
(11,499)
12,089
7,654
102
11
4
(13)
(1,649)
37
12
‐
(1,607)
(13,957)
(8,816)
2,806
107
(82)
(8,621)
(10,914)
(16,704)
27,281
(922)
‐
‐
26,359
1
840
4,416
5,256
2,162
(9,156)
5,518
45
‐
249
68
15
(484)
(18)
(24)
(31)
(3,126)
‐
(6,944)
‐
44
(7)
(32,073)
(4,769)
(36,805)
‐
‐
17,000
(777)
16,223
21
(27,505)
31,921
4,416
‐
The accompanying Notes are an integral part of these consolidated financial statements.
33
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(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 Suite 2600 Oceanic Plaza,
1066 West Hastings Street, Vancouver, British Columbia V6E 3X1. 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, 2017, under the historical cost convention. The significant
accounting policies of the Company have been applied consistently throughout the year. The policies applied in these
financial statements are based on IFRS which were outstanding and effective as of March 8, 2018, 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 into the foreseeable future its assets and liabilities in the normal course of business
as they come due. Management has applied significant judgment in preparing forecasts supporting the going concern
assumption. Specifically, management has made assumptions regarding projected oil sale volumes and pricing, and
the timing and extent of capital, operating, and general and administrative expenditures.
At December 31, 2017 ShaMaran held cash and cash equivalents of $5.3 million, of which an amount of $2.2 million
was restricted under the Company’s bond agreements. Combined cash flows from management forecasts of Atrush
oil sales, spending on Atrush development, bond coupon interest and technical and administrative costs in support of
Atrush operations is projected to result in net cash inflows of $32 million for the 12 months ended December 31,
2018. The oil sales volume assumptions reflect production at a rate of 27,000 barrels of oil per day in 2018, which is
consistent with Atrush production rates up to the date these financial statements were approved, and that all crude
oil produced from Atrush will be delivered, sold and paid for in accordance with the terms of the Atrush PSC and
collected within three months following the month of production. The forecasted revenue cash flows are based on
Dated Brent forward contract prices as of the balance sheet date and a $15.73 discount for transportation costs and
oil quality differentials consistent with the agreement for the sale of Atrush oil exports between the Atrush Non‐
Government Contractors and the Kurdistan Regional Government (“KRG”). The timing and extent of Atrush
development costs is based on the Operator’s latest forecasts for the Atrush work program while the technical and
administrative support costs are management’s latest estimates for these forthcoming requirements.
The Company is considering alternatives for refinancing its $186 million of outstanding bonds and is confident that it
will secure sufficient funding before the bonds mature in November 2018. Accordingly, the $32 million of projected
2018 cash inflows does not include any cash outflows associated with repayment of the maturing bond principal.
Should there be 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 in the next 12 months to fund the forecasted Atrush operating and
development costs thereafter. Failure to meet development commitments could put the Atrush PSC and the
Company’s bond agreements at risk of forfeiture.
34
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
In case the Company could not secure external financing in sufficient amount and in time to meet its obligations as
they come due, the Company may be required to take measures such as divestment of assets and or further
renegotiation of its existing debt. Should this not be successful, there is a risk that the Company would be subject to
a partial or complete reorganization, or that the Company is declared bankrupt. The potential that the Company’s
financial resources are insufficient to fund its appraisal, development and production activities for the next 12 months,
particularly in case the Company is unable to finance the maturing bonds when they come due and or there are any
unforeseen delays in receipt of funds from oil sales, indicates a material uncertainty which may cast significant doubt
over the Company’s ability to continue as a going concern. These consolidated financial statements do not include the
adjustments that would result if the Company is unable to continue as a going concern.
Refer also to Notes 15 and 21.
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.
(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.
35
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
(d) Non‐current assets held for sale and discontinued operations
Non‐current assets (or disposal groups) are classified as assets held for sale when their carrying amount is to be
recovered principally through a sale transaction and a sale is considered highly probable. They are measured at the
lower of carrying amount and fair value less costs to sell.
The results of a component of the Company that represent a major line of business or geographical area of operations
that has either been disposed of (by sale, abandonment or spin‐off) or is classified as held for sale is reported as
discontinued operations. The financial statements of the Company include amounts and disclosures pertaining to
discontinued operations in accordance with IFRS 5 Non‐current Assets Held for Sale and Discontinued Operations.
(e) 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.
(f) 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.
36
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
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 less accumulated amortisation and are subject to
the impairment test set out below. Such E&E assets are depreciated on a unit of production basis over the life of the
commercial reserves attributed to the cost pool to which they relate.
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
(g) 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.
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
37
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
(h)
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.
(i)
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.
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.
Loans and receivables comprise of other 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.
38
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Impairment of financial assets
At each reporting date the Company assesses whether there is objective evidence indicating that a financial asset is
impaired including:
Significant financial difficulty of the issuer
A breach of contract such as delinquency in interest or principal payments
Active market for that financial asset disappears because of financial difficulties
Observable data indicating that there is a measurable decrease in the estimated future cash flows from a portfolio
of financial assets since the initial recognition of those assets
If evidence of impairment exists the Company recognises an impairment loss in the statement of comprehensive
income as follows:
Financial assets carried at amortised cost – the impairment loss is the difference between the carrying amount of
the loan or receivable and the present value of the estimated future cash flows discounted using the instrument’s
effective interest rate.
Impairment losses on financial assets carried at amortised cost are reversed in subsequent periods if the amount of
the loss decreases and the decrease can be related objectively to an event occurring after the impairment was
recognised.
(j) 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.
(k) 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. All other borrowing costs are recognised in profit or loss in the period
in which they are incurred.
(l) 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.
39
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(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 the tax that has been paid on its behalf
and consequently revenue is not reported gross of income tax paid.
(m) 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.
(n) 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.
(o) 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.
(p) 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.
40
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
(q) 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. The fair value 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.
(r) Changes in accounting policies
There are no IFRS or interpretations that have been issued effective for financial years beginning on or after January
1, 2017 that would have a material impact on the Company’s consolidated financial statements.
(s) Accounting standards issued but not yet applied
New accounting standards which will come into effect for annual periods beginning on or after January 1, 2018 are
discussed below.
IFRS 9: Financial Instruments ‐ Classification and Measurement, will replace IAS 39 “Financial Instruments: Recognition
and Measurement”. IFRS 9 introduces a revised model for classification and measurement, a forward‐looking
“expected loss” impairment model and a substantially reformed approach to hedge accounting. IFRS 9 is effective for
annual periods beginning on or after January 1, 2018, with earlier adoption permitted. The Company plans to adopt
the standard beginning January 1, 2018. The Company has reviewed its financial assets and liabilities and has made
the following conclusions from the adoption of the new standard on January 1, 2018:
There will be no impact on the Company’s accounting for financial liabilities, as the new requirements only affect
the accounting for financial liabilities that are designated at fair value through profit or loss and the Group does
not have any such liabilities. The derecognition rules have been transferred from IAS 39 Financial Instruments:
Recognition and Measurement and have not been changed.
The new hedge accounting rules will align the accounting for hedging instruments more closely with risk
management practices. The Company currently has no hedging instruments.
The new impairment model requires the recognition of impairment provisions based on expected credit losses
(ECL) rather than only incurred credit losses as is the case under IAS 39. It applies to financial assets classified at
amortised cost, debt instruments measured at Fair Value through other comprehensive income (FVOCI), contract
assets under IFRS 15, lease receivables, loan commitments and certain financial guarantee contracts. Based on the
assessments undertaken to date, the Company expects that there will be no resulting material changes to the
trade debtor amounts reported in its financial statements.
41
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
IFRS 15: Revenue from contracts with customers is the new standard which replaces IAS 18 Revenue and IAS 11
Construction Contracts and provides a five‐step framework for application to customer contracts; identification of
customer contracts, identification of the contract performance obligations, determination of the contract price,
allocation of the contract price to the contract performance obligations, and revenue recognition as performance
obligations are satisfied. A new requirement where revenue is variable stipulates that revenue may only be recognised
to the extent that it is highly probable that significant reversal of revenue will not occur. The Company plans to adopt
the new standard when it comes into effect for reporting periods following January 1, 2018. The Company has
assessed the impact of implementing IFRS 15 and anticipates that it will not have a material effect on its financial
statements
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.
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(q) the Company recognises revenues when oil reaches the delivery point at the Atrush Block
boundary on the basis that ownership is then transferred to the buyer, the amount can be measured reliably and it is
probable that the related economic benefits will flow to the Company. 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. Key information which
management has considered in reaching its conclusion includes the KRG’s announcement in February 2016 of its
intention to apply the PSC terms and the KRG’s record since that time in paying other Kurdistan oil exporters as well
as payments received for Atrush oil exports which commenced in July of 2017.
(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 2018 the Company received an independent reserves and resources report from McDaniel & Associates
Consultants Ltd. (“McDaniel”) to estimate the Company’s Atrush Block reserves and resources at December 31, 2017.
McDaniel’s estimate of the Company’s entitlement share of proven plus probable oil reserves relating to the Atrush
PSC increased from 10.2 MMbbl estimated at December 31, 2016 to 11.6 MMbbl estimated at December 31, 2017.
McDaniel’s estimate of the Company’s share of contingent resources were not changed materially from the previous
year.
42
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
(c) Loans and receivables
The Company has reported loans and receivables of $77.0 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 a number of 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 relatively consistent record of
delivering regular monthly payments to IOCs for their entitlement revenues in respect of monthly petroleum
production.
In the year 2018 up to the date these financial statements were approved the Company received a total of $5.1 million
in payments relating to the loans and receivables balances outstanding at December 31, 2017. In case of delays in
production exports, or delay by the KRG in paying the amounts in full when they are due, the current portion of loans
and receivables will be less than the reported amounts. Under the terms of the relevant agreements the loans and
receivable balances are recoverable in a number of ways including by cash settlement and or through payment in kind
of petroleum production.
Refer also to Note 13.
(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(h) and 3(i) 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: that there has been an
increase in the Company’s share of the latest estimated recoverable reserves and resources for Atrush and the related
production curve estimates as determined by McDaniel; that 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 despite a decrease in the long term price forecast relative to the
prior year forecast; that there has been a decrease in the forecasted costs per barrel required to recover the Atrush
oil reserves; the collectability of cash for future sales of Atrush oil which has remained stable since production
commenced; that 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; and that 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 16.
(f) Share‐based payments
The Company issues equity‐settled share‐based payments to certain directors, employees and third parties. In
accordance with IFRS 2 Share‐based payments, in determining the fair value of options granted, the Company has
applied the Black‐Scholes model and as a result makes assumptions for the expected volatility, expected life, risk‐free
rate, behavioural considerations and expected dividend yield. Refer to Note 18 for further information on share based
payments.
43
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
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 from the
commencement of production on July 3, 2017 to the end of 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
volumes from Atrush in 2017 were 3.4 MMbbls and the Company’s entitlement share was approximately 0.4 MMbbls
which were sold with an average netback price of $44.38 per barrel. 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 which 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.
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 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.
Refer also to Note 6.
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,
2016
2017
1,042
500
107
1,649
406
34
44
484
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 and investments held in interest bearing term
deposits.
9.
Finance cost
Interest charges on bonds at coupon rate
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 E&E and PP&E assets
Finance cost
For the year ended December 31,
2016
2017
20,018
841
20,859
102
4
20,965
(8,770)
12,195
17,951
943
18,894
‐
68
18,962
(13,376)
5,586
44
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
During the year ended December 31, 2017 the Company incurred interest expense relating to its Senior Bonds and
Super Senior Bonds which both carry an 11.5% fixed semi‐annual coupon interest rate. The rate used by the Company
during the year to allocate borrowing costs to E&E and PP&E decreased to approximately 42% from 70.8% in 2016
due to proportionately less spending on the capital program with the commencement of production in the year.
Refer also to Notes 11, 12 and 15.
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:
Loss from continuing operations before income tax
Corporate income tax rate
Computed income tax recovery
Increase / (decrease) resulting from:
Share issuance costs charged to share capital
Effect of changes in foreign exchange rates
Non‐taxable foreign exchange gain
Non‐deductible compensation expense
Other expense
Change in valuation allowance
Foreign tax rate differences
Non‐deductible losses on foreign operations
Income tax expense from continuing operations
For the year ended December 31,
2016
2017
11,414
26.0%
2,968
244
107
(1)
(3)
(99)
(344)
(646)
(2,311)
(85)
9,087
26.0%
2,363
‐
112
‐
(65)
(399)
40
(494)
(1,626)
(69)
The Company’s income tax expense relates to a provision 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:
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
As at December 31,
2017
2016
20,100
2,443
1,267
177,633
173,319
3,654
378,416
18,544
2,419
758
178,631
173,314
3,654
377,320
The Canadian losses from operations may be used to offset future Canadian taxable income and will expire over the
period from 2026 to 2037. 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
2018 to 2020. The Dutch losses from operations may be used to offset future Dutch taxable income and will expire
over the period from 2018 to 2026. The U.S. Federal losses are available to offset future taxable income in the United
States through 2032.
The Company has not recognised approximately $104 million (2016: $103 million) of deferred tax assets 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, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
11. Property, plant and equipment
At January 1, 2016
Cost
Accumulated depreciation
Net book value
For the year ended December 31, 2016
Opening net book value
Additions
Transfer to Atrush Development Cost Loan
Transfer to Atrush Exploration Costs receivable
Depreciation expense
Net book value
At December 31, 2016
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
Oil and gas
assets
Computer
equipment
Furniture
and office
equipment
177,138
(138)
177,000
177,000
45,799
(10,682)
(37,475)
‐
174,642
174,780
(138)
174,642
174,642
17,903
(7,627)
184,918
192,683
(7,765)
184,918
258
(214)
44
44
1
‐
‐
(29)
16
253
(237)
16
16
3
(16)
3
266
(263)
3
153
(153)
‐
‐
‐
‐
‐
‐
‐
150
(150)
‐
‐
‐
‐
‐
156
(156)
‐
Total
177,549
(505)
177,044
177,044
45,800
(10,682)
(37,475)
(29)
174,658
175,183
(525)
174,658
174,658
17,906
(7,643)
184,921
193,105
(8,184)
184,921
The net book value of PP&E at December 31, 2017 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. During the year 2017 additions of
$17.9 million (2016: $45.8 million), which included borrowing costs totalling $8.8 million (2016: $13.1 million), were
capitalised to PP&E and depletion of $7.6 million (2016: $nil) was charged to PP&E
Refer also to Notes 9, 12, 15 and 22.
46
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
12.
Intangible assets
At January 1, 2016
Cost
Accumulated amortisation
Net book value
For the year ended December 31, 2016
Opening net book value
Additions
Amortisation expense
Net book value
At December 31, 2016
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
Exploration and
evaluation assets
Other intangible
assets
88,594
‐
88,594
88,594
378
‐
88,972
88,972
‐
88,972
88,972
141
‐
‐
89,113
89,113
‐
89,113
321
(270)
51
51
‐
(16)
35
314
(279)
35
35
2
(21)
(10)
6
307
(301)
6
Total
88,915
(270)
88,645
88,645
378
(16)
89,007
89,286
(279)
89,007
89,007
143
(21)
(10)
89,119
89,420
(301)
89,119
The net book value of E&E assets at December 31, 2017 represents Atrush Block exploration and appraisal costs
related to the Company’s share of Atrush Block contingent resources as estimated by McDaniel. During the year 2017
additions of $143 thousand (2016: $378 thousand), which included borrowing costs of $16 thousand (2016: $277
thousand), were capitalised to E&E assets.
Refer also to Notes 9, 11, 15, and 22.
13. Loans and receivables
On November 7, 2016, the 4th PSC Amendment and Atrush Facilitation Agreement were concluded between the Non‐
Government Contractors and the KRG. On the same day TAQA entered into an Engineering, Procurement and
Construction (“EPC”) contract with KAR Company for the construction of the feeder pipeline from the Atrush block
boundary to the tie‐in point with the main Kurdistan export pipeline (the “Feeder Pipeline”).
Under the terms of the 4th PSC Amendment and Atrush Facilitation Agreement:
The KRG acquires a 25% interest in the Atrush PSC effective November 7, 2012, the date of declaration of
commerciality (“DOC date”). Consequently, the respective participating interests in the Atrush PSC are TAQA at
39.9%, the KRG at 25%, GEP at 20.1% and MOKDV at 15%;
All Atrush petroleum costs from the DOC date through the commencement of oil exports from Atrush will be paid
by the Non‐Government Contractors and a defined portion of the KRG’s share of these costs are deemed
Exploration Costs as defined in the Atrush PSC and repaid through an accelerated petroleum cost recovery
arrangement from the sale of future oil production from Atrush. This arrangement has resulted in the Atrush
Exploration Cost receivable at year end as reported in the table below; and
47
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
The Non‐Government Contractors will fund the cost of constructing the Feeder Pipeline which will be novated to
the KRG following the commencement of oil exports from Atrush. The Feeder Pipeline costs and the balance of the
Atrush petroleum costs incurred by the Non‐Government Contractors on behalf of the KRG excluding the portion
deemed as Exploration Costs will be repaid with interest at 7% per annum by the KRG within 2 years from
October 31, 2017 (respectively, the “Atrush Feeder Pipeline Cost Loan” and the “Atrush Development Cost Loan”).
These arrangements have resulted in loan balances at year end as reported in the table below.
Atrush Exploration Costs receivable
Atrush Development Cost Loan
Accounts receivable on Atrush oil sales
Atrush Feeder Pipeline Cost Loan
Total loans and receivables
‐ Current portion
‐ Non‐current portion
As at December 31,
2017
2016
37,247
16,018
13,957
9,751
76,973
32,277
44,696
37,475
12,857
‐
3,034
53,366
7,252
46,114
In the last three months of 2017 the Company received $4.0 million in total payments for its entitlement share Atrush
production for July through September and reimbursement instalments on the Atrush Exploration Costs receivable.
In January 2018 the Non‐Government Contractors and the KRG agreed that substantially all the first two instalments
on the Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost Loan, which were due in November and
December of 2017, would be offset against amounts owed to the KRG for security services which they provided for
the Atrush operations, and an Atrush production bonus. The total loan balances offset against amounts owed to the
KRG as of the balance sheet date due to the agreement was $2.6 million.
In the year 2018 up to the date these financial statements were approved the Company received a total of $5.1 million
in payments for loans and receivables balances outstanding at December 31, 2017 comprised of $4.8 million in total
payments for its entitlement share of oil sales for the months October and November and $0.3 million in
reimbursements of the Atrush Exploration Costs receivable.
Refer also to Notes 6 and 8.
14. Accounts payable and accrued expenses
Payables to joint operations partner
Trade payables
Accrued expenses
Total accounts payable and accrued expenses
Refer also to Note 13.
15. Borrowings
As at December 31,
2017
4,365
371
91
4,827
2016
6,146
170
118
6,434
At December 31, 2017 General Exploration Partners, Inc. had outstanding $166.3 million of senior secured bonds
(“Senior Bonds”) and $20.2 million of super senior secured bonds (“Super Senior Bonds”). The Senior Bonds are listed
on the Oslo Børs in Norway under the symbol “GEP01”, have a five‐year maturity from their issuance date of
November 13, 2013 and carry an 11.5% fixed semi‐annual coupon and were used to fund capital expenditures related
to the development of the Atrush Block. The Super Senior Bonds also mature on November 13, 2018, carry an 11.5%
fixed semi‐annual coupon and were used to fund capital expenditures related to the development of the Atrush Block.
GEP has the option to pay in cash or in kind by issuing new bonds (“PIK Bonds”) the remaining coupon interest on
both Senior and Super Senior bonds.
48
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
All the movements in borrowings during the year were non‐cash and are explained as follows:
For the year ended December 31,
2016
2017
Opening balance
Interest charges at coupon rate
Bonds issued
Amortisation of bond transaction costs
Super Senior Bonds issued – net of transaction costs
Senior Bonds exchanged for ShaMaran common shares
Interest payments to bondholders
Ending balance
‐ Current portion: accrued bond interest expense
‐ Current portion: borrowings
‐ Non‐current portion: borrowings
167,632
20,018
19,721
841
‐
‐
(19,721)
188,491
2,799
185,692
‐
150,515
17,951
17,700
943
16,223
(18,000)
(17,700)
167,632
2,503
‐
165,129
The remaining contractual obligations comprising of repayment of principal and interest expense under the Bond
agreements, based on undiscounted cash flows at payment dates and assuming 2018 interest is paid in cash, are as
follows:
Less than one year
Between one and two years
Total
Debt Incurrence Tests
For the year ended December 31,
2016
2017
207,860
‐
207,860
19,722
188,138
207,860
In accordance with the amended terms of GEP’s Senior Bonds and Super Senior Bonds agreements ShaMaran is
required to follow certain debt incurrence tests as follows:
1.
upon incurrence of any new financial indebtedness, other than certain permitted financial indebtedness as
described in the Super Senior Bonds agreement, then ShaMaran’s Book Equity Ratio, which is defined as
shareholders’ equity divided by total assets, shall be minimum 30% immediately thereafter, and
ShaMaran and any of its subsidiaries (together the “Group”) other than GEP, which is not allowed to do so, may
not enter into an agreement to make any acquisitions, merger or any other transactions involving another party
being consolidated into the Group’s accounts, unless such other party has a minimum 30% Book Equity Ratio
prior to such transaction taking place.
2.
Security
The Senior Bonds and Super Senior Bonds hold security jointly with Super Senior Bonds ranking first until these bonds
are repaid in full.
The bonds include an unconditional and irrevocable on‐demand guarantee on a joint and several basis from the
Company and certain of the Company’s direct and indirect subsidiaries and, among other arrangements, agreements
which pledge all of the ordinary shares of GEP and the Company’s Swiss service subsidiary, ShaMaran Services SA, as
security for GEP’s bond related obligations, as well as an internal credit facility agreement among the Company and
certain of its subsidiaries setting out the terms and conditions for intra‐group credit to be made available amongst
the parties.
Under the terms of both bond agreements GEP’s cash accounts are pledged to the bond trustee as security and cash
may be employed only for prescribed purposes, to fund the financing, development and operation of the Atrush Block
and to fund technical, management and administrative services of ShaMaran’s subsidiary companies up to $6 million
per year over the term of the bonds. Of the Company’s $5.3 million of total cash and cash equivalents at December
31, 2017 (2016: $4.4 million) $2.2 million was held in GEP’s restricted accounts (December 31, 2016: $nil).
In the year ended December 31, 2017 PIK Bonds of $17.6 million and $2.1 million were issued under the Senior Bonds
and Super Senior Bonds agreements, respectively, to pay semi‐annual coupon interest which came due in the year
ended December 31, 2017. Refer also to Notes 2, 9, 11, 12 and 20.
49
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
16. Provisions
The Company has provided for its working interest share of decommissioning and site restoration costs in relation to
activities undertaken to date on the Atrush Block in Kurdistan.
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
As at December 31,
2017
2016
8,869
425
129
4
9,427
8,080
(1,119)
1,840
68
8,869
The above provisions assume decommissioning and site restoration work is to be undertaken in the year 2032 and
estimated costs have been discounted to net present value using a Bank of Canada long term bond yield rate of 2.26%
(2016: 2.31%) and an inflation rate of 2.11% (2016: 2.08%). Refer also to Note 22.
17. Share capital
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, 2016
Shares issued to holders of GEP’s Senior Bonds
At December 31, 2016
Shares issued on private placement
Transaction costs on private placement
At December 31, 2017
Number of shares
Share capital
1,579,768,534
218,863,000
1,798,631,534
360,000,000
‐
2,158,631,534
593,179
18,000
611,179
27,281
(922)
637,538
On January 30, 2017, the Company completed the issue of 360 million common shares of ShaMaran on a private
placement basis (the “Private Placement”) at a price per share of CAD 0.10 (equal to SEK 0.67) which resulted in gross
proceeds to the Company of $27.3 million ($26.4 million net of transaction related costs). Zebra Holdings and
Investments SARL, Lorito Holdings SARL and Lundin Petroleum BV, the Company’s major shareholders, subscribed for
43,463,618 shares, 16,984,621 shares and 17,800,000 shares, respectively, in the Private Placement. Refer also to
Note 23.
Earnings per share
The earnings per share amounts were as follows:
For the year ended December 31,
2016
2017
Net loss, in dollars
Weighted average common shares outstanding during the year
Basic and diluted loss per share, in dollars
(11,499,000)
2,129,042,493
(0.01)
(9,156,000)
1,722,479,202
(0.01)
18. Share based payments expense
The Company has an established 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 under option at any specific time to any one option holder shall not exceed 5% of the issued
and outstanding common shares of the Company. The term of any options granted under the 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.
50
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
Movements in the Company’s outstanding share options are explained as follows:
At January 1, 2016
Expired in the year 2016
At December 31, 2016
Change in the year 2017
At December 31, 2017
Share options exercisable:
At December 31, 2016
At December 31, 2017
Number of
share options outstanding
Weighted average
exercise price
CAD
28,190,000
(25,000)
28,165,000
‐
28,165,000
19,498,333
28,165,000
0.13
0.80
0.13
‐
0.13
0.14
0.13
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.
There were no options granted during the year 2017. Share based payments expense for the year ended December
31, 2017 was $11 thousand (2016: $0.2 million).
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.
19. 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,
2016
2017
8,082
(6,301)
1,781
7,304
(5,634)
1,670
The movement in the defined benefit obligation over the year is as follows:
As at December 31,
2017
Opening balance
Foreign exchange loss / (gain)
Additional contributions paid by employees
Current service cost
Ordinary contributions paid by employees
Interest expense on defined benefit obligation
Actuarial loss on defined benefit obligation
Administration costs
Benefits paid from plan assets
Defined benefit obligation, ending balance
7,304
327
217
172
110
49
32
5
(134)
8,082
2016
7,062
(162)
183
184
113
54
23
5
(158)
7,304
The weighted average duration of the defined benefit obligation is 16.9 years. There is no maturity profile since the
average remaining life before active employees reach final age according to the plan is 9.7 years.
51
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
The movement in the fair value of the plan assets over the year is as follows:
Opening balance
Foreign exchange gain / (loss)
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
Benefits paid from plan assets
Fair value of plan assets, ending balance
As at December 31,
2017
5,634
253
217
165
110
38
18
(134)
6,301
2016
5,374
(126)
183
169
113
41
38
(158)
5,634
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
Total expense recognised
For the year ended December 31,
2016
2017
172
49
5
(38)
188
184
54
5
(41)
202
The expense associated with the Company’s pension plan of $0.2 million was included within general and
administrative expenses. The Company also recognised in other comprehensive income a $13 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,
2016
2017
0.70%
1.00%
1.00%
0.00%
M65/F64
0.65%
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 2018 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 by 7.9%
Increase by 0.2%
Increase by 2.0%
Decrease in
assumption
Increase by 8.9%
Decrease by 0.2%
Decrease by 2.1%
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.
52
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(Expressed in thousands of United States dollars unless otherwise stated)
______________________________________________________________________________
20. Financial instruments
Financial assets
The financial assets of the Company on the balance sheet dates were as follows:
Loans and receivables ²
Cash and cash equivalents, unrestricted ²
Cash and cash equivalents, restricted ²
Other receivables ²
Total financial assets
Carrying and fair values ¹
At December 31, 2017 At December 31, 2016
39,726
3,094
2,162
52
45,034
15,891
4,416
‐
77
20,384
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
Pension liability
Total financial liabilities
Fair value
hierarchy ⁴
Level 2
Carrying values
At December 31, 2017 At December 31, 2016
185,692
2,799
4,827
1,781
195,099
165,129
2,503
6,434
1,670
175,736
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 $151.8 million (December 31, 2016: $63.1
million). The fair value was determined by reference to the bond agreement terms and the weighted average of
available annual published price quotations on the Oslo Børs.
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.
53
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(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
$188.5 million as at December 31, 2017 (2016: $167.6 million). Refer also to Note 15.
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 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.
The carrying amounts of the Company’s principal monetary assets and liabilities denominated in foreign currency at
the reporting date are as follows:
Canadian dollars in thousands (“CAD 000”)
Swiss francs in thousands (“CHF 000”)
Assets
December 31,
2017
2016
36
83
58
185
Liabilities
December 31,
2016
2017
68
221
37
107
54
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(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 and liabilities 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 and liabilities 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
Liabilities
2017
2016
2017
2016
‐
1
‐
2
‐
(2)
‐
(1)
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 Group is highly leveraged though financing at the project level, for the continuation of Atrush project, and at the
corporate level due to the $186.5 million of bonds which have been issued since November 2013. 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.
55
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(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” and further information relevant to the Company’s liquidity position is disclosed
in the Company’s going concern assessment in Note 2.
21. Commitments and contingencies
As at December 31, 2017 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,
2018
32,657
40
32,697
2019
120
‐
120
2020
Thereafter
120
‐
120
1,448
‐
1,448
Total
34,345
40
34,385
Amounts relating to Atrush Block development represent the Company’s unfunded paying interest share of the
approved 2018 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: $8.3
million at 10 million barrels (ShaMaran share: $2.2 million); $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 2, 15 and 22.
22.
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 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, the date when the Final Completion Certificate for the Atrush Feeder
Pipeline for the Feeder Pipeline was issued. These costs are due to be reimbursed to the Non‐Government Contractors
in 24 equal monthly instalments over the period ending October 31, 2019.
56
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(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 and 21.
Information about subsidiaries
The consolidated financial statements of the Company include:
Subsidiary
Principal activities
Country of
Incorporation
% equity interest as at
31 Dec 2017
31 Dec 2016
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
23. Related party transactions
Transactions with corporate entities
Lundin Petroleum AB
Namdo Management Services Ltd.
McCullough O’Connor Irwin LLP
Total
Purchases of services
during the year
2017
2016
Amounts owing at
December 31,
2016
2017
204
50
45
299
299
99
44
442
18
‐
‐
18
24
1
‐
25
The Company receives services from various subsidiary companies of Lundin Petroleum AB (“Lundin”), a shareholder
of the Company. Lundin charges during the year ended December 31, 2017 of $204 (2016: $299) were comprised of
office rental, administrative and building services of $177 (2016: $268), investor relations services of $26 (2016: $28)
and technical service costs of $1 (2016: $3).
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.
McCullough O’Connor Irwin LLP is a law firm in which an officer of the Company is a partner and has provided legal
services to the Company.
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 17.
57
SHAMARAN PETROLEUM CORP.
Notes to the Consolidated Financial Statements
For the year ended December 31, 2017
(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 short‐term and pension benefits
Management’s salaries
Directors’ fees
Management’s share based payments
Directors’ share based payments
Total
For the year ended December 31,
2016
2017
1,079
877
81
9
3
2,049
492
878
79
192
58
1,699
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’.
58
SHAMARAN PETROLEUM CORP.
DIRECTORS
CORPORATE INFORMATION
Keith C. Hill
Director, Chairman
Florida, U.S.A
Chris Bruijnzeels
CORPORATE OFFICE
885 West Georgia Street
Suite 2000
Vancouver, British Columbia V6C 3E8
Telephone: +1‐604‐689‐7842
Director, President & Chief Executive Officer
Geneva, Switzerland
Facsimile: +1‐604‐689‐4250
Website: www.shamaranpetroleum.com
Brian D. Edgar
Director
Vancouver, British Columbia
Gary S. Guidry
Director
Calgary, Alberta
C. Ashley Heppenstall
Director
Hong Kong
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
Geneva, Switzerland
Kevin E. Hisko
Corporate Secretary
Vancouver, British Columbia
Vancouver, British Columbia
STOCK EXCHANGE LISTINGS
TSX Venture Exchange and
NASDAQ OMX First North Exchange
Trading Symbol: SNM
INVESTOR RELATIONS
Sophia Shane
Vancouver, British Columbia
59