ShaMaran Petroleum Corp.
Annual Report 2018

Plain-text annual report

ShaMaran Petroleum Corp. Annual Report For the year ended December 31, 2018 SHAMARAN PETROLEUM CORP. MANAGEMENT DISCUSSION AND ANALYSIS For the year ended December 31, 2018 Management’s discussion and analysis (“MD&A”) of the financial and operating results of ShaMaran Petroleum Corp. (together with its subsidiaries, “ShaMaran” or the “Company”) is prepared with an effective date of March 7, 2019. The MD&A should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2018, together with the accompanying notes. The financial statements of the Company have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. Unless otherwise stated herein all currency amounts indicated as “$” in this MD&A are expressed in thousands of United States dollars (“USD”). OVERVIEW ShaMaran Petroleum Corp. is a Canadian oil and gas company listed on the TSX Venture Exchange and the NASDAQ First North Exchange (Stockholm) under the symbol "SNM". ShaMaran has a 20.1% direct interest in the Atrush Block production sharing contract (“Atrush PSC”) located. The Atrush Block is in the Kurdistan Region of Iraq (“Kurdistan”), approximately 85 kilometers northwest of Erbil, the capital of Kurdistan. The Atrush Block is 269 square kilometers in area and has oil proven in Jurassic fractured carbonates in the Chiya Khere structure. Oil production from Atrush commenced in July 2017. Installed production facilities have a capacity of 30,000 barrels of oil per day (“bopd”). Ten wells have been drilled to date. Five wells are currently producing. Atrush is continuously being appraised and further phases of development, including further drilling and possible facilities expansion will be defined based on production data, appraisal information and economic circumstances. HIGHLIGHTS AND DEVELOPMENTS Atrush Operations • • • ShaMaran entered into agreements on December 26, 2018 to acquire jointly with TAQA Atrush B.V. (“TAQA”) the 15% interest in the Atrush Block (“the Marathon Acquisition”) held by Marathon International Oil Company (“MIOC”). Following close of these agreements ShaMaran’s working interest in Atrush will increase from 20.1% to 27.6%. The parties to the agreements are currently in the process of obtaining the consent of the Kurdistan Regional Government (“KRG”). YTD 2019 average production was 26 thousand barrels of oil per day (“Mbopd”), coming mainly from four wells: Atrush-2, (“AT-2”) Chiya Khere-5 “CK-5”), Chiya Khere-7 (“CK-7”) and Chiya Khere-8 (“CK-8”). The Chiya Khere-10 (“CK-10”) well was offline for 18 days for an intervention to replace an electric submersible pump (“ESP”) and the Atrush Production Facilities were shut-in for 7 days in February during maintenance of the export pipeline. Currently Atrush is producing around 30 Mbopd. Fourth quarter average production was 27.4 Mbopd, significantly up from the 21.7 Mbopd average third quarter production. The increase was due to successful resolution of processing capacity restrictions caused by high salt concentrations produced from two wells. • Annual production for the year 2018 was 22.1 Mbopd, which was below guidance mainly due to salt-related processing restrictions negatively impacting production during the second and third quarters. Processing capacity constraints associated with salt production and low ambient temperatures during the winter months have been addressed. The Atrush Production Facilities can now consistently operate at, or above, the 30.0 thousand barrels of liquids per day (“Mblpd”) design rate during normal operations. • The average lifting costs in the fourth quarter was $7.84 per barrel, down from $7.92 per barrel in the third quarter mainly due to the higher average production in the fourth quarter. Lifting costs averaged $7.41 per barrel over the year 2018 compared to $8.52 per barrel in the year 2017. The 2018 average lifting costs were above guidance due to lower production than planned and additional costs related to mitigating salt related problems. 1 • Revenue from oil sales in the fourth quarter was $14.5 million, up from $13.2 million reported in the third quarter due to the higher fourth quarter production and despite lower average netback oil prices over the same period which decreased from $59.72 per barrel to $52.58 per barrel. The Company reported $69.6 million of revenue from oil sales for the year 2018. • • Three wells were successfully completed in the year 2018. The CK-7 and CK-10 production wells started production near the end of July 2018. The CK-9 water disposal well was completed and tested according to schedule during November 2018 and is now online and used for disposal of Atrush produced water. In December 2018 the Atrush 3 (“AT-3”) well was re-completed as a heavy oil production well. Following the AT- 3 re-completion the CK-11 production well was spudded at the start of January 2019 and the Chiya Khere 6 (“CK- 6”) was re-completed. • Heavy oil extended well test (“HOEWT”) facilities have been installed and heavy oil production from AT-3 is expected to commence in March 2019. This test aims to progress development planning for the significant volumes of heavy oil currently classified as Atrush contingent resources. • The procurement process for Atrush early production facilities (“EPF”) is underway and it is expected that these facilities, as well as ongoing debottlenecking of the existing Production Facilities, will deliver 50.0 Mblpd processing capacity in the second half of 2019. Financial and Corporate • The Company issued new $240 million senior unsecured bonds with 5-year term to July 5, 2023 and 12% semi- annual coupon interest and bonds due to mature in November 2018 were retired. On December 31, 2018 the Company deposited cash of $14.4 million to the bondholders’ Debt Service Retention Account and, on January 5, 2019, paid the first semi-annual interest payment of $14.4 million to ShaMaran bondholders. Refer to the discussion under “Borrowings” section below. • Amendments were approved to the terms of the Company’s $240 million senior bonds on February 1, 2019. On February 8, 2019 the Company repaid $50 million of bonds plus accrued interest reducing its bonds currently outstanding to $190 million. • Atrush related cash inflows in the year ending December 31, 2018: o $69 million for entitlement share of Atrush PSC profit oil and cost oil for October 2017 through September 2018 oil deliveries. A further 10.9 million has been received in the year to date 2019 relating to October and November 2018 oil sales. o $2.3 million of Atrush Exploration Costs receivable1 on October 2017 through September 2018 oil sales. A further $0.5 million was received in the year to date 2019 relating to October and November 2018 oil sales. o $15.6 million in payments of principal plus interest on the Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost loans for invoices from January to December 2018 and an additional $2.6 million has been collected in the year to date 2019. • An amended Atrush oil sales agreement was concluded between Atrush co-venturers and the KRG in the fourth quarter which reduced the oil price discount from the previous $15.73 per barrel to $15.43 per barrel with effect from October 1, 2018. The KRG purchases oil exported from the Atrush field by pipeline at the Atrush block boundary based upon the Dated Brent oil price minus an oil price discount for quality and all local and international transportation costs. Reserves and Resources • In February 2019, the Company reported estimated reserves and contingent resources for the Atrush field as at December 31, 2018. Total Field Proven plus Probable (“2P”) Reserves on a property gross basis for Atrush increased from 102.7 million barrels (“MMbbl”) reported as at December 31, 2017 to 106 MMbbl which, when 2018 Atrush production of 8 MMbbl is included, represents an increase of 11 percent. Total Field Unrisked Best Estimate Contingent Oil Resources (“2C”)2 on a property gross basis for Atrush decreased from the 2017 estimate of 296 MMbbl to 268 MMbbl. Total discovered oil in place in the Atrush Block is a low estimate of 1.5 billion barrels, a best estimate of 2 billion barrels and a high estimate of 2.6 billion barrels. 1 The Exploration Costs Receivable is related to the repayment of certain development costs that ShaMaran paid on behalf of the KRG which, for purposes of repayment, are governed under the Atrush PSC and the related Facilitation Agreement and are deemed to be Exploration Costs. 2 This estimate of remaining recoverable resources (unrisked) includes contingent resources that have not been adjusted for risk based on the chance of development. It is not an estimate of volumes that may be recovered. 2 OPERATIONS Atrush oil production Oil production on the Atrush Block commenced on July 3, 2017. Cumulative production exported from Atrush from July 2017 to December 31, 2018, was 11.4 million barrels of oil. Average daily oil production (bopd) Oil produced and sold – gross field (Mbbls) ShaMaran production entitlement (Mbbls) Q4.2018 Q3.2018 Q4.2017 27,426 2,523 276 21,712 1,998 223 21,681 1,995 295 From start up, production in Atrush steadily increased to approximately 26.0 Mbopd in January 2018. In March 2018 production dropped to approximately 20.3 Mbopd due to a partial blockage by sediment in a production facility heat exchanger. In early April 2018 production was temporarily suspended to address the partial blockage of the heat exchanger. The sediments were successfully removed from the heat exchanger during this plant shut down. Analysis of the removed sediments indicate high concentrations of salts lost to the formation during drilling operations. These materials were flowed back into the production facilities with the produced dry oil where they caused capacity restrictions. To target these materials, fresh water was introduced at the CK-5 wellhead from June 2018 onwards. The salt materials are now diluted into the fresh water, which is then separated and disposed of during normal processing operations. During the third quarter of 2018, daily production was constrained by exceptionally high export pipeline downtime during the month of August (over 6 days) as well as salt fill in the production facilities stripper column. The salt fill became apparent once additional well capacity from the CK-7 and CK-10 wells enabled Production Facility rates to exceed 26.0 Mbopd. The stripper column was flushed during a two-day shutdown in late September which successfully removed all salt restrictions and enabled the high stabilized rates throughout the fourth quarter. During the fourth quarter 2018, well rates were steadily increased to test and evaluate the limits of the Production Facility. By the end of November 2018 and through early December 2018, several days with rates over 30.0 Mbopd were reported until the onset of failure of the CK-10 ESP, which reduced the available well capacity and therefore negatively impacted the daily production rate. The CK-10 well was brought back on production late January 2019 after a successful work-over. The Company’s production entitlement share decreased after its exploration cost sharing arrangement with Taqa was fully settled in the second quarter of 2018. This is explained further in the discussion under the “Gross Margin” section below. Drilling, Testing and Facilities The CK-7 well was drilled in Q4 2017 and the reservoir section was encountered 114 meters shallower than prognosis. In March and April 2018 three intervals were successfully tested: the Mus formation tested 20.1 API oil at a rate of 0.8 Mbopd, with a final productivity of 13 stb/d/psi3; the Alan formation tested 27.1 API oil at a rate of 0.9 Mbopd, with a final productivity of 6 stb/d/psi; and the main Lower Sargelu formation tested 26.4 API oil at 1.0 Mbopd at a drawdown of only 2 psi, yielding a final productivity of 446 stb/d/psi. No water was produced at the end of the test. CK-7 is now completed over the Alan and Lower Sargelu formation with an electric submersible pump. During the final completion test the well produced 7,040 bopd at only 14 psi drawdown. The CK-10 well was spudded on May 15, 2018 was drilled to a total depth of 1,985 meters, which was reached on time and within budget on June 16, 2018. The reservoir section was encountered some 60 meters shallow to prognosis. The well flow tested approximately 4.4 Mbopd at a low drawdown, yielding a final productivity index of 313 stb/d/psi. The well is now completed over the Lower Sargalu formation. The CK-9 water disposal well was spudded on July 20, 2018 and was drilled to a total depth of 3015 meters, which was reached on time and within budget on October 18, 2018. Water injection started in January 2019. A further two appraisal wells have previously been drilled and tested in the eastern part of the field and have proven reservoir communication between the eastern and the western parts of the field. It is planned to conduct an extended well test in one of the two eastern appraisal wells, AT-3. This will provide important production information on the heavier part of the oil column. Together with production data from the other producing wells, this will allow for defining the next phases of Atrush development. 3 Stock tank barrels per day per pound per square inch (“stb/d/psi”) is a standard industry measure of productivity. 3 The AT-3 well was re-completed as a heavy oil production well during December 2018. The well commenced production in February 2019. The CK-11 production well was spudded at the start of January 2019 and is currently drilling. Positive production results have shown the potential to increase Atrush production levels. It is expected that by installing an EPF and debottlenecking existing Production Facilities, the Atrush processing capacity can be increased to 50.0 Mblpd. The procurement process for an Atrush EPF is underway and increased processing capacity is expected to be available in the second half of 2019. The Company’s independent reserves and resources evaluator, McDaniel & Associates Consultants Ltd (“McDaniel”) increased the 2P oil reserves estimate to 106MMbbl at the end of the year 2018. This estimate assumes that four extra production wells will be drilled to further develop the medium gravity oil in the reserves area of the field increasing medium oil recovery. Reserves associated with the HOEWT planned in 2019 for the AT-3 well have also been included. Reserves which were included in McDaniel’s previous estimate for heavy oil production from the wells currently producing have now been transferred to contingent resources because production to date has shown no indication of heavy oil. The contingent oil resources represent the likely recoverable oil volumes associated with further phases of development after Phase 1. McDaniel has estimated gross 2C best estimate contingent oil resources of 268 MMbbl. These are contingent oil resources rather than reserves due to the uncertainty over the future development plan which will depend in part on Phase 1 production performance and the HOEWT planned for the beginning of 2019. McDaniel estimates the chance of developing the 2C contingent oil resources at 80 percent. OUTLOOK Operations The Company provides the following guidance for 2019: • Atrush field gross production is expected to range from 30 Mbopd to 35 Mbopd and will depend mainly on the timing of the installation of additional production facilities; • Atrush lifting costs are estimated to range from $6.30 per barrel to $7.90 per barrel. Atrush lifting costs are mainly fixed costs and therefore we expect the dollar per barrel estimates to decrease with increasing levels of production; and • Atrush gross capital expenditures for 2019 is estimated at $137 million which includes: o debottlenecking to increase existing production capacity beyond 30.0 Mbopd; o re-completing the Chiya Khere-6 well to initially monitor the heavy oil well during the HOEWT, and then later produce from the medium oil interval; o completing drilling, testing and completion activities at CK-11; o drilling, testing and completing three additional production wells; o expansion of processed oil storage capacity to reduce impact of export pipeline shutdowns on Atrush production rates; o installation of a desalter vessel at the Processing Facilities to reduce the operating costs associated with the short-term salt mitigation measures; o construction of the Chamanke-D drilling location to enable addition of future production wells, and o installing of an EPF and debottlenecking of existing Production Facilities, to extend Atrush oil processing capacity to 50.0 Mblpd in the second half of 2019. Following the 2019 drilling program, the extended well testing in AT-3 and increased production, the Company expects to further assess the significant undeveloped Atrush resource base with the potential to grow to approximately 100.0 Mblpd production. Management expects that investment decisions for further phases of development can be made by early 2020. 4 OWNERSHIP, PRINCIPAL TERMS OF THE ATRUSH PSC At the end of 2018 ShaMaran, through its wholly owned subsidiary, General Exploration Partners, Inc. (“GEP”), held a 20.1% direct interest in the Atrush PSC. TAQA Atrush B.V. (“TAQA” a subsidiary of Abu Dhabi National Energy Company PJSC, and the “Operator” of the Atrush Block) with a 39.9% direct interest, the KRG a 25% direct interest and Marathon Oil KDV B.V. (“MOKDV”) held a 15% direct interest. TAQA, GEP, and MOKDV together are the “Non- Government Contractors” to the Atrush PSC. The Non-Government Contractors and the KRG together are the “Contractors” to the Atrush PSC. The Atrush field was discovered in 2011 and a Phase 1 development plan was approved in October 2013, which consists of installing and commissioning production facilities with 30,000 bopd capacity and the drilling and completion of production wells which supply the Production Facility. In August 2010 the Company acquired a 33.5% shareholding in GEP which then held an 80% working interest in the Atrush PSC, with the remaining 20% third party interest (“TPI”) being held by the KRG. In October 2010 MOKDV was assigned the 20% TPI in the Atrush PSC. On December 31, 2012 GEP sold a 53.2% direct interest in the Atrush Block to TAQA, who also assumed from GEP the Operatorship of the Block and repurchased the entire 66.5% shareholding which Aspect Energy International LLC (“Aspect”) held in GEP, leaving the Company with a 100% shareholding interest in GEP and, at that time, a 26.8% direct interest in the Atrush PSC. On November 7, 2016 the Assignment, Novation and Fourth Amendment Agreement to the Atrush PSC (the “4th PSC Amendment”) and Atrush Facilitation Agreement were concluded between Non-Government Contractors and the KRG, in which the KRG acquired a 25% interest in the Atrush PSC effective November 7, 2012, resulting in GEP reducing its interest in the Atrush PSC to 20.1%. Under the terms of the Atrush PSC the development period is for 20 years after the declaration of commerciality (November 7, 2012) with an automatic right to a five-year extension and the possibility to extend for an additional five years. All qualifying petroleum costs incurred by the Contractors shall be recovered from a portion of available petroleum production, defined under the terms of the Atrush PSC. All modifications to the Atrush PSC are subject to the approval of the KRG. Fiscal terms under the Atrush PSC include a 10% royalty and a variable profit split based on a percentage share to the KRG. GEP has the right to recover costs using up to 40% of the available oil (produced oil less royalty oil) and 55% of the produced gas. The Contractors are entitled to cost recovery in respect of all costs and expenditures incurred for exploration, development, production and decommissioning operations, as well as certain other allowable direct and indirect costs. The portion of profit oil available to the Contractors is based on a sliding scale from 32% to 16% depending on the “R- Factor”, which is a ratio of cumulative revenues to cumulative costs. When the ratio is below one, the Contractors are entitled to 32% of profit oil, with a reducing scale to 16% when the ratio is greater than 2.75. In respect of gas, the sliding scale is from 40% to 22%. SELECTED ANNUAL FINANCIAL INFORMATION The following is a summary of selected annual financial information for the Company: (In $000, except per share data) Revenues Cost of goods sold Service fees income General and administrative expense Share based payments expense Depreciation and amortisation expense Finance income Finance cost Income tax expense Income / (loss) for the year For the year ended December 31, 2018 2017 2016 69,600 (42,072) - (4,564) - (8) 2,091 (23,114) (64) 1,869 17,689 (14,009) - (4,511) (11) (26) 1,649 (12,195) (85) (11,499) - - 120 (3,811) (249) (45) 484 (5,586) (69) (9,156) Basic and diluted loss in $ per share: - (0.01) (0.01) 5 Financial position – net book value of principal items Property Plant & Equipment Exploration and evaluation assets Loans and receivables Cash and other assets Total assets Borrowings Other liabilities Shareholders’ equity 2018 195,908 67,829 61,283 94,756 419,776 (236,717) (28,860) 154,199 As at December 31, 2017 184,921 89,119 76,973 5,468 356,481 (185,692) (18,834) 151,955 2016 174,658 89,007 53,366 4,640 321,671 (165,129) (19,476) 137,066 Common shares outstanding (x 1,000) 2,158,632 2,158,632 1,798,632 Summary of Principal Changes in Annual Financial Information The Company has reported in 2018 a net income of $1.9 million which was primarily driven by the gross margin on Atrush oil sales, interest income on Atrush cost loans and interest on cash held in short term deposits offset by finance cost, the substantial portion of which was expensed borrowing costs on the Company’s bonds, and routine general and administrative expenses. The Company’s operations are comprised of the Phase 1 development program on the Atrush Block petroleum property which commenced production on July 3, 2017. The principal changes in annual financial information are further explained in the sections below. Gross margin on oil sales In $000 ---------Three month period--------- Q4.2017 Q4.2018 Q3.2018 -----Twelve month period---- Q4.2017 Q4.2018 Revenues from Atrush oil sales 14,531 13,240 13,907 69,600 17,689 Lifting costs Other costs of production Depletion costs Cost of goods sold (3,978) (1,732) (10,259) (15,969) (3,180) (39) (3,726) (6,945) (3,245) (834) (5,347) (9,426) (12,047) (1,854) (28,171) (42,072) (5,547) (834) (7,628) (14,009) Gross margin on oil sales 3,680 Revenues relate to the Company’s entitlement share of oil sales from Atrush. Revenue for sales of oil is recognised when the significant risks and rewards of ownership are deemed to have been transferred to the KRG, the amount can be measured reliably and it is assessed as probable that economic benefit associated with the sale will flow to the Company. This occurs when oil reaches the delivery point at the Atrush Block boundary in route to the KRG’s main export pipeline. (1,438) 27,528 6,295 4,481 Revenue is recognised at fair value which is comprised of the Company’s entitlement production due under the terms of the Atrush Joint Operating Agreement (“Atrush JOA”) and the Atrush PSC which have two principal components: cost oil, which is the mechanism by which the Company recovers qualifying costs it has incurred on an asset, and profit oil, which is the mechanism through which profits are shared between the Company, the Atrush co-venturers and the KRG. The Company pays capacity building payments on profit oil, which are due for payment once the Company has received the related profit oil proceeds. Profit oil revenue is reported net of any related capacity building payments. The Company’s oil sales are made to the KRG under the terms of a sales agreement which allows for Atrush oil volumes to be sold to the KRG at the Atrush block boundary at a discount to the Dated Brent oil price for estimated oil quality adjustments and all local and international transportation costs. Income tax arising from the Company’s activities under production sharing contracts is settled by the KRG at no cost and on behalf of the Company. However, the Company is not able to measure the tax that has been paid on its behalf and consequently revenue is not reported gross of income tax paid. 6 Production from the Atrush field was delivered to the KRG’s Feeder Pipeline at the Atrush block boundary for onward export through Ceyhan, Turkey. In the three and twelve months ended December 31, 2018, the respective gross exported oil volumes from Atrush were 2.5 MMbbls and 8.1 MMbbls and the Company’s entitlement shares were approximately 276 Mbbls and 1.3 MMbbls. ShaMaran’s oil entitlement share is based on PSC terms covering allocation of profit oil and cost oil, capacity building bonuses owed to the KRG, a priority arrangement with TAQA for sharing initial exploration cost oil 4 and on export prices. Export prices are based on Dated Brent oil price with an agreed discount for estimated oil quality adjustments and all local and international transportation costs, of $15.43 per barrel for the three months ended December 31, 2018. Average Atrush fourth quarter production was 27.4 Mbopd, up from 21.7 Mbopd in the third quarter, and was 22.1 Mbopd for the year 2018. The increased fourth quarter production was due to continued improvements in processing capacity restrictions caused by unexpectedly high concentrations of salt flowed back by two wells which started to occur in March 2018. The restrictions were relieved through flushing of plugged process vessels as well as introduction of fresh water at one well location. Revenue from oil sales in the fourth quarter also moved up to $14.5 million compared to $13.2 million reported in the third quarter in line with the higher average fourth quarter production and despite lower average netback oil prices over the same period which decreased from to $52.58 per barrel from the $59.72 per barrel in the third quarter. The average netback price for the year was $54.52 per barrel. Lifting costs are comprised of the Company’s share of expenses related to the production of oil from the Atrush Block including operation and maintenance of wells and production facilities, insurances, and the operator’s related support costs. The average lifting costs in the fourth quarter was $7.84 per barrel, down from $7.92 per barrel in the third quarter mainly due to the higher average production in the fourth quarter. Lifting costs averaged $7.41 per barrel over the year 2018 compared to $8.52 per barrel in the year 2017. The 2018 average lifting costs were above guidance due to lower production than planned and additional costs related to mitigating salt related problems. Other costs of production include the Company’s share of production bonuses paid to the KRG, $1.7 million was paid in the fourth quarter of 2018, and of other costs prescribed under the Atrush PSC. Oil and gas assets are depleted using the unit of production method based on proved and probable reserves using estimated future prices and costs and accounting for future development expenditures necessary to bring those reserves into production. The reserves correspond to the Company’s entitlement to oil under the terms of the PSC. The depletion cost per entitlement barrel was $37.12 and $22.07, respectively for the three and twelve months ended December 31, 2018. Changes to depletion rates resulting from changes in reserve quantities and estimates of future development expenditure are reflected prospectively and the increase in the depletion cost in the fourth quarter of 2018 is attributable to a reclass of capital costs from E&E to PP&E at the end of 2018 and an increase in forecasted future development costs (for further information refer to the “Reserves and Resource” section below). General and administrative expense In $000 Salaries and benefits Legal, accounting and audit fees Management and consulting fees Listing costs and investor relations General and other office expenses Travel expenses Advertisements General and administrative expense ---------Three month period--------- Q4.2017 Q4.2018 Q3.2018 -----Twelve month period---- Q4.2017 Q4.2018 1,045 472 156 67 86 87 - 1,913 453 40 114 68 84 26 - 785 503 102 121 56 106 43 35 966 2,494 682 463 335 332 258 - 4,564 3,093 242 372 286 331 152 35 4,511 The higher general and administrative expense incurred in the year 2018 was principally due to legal and consulting services related to refinancing the Company’s bonds and towards acquiring an additional interest in Atrush and were offset by lower payroll costs relating to salary bonuses incurred by the Company’s Swiss subsidiary in the prior year. 4 The Company’s 2018 entitlement share included an adjustment for the exploration cost sharing arrangement between TAQA and GEP. TAQA and GEP had under the Atrush JOA agreed a priority arrangement for sharing their combined initial $49.9 million share of exploration cost oil revenues such that TAQA received the initial $10.8 million and GEP received the next $39.1 million. Thereafter cost oil revenues for these two parties is determined by their relative participating interests in the Atrush PSC. The Company’s entitlement share of oil sold in 2018 reflects a full recovery of the $39.1 million. 7 Share based payments expense In $000 ---------Three month period--------- Q4.2017 Q4.2018 Q3.2018 -----Twelve month period---- Q4.2017 Q4.2018 Share based payments expense - - - - 11 The Company uses the fair value method of accounting for stock options granted to directors, officers, employees and consultants whereby the fair value of all stock options granted is recorded as a charge to operations. The fair value of common share options granted is estimated on the date of grant using the Black-Scholes option pricing model. Share based payments expense results from the vesting of stock options granted over the vesting period which is normally two years after the grant date. The last stock option grant of January 19, 2015 is now fully vested and was fully expensed at the end of the first quarter of 2017. Depreciation and amortisation expense In $000 ---------Three month period--------- Q4.2017 Q4.2018 Q3.2018 ----Twelve month period----- Q4.2017 Q4.2018 Depreciation and amortisation expense 1 1 - 8 26 Depreciation and amortisation expense corresponds to cost of use of the furniture and IT equipment at the Company’s technical and administrative offices located in Switzerland and Kurdistan. Finance income In $000 ---------Three month period--------- Q4.2017 Q4.2018 Q3.2018 ----Twelve month period----- Q4.2017 Q4.2018 Interest on Atrush Development Cost Loan Interest on Atrush Feeder Pipeline Cost Loan Interest on deposits Total interest income Foreign exchange gain Total finance income 151 99 645 895 5 900 190 122 57 369 - 369 242 106 13 361 - 361 836 535 720 2,091 - 2,091 1,042 500 107 1,649 28 1,677 Under the terms of the 4th PSC Amendment and the Atrush Facilitation Agreement the Non-Government Contractors have agreed to pay their pro-rata share of the Feeder Pipeline costs and of the KRG’s share of Atrush development costs up to October 31, 2017. Thereafter these costs will be reimbursed to the Non-Government Contractors. The loan interest amounts reported in the year 2018 represent 7% per annum interest on the principal balances outstanding over this period. For further information on the loans refer to the discussion under the “Loans and receivables” section below. Interest on deposits represents bank interest earned on cash, investments and restricted cash held in interest bearing funds. The overall decrease in interest income reported in the year 2018 relative to the amount reported in 2017 is due to the decreasing loan principal balance over this period because of the loan payments received from the KRG, and partially offset by the increase in interest on deposits due to the higher level of interest-bearing funds held in 2018. 8 Finance cost In $000 ---------Three month period--------- Q4.2017 Q4.2018 Q3.2018 ----Twelve month period----- Q4.2017 Q4.2018 Interest charges on bonds at coupon rate Call premiums on early retirement of bonds Amortisation of bond transaction costs Interest expense on borrowings Foreign exchange loss Unwinding discount on decommissioning provision Total finance costs before borrowing costs capitalised Borrowing costs (capitalised as) / reversed from E&E 7,280 - 183 7,463 - 6 7,469 7,429 1,427 484 9,340 21 5 9,366 5,221 - 210 5,431 83 4 5,518 25,428 1,427 1,087 27,942 26 5 27,973 20,018 - 841 20,859 102 4 20,965 and PP&E assets Finance cost (122) (780) 284 (4,859) (8,770) 7,347 8,586 5,802 23,114 12,195 The increase in interest charges on bonds between the years 2018 and 2017 is principally due to the new ShaMaran bond issue which brought bonds outstanding before the issue of $186 million up to $240 million after the issue on July 5, 2018. In addition, the coupon rate on the new bonds increased to 12% from 11.5% coupon rate on the retired GEP bonds. Since the GEP bonds were retired earlier than the November 13, 2018 maturity date the GEP paid to bondholders call premiums in accordance with the terms of the related bond agreements. Borrowing costs are capitalised where they are directly attributable to the acquisition of, and preparation for their intended use, Atrush development assets. All other borrowing costs are recognised in profit or loss in the period in which they are incurred. The significant decrease in capitalised borrowing costs in 2018 is due to a significant number of development projects having been completed for their intended use. For further information on the Company’s borrowings refer to the discussion in the section below entitled “Borrowings”. Income tax expense In $000 ---------Three month period--------- Q4.2017 Q4.2018 Q3.2018 ----Twelve month period----- Q4.2017 Q4.2018 Income tax expense 25 12 14 64 85 Income tax expense relates to provisions for income taxes on service income generated in Switzerland which is based on costs incurred in procuring the services. The decrease in tax expense reported in the year ended December 31, 2018 is primarily due to lower taxable income in the Company’s Swiss subsidiary which decreased compared to 2017 due to lower costs of service. Capital Expenditures on Property Plant & Equipment (“PP&E”) The net book value of PP&E is principally comprised of development costs related to the Company’s share of Atrush PSC proved and probable reserves as estimated by McDaniel less the cumulative depletion costs corresponding to commercial production which commenced in July 2017. The movements in PP&E are explained as follows: In $000 Year ended December 31, 2018 Office equipment Oil and gas assets Total Year ended December 31, 2017 Office equipment Oil and gas assets Total Opening net book value Additions Reclass from intangible E&E assets Depletion and depreciation expense Net book value 184,918 17,356 21,794 (28,171) 195,897 3 12 - (4) 11 184,921 17,368 21,794 (28,175) 195,908 174,642 17,903 - (7,627) 184,918 16 3 - (16) 3 174,658 17,906 - (7,643) 184,921 During the year 2018 movements in PP&E were comprised of additions of $17.4 million (year 2017: $17.9 million), depletion and depreciation expense of $28.2 million (year 2017: $7.6 million) and a reclass to PP&E from E&E of $21.8 million (year 2017: $nil) which resulted in a net increase of $11.0 million to the net book value of PP&E assets. Net additions in 2018 included capitalised borrowing costs of $5.0 million (year 2017: $8.8 million). During the year 2018 plans were approved to produce and sell heavy oil which has resulted in the reclass from E&E to PP&E of $21.8 of heavy oil related project costs. 9 Capital Expenditures on Intangible Assets The net book value of Intangible assets is principally comprised of exploration and evaluation (“E&E”) assets which represent the Atrush Block exploration and appraisal costs related to the Company’s share of Atrush Block contingent resources as estimated by McDaniel. The movements in Intangible assets are explained as follows: In $000 Opening net book value Additions Reclass to PP&E Disposals Amortisation expense Net book value Year ended December 31, 2018 Software E&E & Licences assets Total Year ended December 31, 2017 Software E&E & Licences assets Total 89,113 506 (21,794) - - 67,825 6 3 - - (5) 4 89,119 509 (21,794) - (5) 67,829 88,972 141 - - - 89,113 35 2 - (21) (10) 6 89,007 143 - (21) (10) 89,119 During the year 2018 movements in intangible assets were comprised of net additions of $509 thousand (year 2017: $143 thousand), depreciation of $5 thousand (year 2017 $10 thousand) and a reclass of $21.8 million (year 2017: $nil) from E&E to PP&E resulting in a net decrease to intangible assets of $21.3 million. Net additions in 2018 included the reversal of borrowing costs of $123 thousand (year 2017: $16 thousand). Loans and receivables In November 2016 the Company entered into certain agreements with the KRG and other Atrush contractors for the reimbursement by the KRG to the Atrush contractors of certain Atrush exploration and development costs and pipeline costs incurred by KRG in the years 2013 through 2017 which were funded by the Atrush contractors. The Atrush Exploration Costs receivables, which relate to a share of the KRG’s development costs carried by ShaMaran prior to the year 2016 and deemed to be exploration costs under the Atrush PSC, are repaid through an accelerated petroleum cost recovery arrangement. The Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost Loan are being repaid with interest at 7% per annum in 24 equal monthly instalments ending in October 2019. The Company was owed amounts for its entitlement share of oil deliveries made to the KRG during the last three months of the year. At year end the Company had loans and receivables outstanding as follows: In $000 As at December 31, Atrush Exploration Costs receivable Accounts receivable on Atrush oil sales Atrush Development Cost Loan Atrush Feeder Pipeline Cost Loan Total loans and receivables 2018 34,898 14,531 7,136 4,718 61,283 2017 37,247 13,957 16,018 9,751 76,973 In the year 2018 the Company received principal plus interest payments totalling $11.3 million for Atrush Development Cost Loan and $6.9 million for the Atrush Feeder Pipeline Cost Loan, as well as $2.3 million of Atrush Exploration Cost receivables. In the year 2019 up to the date of the MD&A the Company received $14.0 million in total payments for loans and receivables balances outstanding at December 31, 2018, comprised of $10.9 million in total payments for its entitlement share of oil sales for the months of October and November 2018, $2.6 million for Atrush Development Cost Loan and Atrush Feeder Pipeline Cost Loan balances outstanding and $0.5 million in reimbursements of the Atrush Exploration Costs receivable. 10 Borrowings On July 5, 2018 the Company issued $240 million of senior unsecured bonds (“the ShaMaran bonds”). The ShaMaran bonds have a five-year maturity without amortization and carry 12% fixed semi-annual coupon. Holders of $136 million of the $186.4 million of previously outstanding bonds (“GEP bonds”) of General Exploration Partners, Inc. (“GEP”), a wholly owned subsidiary of the Company, agreed to early redeem their bonds in exchange for receiving an equivalent amount of ShaMaran bonds. As a result the Company received $104 million ($100.4 million net of related transaction costs) of cash proceeds from the ShaMaran bond issue. An amount of $50.4 million of the cash proceeds, with an additional $3 million of the Company’s cash, have been used to early retire the remaining GEP bonds and the remaining $53 million of the cash proceeds were held by the Company in an escrow account pledged to the bondholders (the “Marathon Pledged Account”) on the balance sheet date, pending release to the Company upon the closing of the purchase by the Company of an additional interest in the Atrush asset under terms prescribed in the bond agreement. On December 31, 2018, in accordance with the terms of the ShaMaran bonds the Company contributed $14.4 million, representing one semi-annual interest payment, to a Debt Service Retention Account (“DSRA”) and pledged to the bondholders as security for the Company’s obligations under the ShaMaran bonds. The amounts on deposit in the Marathon Pledged Account and the DSRA resulted in total restricted cash of $67.9 million on the balance sheet date, including interest earned of $484 thousand. The movements in borrowings are explained as follows: In $000 As at December 31, Opening balance Bond issued – net of transaction costs Interest charges at coupon rate Call premiums on early retirement of bonds Amortisation of bond transaction costs Bonds issued as interest payments Payment to Bondholders – interest and call premiums Bonds retired Ending balance - Current portion: accrued bond interest expense - Current portion: borrowings - Non-current portion: borrowings 2018 188,491 236,361 25,428 1,427 1,087 - (15,575) (186,422) 250,797 14,080 - 236,717 2017 167,632 - 20,018 - 841 19,721 (19,721) - 188,491 2,799 185,692 - Events after the reporting period related to Borrowings On January 5, 2019 the Company issued the first semi-annual interest payment to ShaMaran bondholders in the amount of $14.4 million. • • On February 1, 2019, bondholders approved of certain amendments to the ShaMaran Bonds agreement as follows: • funds on deposit in the DSRA may be used by the Company to fund the Acquisition and for general corporate purposes; funds in the Marathon Pledged Account will be used by the Company to prepay $50 million of ShaMaran Bonds plus accrued interest; the Company will reduce the aggregate outstanding amount of the Bond Issue to a maximum of $175 million on or before July 2020; in case the Acquisition is not closed by July 4, 2019 there will be a one-time step up in bond coupon interest by 1% per annum; and the Liquidity Guarantee will remain in force until the Company has funded the DSRA with 12 months of bond coupon interest. • • On February 8, 2019, the Company repaid $50 million of ShaMaran Bonds and $550 thousand of related accrued interest. At the date the financial statements were approved there were $190 million of ShaMaran Bonds outstanding. Nemesia S.à.r.l. (“Nemesia”), a company controlled by a trust settled by the estate of the late Adolf H. Lundin, agreed to guarantee the Company’s obligations under the ShaMaran Bonds agreement up to an amount of $22.8 million (the “Liquidity Guarantee”) representing one year of coupon interest of $190 million of ShaMaran Bonds now outstanding. In exchange for providing the Liquidity Guarantee the Company issued Nemesia 2,000,000 common shares of ShaMaran. In case of a draw down on the Liquidity Guarantee, the Company is required to issue to Nemesia a further 50,000 shares of ShaMaran for each $500 thousand drawn down per month until the drawn amount is repaid. Nemesia are a related party after this event in 2019. 11 The remaining contractual obligations under the amended ShaMaran Bonds at the date of this MD&A, which are comprised of the repayment of principal and interest expense based on undiscounted cash flows at payment date, reflect the repayment of $50.6 million of principal and interest on February 8, 2019, and are based on the current $190 million of bonds outstanding thereafter until a further reduction in ShaMaran Bonds outstanding to $175 million is completed in July 2020, are as follows: In $000 March 8 to December 31, 2019 Year ended December 31, 2020 Three years ended December 31, 2023 Total 11,400 37,800 238,000 287,200 SELECTED QUARTERLY FINANCIAL INFORMATION The following is a summary of selected quarterly financial information for the Company: (In $000, except per share data) Continuing operations Revenues Cost of goods sold General and admin. expense Share based payments expense Depreciation and amortisation Finance cost Finance income Income tax expense Dec-31 2018 Sep-30 2018 Jun-30 2018 Mar 31 2018 Dec 31 2017 Sep 30 2017 Jun 30 Mar 31 2017 2017 For the quarter ended 14,531 (15,969) (1,913) - (1) (7,347) 900 (25) 13,240 (6,945) (785) - (1) (8,586) 369 (12) 15,328 (6,990) (941) - (2) (3,016) 444 (11) 26,501 (12,168) (925) - (4) (4,230) 443 (16) 13,907 (9,426) (966) - - (5,802) 361 (14) 3,782 (4,583) (1,637) - (8) (3,436) 525 (36) - - (818) - (8) (1,482) 439 (14) - - (1,090) (11) (10) (1,503) 352 (21) Net (loss) / income (9,824) (2,720) 4,812 9,601 (1,940) (5,393) (1,883) (2,283) Basic and diluted net (loss) / inc in $ per share (0.005) (0.001) 0.002 0.004 (0.001) (0.002) (0.001) (0.001) Summary of Principal Changes in the Fourth Quarter Financial Information In the fourth quarter of 2018 production from the Atrush Block and work on the Atrush development program continued. The net loss was principally driven by $10.3 million of depletion costs, a non-cash expense, included in cost of goods sold, as well as the inclusion of $1.7 million of production bonuses paid to the KRG, and relating to the 10 million barrel cumulative production milestone reached in November 2018, as well as the financing costs of $7.3 million which reflected $240 million of bond principal outstanding during the period. The bonds outstanding were reduced to $190 million on February 8, 2019. LIQUIDITY AND CAPITAL RESOURCES Working capital at December 31, 2018 was positive $112.9 million compared to negative $155.6 million at December 31, 2017. The increase in working capital since December 31, 2017, is principally due to significant operational cash flows over the past year and to the re-financing of the Company’s bonds in the third quarter of 2018. Refer also to the discussion above under “Borrowings”. The overall cash position of the Company increased by $87.2 million during the year 2018 compared to an increase in cash of $0.8 million during the same period of 2017. The main components of the movement in funds are discussed in the following paragraphs. 12 The operating activities of the Company during the year 2018 resulted in an increase in the cash position of $47.4 million compared to a decrease of $8.8 million in the cash position during the comparable period of 2017. The increase in the cash position is explained by net income of $1.9 million plus $45.5 million of net positive cash adjustments from working capital items, net borrowing costs and non-cash expenses. Net cash inflows from investing activities in 2018 were $5.5 million compared to cash outflows of $16.7 million during the same period in 2017. Cash inflows from investing activities in 2018 were comprised of cash inflows of $18.4 million in payments by the KRG of Atrush loans and receivables, which includes interest on the loans, net of cash outflows of $12.9 million on investments in the Atrush Block development work program. Net cash inflows to financing activities in the year were $34.4 million compared to $26.4 million of cash inflows in the comparable period in 2017. The Company received $100.4 million of net cash proceeds from the ShaMaran bond issue net of related transaction costs. $15.6 million of coupon interest payments made to bondholders as well as $50.4 million to early retire GEP bonds which were not exchanged for new ShaMaran bonds. The consolidated financial statements were prepared on the going concern basis which assumes that the Company will be able to realise its assets and liabilities in the normal course of business as they come due in the foreseeable future. OUTSTANDING SHARE DATA AND STOCK OPTIONS The Company had 2,158,631,534 outstanding shares at December 31, 2018, (2,183,631,534 outstanding shares after dilution). On January 23, 2019, the Company issued to Nemesia 2,000,000 common shares of ShaMaran in accordance with the terms of the Liquidity Guarantee. Therefore, at the date of this MD&A the Company had 2,160,631,534 outstanding shares. Refer also to the discussion under the Borrowings section above. The average outstanding shares during the year 2018 were 2,158,631,534 before dilution (2017: 2,129,042,493) and 2,183,631,534 after dilution (2017: 2,157,207,493). The Company has established share unit plans and a share purchase option plan whereby a committee of the Company’s Board may, from time to time, grant up to a total of 10% of the issued share capital to directors, officers, employees or consultants. The number of shares issuable under these plans at any specific time to any one recipient shall not exceed 5% of the issued and outstanding common shares of the Company. Under the share unit plans the Company may grant performance share units (“PSU”), restricted share units (“RSU”) or deferred share units (“DSU”). PSU grants may be awarded annually to employees, directors or consultants (“Participants”) based on the fulfilment of defined Company and individual performance parameters. RSU grants may be awarded to Participants annually based on the fulfilment of defined Company performance parameters. RSUs and PSUs will vest based on the conditions described in the relevant grant agreement and, in any case, no later than the end of the third calendar year following the date of the grant. DSU’s may be awarded annually to non-employee directors of the Company based on the performance of the Company and vest immediately at the time of grant; however DSUs may not be redeemed until a minimum period of three months has passed following the end of service as a director of the Company. The share unit plans provide for redemption of the share units by way of payment in cash, shares or a combination of cash and shares. Under the option plan the term of any options granted under the option plan will be fixed by the Board and may not exceed five years from the date of grant. A four month hold period may be imposed by the stock exchange from the date of grant. Vesting terms are at the discretion of the Board. All issued share options have terms of five years and vest over two years from grant date. The exercise prices reflect trading values of the Company’s shares at grant date. At December 31, 2018 there were 25,000,000 stock options outstanding under the Company’s employee incentive stock option plan. 3,165,000 stock options expired during the current year to date (year 2017: nil). No stock options were forfeited or exercised in 2018 (year 2017: nil). There has been no further change in the number of stock options outstanding from December 31, 2018, to the date of this MD&A. There were no grants of share units at the balance sheet date. The Company has no warrants outstanding. 13 OFF BALANCE SHEET ARRANGEMENTS The Company has no off-balance sheet arrangements. RELATED PARTY TRANSACTIONS In $000 Bennett-Jones Namdo Management Services Ltd. Lundin Petroleum AB Total Purchases of services during the year 2018 2017 Amounts owing at December 31, 2017 2018 51 34 104 189 45 50 204 299 - - - - - - 18 18 Bennett-Jones is a law firm in which an officer of the Company is a partner and has provided legal services to the Company. Amounts reported under Bennett Jones are inclusive of services provided to the Company by McCullough O’Connor Irwin LLP, which merged with Bennett Jones on June 1, 2018, where the same officer of the Company was previously a partner. Namdo Management Services Ltd. is a private corporation affiliated with a shareholder of the Company and has provided corporate administrative support and investor relations services to the Company. The Company received services from various subsidiary companies of Lundin Petroleum AB (“Lundin”), a shareholder of the Company until June 21, 2018, when Lundin sold its ShaMaran shares. Lundin charges from January 1 to June 21, 2018 of $104 (year 2017: $204) were comprised of office rental, administrative and building services of $88 (year 2017: $177), technical service costs of $nil (year 2017: $1) and investor relations services of $16 (year 2017: $27). All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with parties at arm’s length. Also refer to the discussion under the “Outstanding Share Data and Stock Options” section above. COMMITMENTS AND CONTINGENCIES Atrush Block Production Sharing Contract Under the terms of the Atrush PSC the development period is for 20 years after declaration of commerciality (November 7, 2012) with an automatic right to a five-year extension and the possibility to extend for an additional five years. All qualifying petroleum costs incurred by the Contractors shall be recovered from a portion of available petroleum production, defined under the terms of the Atrush PSC. All modifications to the Atrush PSC are subject to the approval of the KRG. The Company is responsible for its pro-rata share of the costs incurred in executing the development work program on the Atrush Block which commenced on October 1, 2013.The Company is responsible for its pro-rata share of the costs incurred in executing the development work program on the Atrush Block which commenced on October 1, 2013. As at December 31, 2018, the outstanding commitments of the Company were as follows: In $000 For the year ended December 31, Atrush Block development Office and other Total commitments 2019 47,583 39 47,622 2020 120 - 120 2021 Thereafter Total 120 - 120 1,328 - 1,328 49,151 39 49,190 Amounts relating to Atrush Block development represent the Company’s unfunded paying interest share of 20.1% of the approved 2019 work program and other obligations under the Atrush PSC. Under the terms of the Atrush PSC the Company will owe a share of production bonuses payable to the KRG when cumulative oil production from Atrush reaches production milestones defined in the Atrush PSC as follows: $13.3 million at 25 million barrels (ShaMaran share: $3.6 million); and $23.3 million at 50 million barrels (ShaMaran share: $6.2 million). 14 PROPOSED TRANSACTIONS ShaMaran entered into agreements on December 26, 2018 to acquire jointly with TAQA the 15% interest in the Atrush Block held by MIOC. Following close of these agreements ShaMaran’s working interest in Atrush will increase from 20.1% to 27.6%. The parties to the agreements are currently in the process of obtaining the consent of the KRG. The Company continues to evaluate other new opportunities. CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICIES Accounting Estimates The consolidated financial statements of the Company have been prepared by management using IFRS. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the period. Specifically, estimates are utilised in calculating depletion, asset retirement obligations, fair values of assets on acquisition of control, share-based payments, amortisation and impairment write-downs as required. Actual results could differ from these estimates and differences could be material. Significant Accounting Policies The Company adopted IFRS 15, Revenue from Contracts with Customers and IFRS 9, Financial Instruments effective January 1, 2018. Refer to Note 3 “Significant Accounting Policies” in the Company’s Consolidated Financial Statements for the year ended December 31, 2018, for further discussion. Other standards, amendments and interpretations, which are effective for the financial year beginning on January 1, 2018, have been assessed and do not have a material impact to the Company. New Accounting Standards Issued But Not Yet Applied Standards and interpretations issued but not yet effective up to the date of issuance of the financial statements are listed below. IFRS 16: Leases will replace IAS 17 Leases and requires assets and liabilities arising from all leases, with some exceptions, to be recognized on the balance sheet. The new standard will be effective for annual periods beginning on or after January 1, 2019. The Company currently has no outstanding leases. There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions. Accounting for Oil and Gas Operations The Company follows the successful efforts method of accounting for its oil and gas operations. Under this method acquisition costs of oil and gas properties, costs to drill and equip exploratory and appraisal wells that are likely to result in proved reserves and costs of drilling and equipping development wells are capitalised and subject to annual impairment assessment. Exploration well costs are initially capitalised and, if subsequently determined to have not found sufficient reserves to justify commercial production, are charged to exploration expense. Exploration well costs that have found sufficient reserves to justify commercial production, but whose reserves cannot be classified as proved, continue to be capitalised if sufficient progress is being made to assess the reserves and economic viability of the well and or related project. Capitalised costs of proved oil and gas properties are depleted using the unit of production method based on estimated gross proved and probable reserves of petroleum and natural gas as determined by independent engineers. Successful exploratory wells and development costs and acquired resource properties are depleted over proved and probable reserves. Acquisition costs of unproved reserves are not depleted or amortised while under active evaluation for commercial reserves. Costs associated with significant development projects are depleted once commercial production commences. A revision to the estimate of proved and probable reserves can have a significant impact on earnings as they are a key component in the calculation of depreciation, depletion and accretion. 15 Producing properties and significant unproved properties are assessed annually, or more frequently as economic events dictate, for potential indicators of impairment. Economic events which would indicate impairment include: • • • • • The period for which the Company has the right to explore in the specific area has expired during the period or will expire in the near future and is not expected to be renewed. Substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned. Exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the Company has decided to discontinue such activities in the specific area. Sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amounts of E&E and oil and gas assets is unlikely to be recovered in full from successful development or by sale. Extended decreases in prices or margins for oil and gas commodities or products. • A significant downwards revision in estimated volumes or an upward revision in future development costs. For impairment testing the assets are aggregated into cash generating unit (“CGU”) cost pools based on their ability to generate largely independent cash flows. The recoverable amount of a CGU is the greater of its fair value less costs to sell and its value in use. Fair value is determined to be the amount for which the asset could be sold in an arm’s length transaction. Value in use is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU. Where conditions giving rise to the impairment subsequently reverse the effect of the impairment charge is also reversed as a credit to the statement of comprehensive income net of any depreciation that would have been charged since the impairment. A substantial portion of the Company’s exploration and development activities are conducted jointly with others. RESERVES AND RESOURCE ESTIMATES The Company engaged McDaniel to evaluate 100% of the Company’s reserves and resource data at December 31, 2018. The conclusions of this evaluation have been presented in a Detailed Property Report which has been prepared in accordance with standards set out in the Canadian National Instrument NI 51-101 and Canadian Oil and Gas Evaluation Handbook (“COGEH”). The Company’s crude oil reserves as of December 31, 2018 were, based on the Company’s working interest of 20.1 percent in the Atrush Block, estimated to be as follows: Company estimated reserves (diluted) As of December 31, 2018 Proved Developed Proved Undeveloped Total Proved Probable Total Proved & Probable Possible Total Proved, Probable & Possible Light/Medium Oil (Mbbl)(1) Gross(2) Net(3) Heavy Oil (Mbbl)(1) Gross(2) Net(3) 4,839 2,695 - - 3,402 1,940 484 272 8,241 4,635 11,603 5,761 19,844 10,397 10,227 3,256 30,071 13,653 484 272 740 369 1,224 641 776 267 2,000 908 Notes: (1) The Atrush Field contains crude oil of variable density. Fluid type is classified according to COGEH: Light/Medium Oil is based on density less than 920 kg/m3 and Heavy Oil is between 920 and 1000 kg/m3. (2) Company gross reserves are based on the Company’s 20.1 percent working interest share of the property gross reserves. (3) Company net reserves are based on Company share of total Cost and Profit Revenues. Note, as the government pays income taxes on behalf of the Company out of the government's profit oil share, the net reserves were based on the effective pre-tax profit revenues by adjusting for the tax rate. The Company’s crude oil and natural gas contingent resources as of December 31, 2018, were estimated to be as follows, based on a Company working interest of 20.1 percent in the Atrush Block: 16 Company estimated contingent resources (diluted) (1) (2)(4)(5) As of December 31, 2018 Light/Medium Oil (Mbbl)(3) Gross Heavy Oil (Mbbl)(3) Gross Natural Gas (MMcf) Gross Low Estimate (1C) Best Estimate (2C) High Estimate (3C) Risked Best Estimate 10,691 10,735 11,004 8,588 21,039 43,153 70,908 34,522 5,029 9,058 13,763 453 Notes: (1) Based on a 20.1 percent Company working interest share of the property gross resources. (2) There is no certainty that it will be commercially viable to produce any portion of the resources. (3) The Atrush Field contains crude oil of variable density. Fluid type is classified according to COGEH: Light/Medium Oil is based on density less than 920 kg/m3 and Heavy Oil is between 920 and 1000 kg/m3. (4) These are unrisked contingent resources that do not account for the chance of development which is defined as the probability of a project being commercially viable. Quantifying the chance of development requires consideration of both economic contingencies and other contingencies, such as legal, regulatory, market access, political, social license, internal and external approvals and commitment to project finance and development timing. As many of these factors are extremely difficult to quantify, the chance of development is uncertain and must be used with caution. The chance of development was estimated to be 80 percent for the Crude Oil and 5 percent for the Natural Gas. (5) The contingent resources are sub-classified as “development unclarified” with an “undetermined” economic status. The contingent resources represent the likely recoverable volumes associated with further phases of development after Phase 1 which differ from reserves mainly due to the uncertainty over the future development plan which will depend in part on Phase 1 production performance and the HOWET planned for the first half of 2019. Prospective resources have not been re-evaluated since December 31, 2013. Risks in estimating resources There are a number of uncertainties inherent in estimating the quantities of reserves and resources including factors which are beyond the control of the Company. Estimating reserves and resources is a subjective process and the results of drilling, testing, production and other new data after the date of an estimate may result in revisions to original estimates. Reservoir parameters may vary within reservoir sections. The degree of uncertainty in reservoir parameters used to estimate the volume of hydrocarbons, such as porosity, net pay and water saturation, may vary. The type of formation within a reservoir section, including rock type and proportion of matrix and or fracture porosity, may vary laterally and the degree of reliability of these parameters as representative of the whole reservoir may be proportional to the overall number of data points (wells) and the quality of the data collected. Reservoir parameters such as permeability and effectiveness of pressure support may affect the recovery process. Recovery of reserves and resources may also be affected by the availability and quality of water, fuel gas, technical services and support, local operating conditions, security, performance of the operating company and the continued operation of well and plant equipment. Additional risks associated with estimates of reserves and resources include risks associated with the oil and gas industry in general which include normal operational risks during drilling activity, development and production; delays or changes in plans for development projects or capital expenditures; the uncertainty of estimates and projections related to production, costs and expenses; health, safety, security and environmental risks; drilling equipment availability and efficiency; the ability to attract and retain key personnel; the risk of commodity price and foreign exchange rate fluctuations; the uncertainty associated with dealing with governments and obtaining regulatory approvals; performance and conduct of the Operator; and risks associated with international operations. The Company’s project is in the early production stage and, as such, additional information must be obtained by further drilling and testing to ultimately determine the economic viability of developing any of the contingent or prospective resources. There is no certainty that the Company will be able to commercially produ ce any portion of its contingent or prospective resources. Any significant change, in particular, if the volumetric resource estimates were to be materially revised downwards in the future, could negatively impact investor confidence and ultimately impact the Company’s performance, share price and total market capitalisation. The Company has engaged professional geologists and engineers to evaluate reservoir and development plans; however, process implementation risk remains. The Company’s reserves and resource estimations are based on data obtained by the Company which has been independently evaluated by McDaniel. 17 FINANCIAL INSTRUMENTS The Company’s financial instruments currently consist of cash, cash equivalents, advances to joint operations, other receivables, borrowings, accounts payable and accrued expenses, accrued interest on bonds, provisions for decommissioning costs, and current tax liabilities. The Company classifies its financial assets and liabilities at initial recognition in the following categories: • • • Financial assets and liabilities at fair value through profit or loss are those assets and liabilities acquired principally to sell or repurchase in the short-term and are recognised at fair value. Transaction costs are expensed in the statement of comprehensive income and gains or losses arising from changes in fair value are also presented in the statement of comprehensive income within other gains and losses in the period in which they arise. Financial assets and liabilities at fair value through profit or loss are classified as current except for the portion expected to be realised or paid beyond twelve months of the balance sheet date, which is classified as non-current. Financial assets carried at amortised cost comprise of loans, receivables and cash and cash equivalents with fixed or determinable payments that are not quoted on an active market and are generally included within current assets due to their short-term nature and are classified as financial assets when the Company has a right to cash collection. If collection of the amounts is expected in one year or less they are classified as current assets. If not, they are presented as non-current assets. Loans and receivables are initially recognised at fair value and are subsequently measured at amortised cost using the effective interest method less any provision for impairment. Financial liabilities at amortised cost comprise of trade and other payables and are initially recognised at the fair value of the amount expected to be paid and are subsequently measured at amortised cost using the effective interest rate method. Financial liabilities are classified as current liabilities unless the Company has an unconditional right to defer settlement for at least 12 months after the balance sheet date. With the exception of borrowings, accrued interest on bonds and provisions for decommissioning costs, which have fair value measurements based on valuation models and techniques where the significant inputs are derived from quoted prices or indices, the fair values of the Company’s other financial instruments did not require valuation techniques to establish fair values as the instrument was either cash and cash equivalents or, due to the short term nature, readily convertible to or settled with cash and cash equivalents. The Company is exposed in varying degrees to a variety of financial instrument related risks which are discussed in the following sections: Financial Risk Management Objectives The Company’s management monitors and manages the Company’s exposure to financial risks facing the operations. These financial risks include market risk (including commodity price, foreign currency and interest rate risks), credit risk and liquidity risk. The Company does not presently hedge against these risks as the benefits of entering into such agreements is not considered to be significant enough as to outweigh the significant cost and administrative burden associated with such hedging contracts. Commodity price risk: The prices that the Company receives for its oil and gas production may have a significant impact on the Company’s revenues and cash flows provided by operations. World prices for oil and gas are characterised by significant fluctuations that are determined by the global balance of supply and demand and worldwide political developments and, in particular, the price received for the Company’s oil and gas production in Kurdistan is dependent upon the Kurdistan government and its ability to export production outside of Iraq. A decline in the price of ICE Brent Crude oil, a reference in determining the price at which the Company can sell future oil production, could adversely affect the amount of funds available for capital reinvestment purposes as well as the Company’s value in use calculations for impairment test purposes. The Company does not hedge against commodity price risk. Foreign currency risk: The substantial portion of the Company’s operations require purchases denominated in USD, which is the functional and reporting currency of the Company and the currency in which the Company maintains the substantial portion of its cash and cash equivalents. Certain of its operations require the Company to make purchases denominated in foreign currencies, which are currencies other than USD and correspond to the various countries in which the Company conducts its business, most notably, Swiss Francs (“CHF”) and Canadian dollars (“CAD”). As a result, the Company holds some cash and cash equivalents in foreign currencies and is therefore exposed to foreign currency risk due to exchange rate fluctuations between the foreign currencies and the USD. The Company considers its foreign currency risk is limited because it holds relatively insignificant amounts of foreign currencies at any point in time and since its volume of transactions in foreign currencies is currently relatively low. The Company has elected not to hedge its exposure to the risk of changes in foreign currency exchange rates. 18 Interest rate risk: The Company earns interest income at variable rates on its cash and cash equivalents and is therefore exposed to interest rate risk due to a fluctuation in short-term interest rates. The Company’s policy on interest rate management is to maintain a certain amount of funds in the form of cash and cash equivalents for short-term liabilities and to have the remainder held on relatively short-term deposits. ShaMaran is leveraged though bond financing at the corporate level. However, the Company is not exposed to interest rate risks associated with the bonds as the interest rate is fixed until July 2023. Credit risk: Credit risk is the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Company. The Company is primarily exposed to credit risk on its cash and cash equivalents, loans and receivables and other receivables. The Company manages credit risk by monitoring counterparty ratings and credit limits and by maintaining excess cash and cash equivalents on account in instruments having a minimum credit rating of R-1 (mid) or better (as measured by Dominion Bond Rate Services) or the equivalent thereof according to a recognised bond rating service. The carrying amounts of the Company’s financial assets recorded in the consolidated financial statements represent the Company’s maximum exposure to credit risk. Liquidity risk: Liquidity risk is the risk that the Company will have difficulties meeting its financial obligations as they become due. In common with many oil and gas exploration companies, the Company raises financing for its exploration and development activities in discrete tranches to finance its activities for limited periods. The Company seeks to acquire additional funding as and when required. The Company anticipates making substantial capital expenditures in the future for the acquisition, exploration, development and production of oil and gas reserves and as the Company’s project moves further into the development stage, specific financing, including the possibility of additional debt, may be required to enable future development to take place. The financial results of the Company will impact its access to the capital markets necessary to undertake or complete future drilling and development programs. There can be no assurance that debt or equity financing, or future cash generated by operations, would be available or sufficient to meet these requirements or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The Company manages liquidity risk by maintaining adequate cash reserves and by continuously monitoring forecast and actual cash flows. Annual capital expenditure budgets are prepared, which are regularly monitored and updated as considered necessary. In addition, the Company requires authorisations for expenditure on both operating and non-operating projects to further manage capital expenditures. RISKS AND UNCERTAINTIES ShaMaran Petroleum Corp. is engaged in the exploration, development and production of crude oil and natural gas and its operations are subject to various risks and uncertainties which include but are not limited to those listed below. If any of the risks described below materialise the effect on the Company’s business, financial condition or operating results could be materially adverse. The following sections describe material risks identified by the Company; however, risks and uncertainties of which the Company is not currently aware or currently believes to be immaterial could develop and may adversely affect the Company’s business, financial condition or operating results. For more information on risk factors which may affect the Company’s business refer also to the discussion of risks under the “Reserves and Resources” and “Financial Instruments” sections of this MD&A above, as well as to the “Risk Factors” section of its Annual Information Form, which is available for viewing both on the Company’s web-site at www.shamaranpetroleum.com and on SEDAR at www.sedar.com, under the Company’s profile. Political and Regional Risks International operations: Oil and gas exploration, development and production activities in emerging countries are subject to significant political, social and economic uncertainties which are beyond ShaMaran’s control. Uncertainties include, but are not limited to, the risk of war, terrorism, criminal activity, expropriation, nationalisation, renegotiation or nullification of existing or future contracts, the imposition of international sanctions, a change in crude oil or natural gas pricing policies, a change in taxation policies, a limitation on the Company’s ability to export, and the imposition of currency controls. The materialisation of these uncertainties could adversely affect the Company’s business including, but not limited to, increased costs associated with planned projects, impairment or termination of future revenue generating activities, impairment of the value of the Company’s assets and or its ability to meet its contractual commitments as they become due. 19 Political uncertainty: ShaMaran’s assets and operations are in Kurdistan, a federally recognised semi-autonomous political region in Iraq, and may be influenced by political developments between Kurdistan and the Iraq federal government, as well as political developments of neighbouring states within MENA region, Turkey, and surrounding areas. Kurdistan and Iraq have a history of political and social instability. As a result, the Company is subject to political, economic and other uncertainties that are not within its control. These uncertainties include, but are not limited to, changes in government policies and legislation, adverse legislation or determinations or rulings by governmental authorities and disputes between the Iraq federal government and Kurdistan. There is a risk that levels of authority of the KRG, and corresponding systems in place, could be transferred to the Iraq federal government. Changes to the incumbent political regime could result in delays in operations and additional costs which could materially adversely impact the operations and future prospects of the Company and could have a material adverse effect on the Company's business and financial condition. Refer also to the discussion in the section below under “Risks associated with petroleum contracts in Iraq.” International boundary disputes: Although Kurdistan is recognised by the Iraq constitution as a semi-autonomous region, its geographical extent is neither defined in the Iraq constitution nor agreed in practice between the Federal Government and the KRG. There are ongoing differences between the KRG and the Federal Government regarding certain areas which are commonly known as “disputed territories”. The Company believes that its current area of operation is not within the “disputed territories”. Industry and Market Risks Exploration, development and production risks: ShaMaran’s business is subject to all the risks and hazards inherent in businesses involved in the exploration, development, production and marketing of oil and natural gas, many of which cannot be overcome even with a combination of experience, knowledge and careful evaluation. The risks and hazards typically associated with oil and gas operations include drilling of unsuccessful wells, fire, explosion, blowouts, sour gas releases, pipeline ruptures and oil spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property or the environment, or in personal injury. The Company is not fully insured against all of these risks, nor are all such risks insurable and, as a result, these risks could still result in adverse effects to the Company’s business not fully mitigated by insurance coverage including, but not limited to, increased costs or losses due to events arising from accidents or other unforeseen outcomes including clean-up, repair, containment and or evacuation activities, settlement of claims associated with injury to personnel or property, and or loss of revenue as a result of downtime due to accident. General market conditions: ShaMaran’s business and operations depend upon conditions prevailing in the oil and gas industry including the current and anticipated prices of oil and gas and the global economic activity. A reduction of the oil price, a general economic downturn, or a recession could result in adverse effects to the Company’s business including, but not limited to, reduced cash flows associated with the Company’s future oil and gas sales. Worldwide crude oil commodity prices are expected to remain volatile in the near future as a result of global supply and demand balances, actions taken by the Organization of the Petroleum Exporting Countries ("OPEC"), and ongoing global credit and liquidity concerns. This volatility may affect the Company's ability to obtain equity or debt financing on acceptable terms. Competition: The petroleum industry is intensely competitive in all aspects including the acquisition of oil and gas interests, the marketing of oil and natural gas, and acquiring or gaining access to necessary drilling and other equipment and supplies. ShaMaran competes with numerous other companies in the search for and acquisition of such prospects and in attracting skilled personnel. ShaMaran’s competitors include oil companies which have greater financial resources, staff and facilities than those of the Company. ShaMaran’s ability to increase reserves in the future will depend on its ability to develop its present property, to select and acquire suitable producing properties or prospects on which to conduct future exploration and to respond in a cost-effective manner to economic and competitive factors that affect the distribution and marketing of oil and natural gas. Reliance on key personnel: ShaMaran’s success depends in large measure on certain key personnel and directors. The loss of the services of such key personnel could negatively affect ShaMaran’s ability to deliver projects according to plan and result in increased costs and delays. ShaMaran has not obtained key person insurance in respect of the lives of any key personnel. In addition, competition for qualified personnel in the oil and gas industry is intense and there can be no assurance that ShaMaran will be able to attract and retain the skilled personnel necessary for the operation and development of its business. 20 Business Risks Risks associated with petroleum contracts in Iraq: The Iraq oil ministry has historically disputed the validity of the KRG’s production sharing contracts and, as a result indirectly, the Company’s right and title to its oil and gas assets. The KRG is disputing the claims and has stated that the contracts are compliant with the Iraq constitution. There is currently no assurance that production sharing contracts agreed with the KRG are enforceable or binding in accordance with ShaMaran’s interpretation of their terms or that, if breached, the Company would have remedies. The Company believes that it has valid title to its oil and gas assets and the right to explore for and produce oil and gas from such assets under the Atrush PSC. However, should the Iraq federal government pursue and be successful in a claim that the production sharing contracts agreed with the KRG are invalid, or should any unfavourable changes develop which impact on the economic and operating terms of the Atrush PSC, it could result in adverse effects to the Company’s business including, but not limited to, impairing the Company’s claim and title to assets held, and or increasing the obligations required, under the Atrush PSC. Government regulations, licenses and permits: The Company is affected by changes in taxes, regulations and other laws or policies affecting the oil and gas industry generally as well as changes in taxes, regulations and other laws or policies applicable to oil and gas exploration and development in Kurdistan specifically. The Company’s ability to execute its projects may be hindered if it cannot secure the necessary approvals or the discretion is exercised in a manner adverse to the Company. The taxation system applicable to the operating activities of the Company in Kurdistan is pursuant to the Oil and Gas Law governed by general Kurdistan tax law and the terms of its production sharing contracts. However, it is possible that the arrangements under the production sharing contracts may be overridden or negatively affected by the enactment of any future oil and gas or tax law in Iraq or Kurdistan which could result in adverse effects to the Company’s business including, but not limited to, increasing the Company’s expected future tax obligations associated with its activities in Kurdistan. Marketing, markets and transportation: The export of oil and gas and payments relating to such exports from Kurdistan remains subject to uncertainties which could negatively impact on ShaMaran’s ability to export oil and gas and receive payments relating to such exports. Potential government regulation relating to price, quotas and other aspects of the oil and gas business could result in adverse effects to the Company’s business including, but not limited to, impairing the Company’s ability to export and sell oil and gas and receive full payment for all sales of oil and gas. Payments for oil exports: Companies who have exported oil from Kurdistan since the year 2009 have reported significant amounts outstanding for past oil exports. Cash payments to oil companies for oil exported from Kurdistan has been under control of the KRG since the beginning of exports in 2009. Since February 1, 2016, when the KRG announced an interim measure whereby monthly payments to oil companies would be made based on an agreed mechanism, the KRG has established a relatively consistent record of delivering regular monthly payments to oil companies for their entitlement revenues in respect of monthly petroleum production, with producers’ most recent reports indicating having received in February 2019 full payments for November 2018 oil exported. Nevertheless there remains a risk that the Company may face significant delays in the receipt of cash for its entitlement share of future oil exports. Paying interest: On November 7, 2016 the KRG exercised its back-in right under the terms of the Atrush PSC and acquired a 25% participating interest. Upon the commencement of oil production exports from Atrush the KRG is required to pay its share of project development costs. There is a risk that the Contractors may be exposed to fund the KRG share of future project development costs. Default under the Atrush PSC and Atrush JOA: Should the Company fail to meet its obligations under the Atrush PSC and or Atrush Block joint operating agreement (“Atrush JOA”) it could result in adverse effects to the Company’s business including, but not limited to, a default under one or both contracts, the termination of future revenue generating activities of the Company and impairment of the Company’s ability to meet its contractual commitments as they become due. Kurdistan legal system: The Kurdistan Region of Iraq has a less developed legal system than that of many more established regions. This could result in risks associated with predicting how existing laws, regulations and contractual obligations will be interpreted, applied or enforced. In addition it could make it more difficult for the Company to obtain effective legal redress in courts in case of breach of law, regulation or contract and to secure the implementation of arbitration awards and may give rise to inconsistencies or conflicts among various laws, regulations, decrees or judgments. The Company’s recourse may be limited in the event of a breach by a government authority of an agreement governing the Atrush PSC in which ShaMaran acquires or holds an interest. 21 Enforcement of judgments in foreign jurisdictions: The Company is party to contracts with counterparties located in a number of countries, most notably Kurdistan. Certain of its contracts are subject to English law with legal proceedings in England. However, the enforcement of any judgments thereunder against a counterparty will be a matter of the laws of the jurisdictions where counterparties are domiciled. Change of control in respect of the Atrush PSC: The Atrush PSC definition of “change of control” in a Contractor includes a change of voting majority in the Contractor, or in a parent company, provided the value of the interest in the Atrush field represents more than 50% of the market value of assets in the Company. Due to the limited amount of other assets held by the Company this will apply to a change of control in GEP or any of its parent companies. Change of control requires the consent of KRG or it will trigger a default under the Atrush PSC. Project and Operational Risks Shared ownership and dependency on partners: ShaMaran’s operations are to a significant degree conducted together with one or more partners through contractual arrangements with the execution of the operations being undertaken by the Operator in accordance with the terms of the Atrush JOA. As a result, ShaMaran has limited ability to exercise influence over the deployment of those assets or their associated costs and this could adversely affect ShaMaran’s financial performance. If the operator or other partners fail to perform, ShaMaran may, among other things, risk losing rights or revenues or incur additional obligations or costs to itself perform in place of its partners. If a dispute would arise with one or more partners such dispute may have significant negative effects on the Company’s operations relating to its projects. Security risks: Kurdistan and other regions in Iraq have a history of political and social instability which have culminated in security problems which may put at risk the safety of the Company’s personnel, interfere with the efficient and effective execution of the Company’s operations and ultimately result in significant losses to the Company. There have been no significant security incidents in the Company’s area of operation. Risks relating to infrastructure: The Company is dependent on access to available and functioning infrastructure (including third party services in Kurdistan) relating to the properties on which it operates, such as roads, power and water supplies, pipelines and gathering systems. If any infrastructure or systems failures occur or access is not possible or does not meet the requirements of the Company, the Company’s operations may be significantly hampered which could result in lower production and sales and or higher costs. Environmental regulation and liabilities: Drilling for and producing, handling, transporting and disposing of oil and gas and petroleum by-products are activities that are subject to extensive regulation under national and local environmental laws, including in those countries in which ShaMaran currently operates. The Company has implemented health, safety and environment policies since industry environmental practices and guidelines for its operations in Kurdistan and is currently in compliance with these obligations in all material aspects. Environmental protection requirements have not, to date, had a significant effect on the capital expenditures and competitive position of ShaMaran. Future changes in environmental or health and safety laws, regulations or community expectations governing the Company’s operations could result in adverse effects to the Company’s business including, but not limited to, increased monitoring, compliance and remediation costs and or costs associated with penalties or other sanctions imposed on the Company for non-compliance or breach of environmental regulations. incorporation, complies with its Risk relating to community relations / labour disruptions: The Company’s operations may be in or near communities that may regard operations as detrimental to their environmental, economic or social circumstances. Negative community reactions and any related labour disruptions or disputes could increase operational costs and result in delays in the execution of projects. Petroleum costs and cost recovery: Under the terms of the Atrush PSC the KRG is entitled to conduct an audit to verify the validity of incurred petroleum costs which the Operator has reported to the KRG and is therefore entitled under the terms of the Atrush PSC to recover through cash payments from future petroleum production. No such audit yet date taken place. Should any future audits result in negative findings concerning the validity of reported incurred petroleum costs the Company’s petroleum cost recovery entitlement could ultimately be reduced. Legal claims and disputes: The Company may suffer unexpected costs or other losses if a counterparty to any contractual arrangement entered into by the Company does not meet its obligations under such agreements. In particular, the Company cannot control the actions or omissions of its partners in the Atrush PSC. If such parties were to breach the terms of the Atrush PSC or any other documents relating to the Company’s interest in the Atrush PSC, it could cause the KRG to revoke, terminate or adversely amend the Atrush PSC. 22 Uninsured losses and liabilities: Although the Company maintains insurance in accordance with industry standards to address risks relating to its operations, the insurance coverage may under certain circumstances not protect it from all potential losses and liabilities that could result from its operations. Availability of equipment and services: ShaMaran’s oil and natural gas exploration and development activities are dependent on the availability of third-party services, drilling and related equipment and qualified staff in the areas where such activities are or will be conducted. Shortages of such equipment or staff may affect the availability of such equipment to ShaMaran and may delay and or increase the cost of ShaMaran’s exploration and development activities. Early stage of production: ShaMaran has conducted oil and gas exploration and development activities in Kurdistan for approximately nine years. The current operations are in an early production stage and there can be no assurance that ShaMaran’s operations will be profitable in the future or will generate sufficient cash flow to satisfy its future commitments. Financial and Other Risks Financial statements prepared on a going concern basis: The Company’s financial statements have been prepared on a going concern basis under which an entity is able to realise its assets and satisfy its liabilities in the ordinary course of business. Management has made assumptions regarding projected oil sale volumes and pricing, and the timing and extent of capital, operating, and general and administrative expenditures. Should production be materially less than anticipated or in case there are extended delays to the forecasted receipt of cash from the sale of oil exports or in the magnitude of those cash receipts, which are under the control of the KRG, and the Company was unable to defer certain planned cost activities, the Company could require additional liquidity to fund the forecasted Atrush operating and development costs and its commitments under the bond agreement in the next 12 months. The Company’s future operations are dependent upon certain factors the identification and successful completion of additional equity or debt financing or the achievement of profitable operations. There can be no assurances that the Company will be successful in completing additional debt or equity financing or achieving profitability. The consolidated financial statements do not give effect to any adjustments relating to the carrying values and classification of assets and liabilities that would be necessary should ShaMaran be unable to continue as a going concern. Substantial capital requirements: ShaMaran anticipates making substantial capital expenditures in the future for the acquisition, exploration, development and production of oil and gas. ShaMaran’s results could impact its access to the capital necessary to undertake or complete future drilling and development programs. To meet its operating costs and planned capital expenditures, ShaMaran may require financing from external sources, including from the sale of equity and debt securities. There can be no assurance that such financing will be available to the Company or, if available, that it will be offered on terms acceptable to ShaMaran. If ShaMaran or any of its partners in the oil asset are unable to complete minimum work obligations on the Atrush PSC, this PSC could be relinquished under applicable contract terms. Dilution: The Company may make future acquisitions or enter into financings or other transactions involving the issuance of securities of the Company. If additional financing is raised through the issuance of equity or convertible debt securities, control of the Company may change and the interests of shareholders in the net assets of ShaMaran may be diluted. Tax legislation: The Company has entities incorporated and resident for tax purposes in Canada, the Cayman Islands, the Kurdistan Region of Iraq, the Netherlands, Switzerland and the United States of America. Changes in the tax legislation or tax practices in these jurisdictions may increase the Company’s expected future tax obligations associated with its activities in such jurisdictions. Capital and lending markets: Because of general economic uncertainties and, in particular, the potential lack of risk capital available to the junior resource sector, the Company, along with other junior resource entities, may have reduced access to bank debt and to equity. As future capital expenditures will be financed out of funds generated from operations, bank borrowings if available, and possible issuances of debt or equity securities, the Company’s ability to do so is dependent on, among other factors, the overall state of lending and capital markets and investor and lender appetite for investments in the energy industry generally, and the Company’s securities in particular. To the extent that external sources of capital become limited or unavailable or available only on onerous terms, the Company’s ability to invest and to maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result. 23 Uncertainty in financial markets: In the future the Company could require financing to grow its business. The uncertainty which periodically affects financial markets and the possibility that financial institutions may consolidate or go bankrupt has reduced levels of activity in the credit markets which could diminish the amount of financing available to companies. The Company’s liquidity and its ability to access the credit or capital markets may also be adversely affected by changes in the financial markets and the global economy. Conflict of interests: Certain directors of ShaMaran are also directors or officers of other companies, including oil and gas companies, the interests of which may, in certain circumstances, come into conflict with those of ShaMaran. If a conflict arises with respect to a particular transaction, the affected directors must disclose the conflict and abstain from voting with respect to matters relating to the transaction. Risks Related to the Company’s Senior Bonds Possible termination of Atrush PSC / bond agreements in event of default scenario: Should ShaMaran default its obligations under the bond agreement ShaMaran may also not be able to fulfil its obligations under the Atrush PSC and or Atrush JOA, with the effect that these contracts may be terminated or limited. In addition, should ShaMaran default its obligations under the Atrush PSC and or Atrush JOA, with the effect that these contracts may be terminated or limited, ShaMaran may also default in respect of its obligations under the bond agreement. Either default scenario could result in the termination of the Company’s future revenue generating activities and impair the Company’s ability to meet its contractual commitments as they become due. Ability to service indebtedness: ShaMaran’s ability to make scheduled payments on or to refinance its obligations under the bond agreement will depend on ShaMaran’s financial and operating performance which, in turn, will be subject to prevailing economic and competitive conditions beyond ShaMaran’s control. It is possible that ShaMaran’s activities will not generate sufficient funds to make the required interest payments which could, among other things, result in an event of default under the bond agreement. Significant operating and financial restrictions: The terms and conditions of the bond agreement contains restrictions on ShaMaran’s and the Guarantors’ activities which restrictions may prevent ShaMaran and the Guarantors from taking actions that it believes would be in the best interest of ShaMaran’s business, and may make it difficult for ShaMaran to execute its business strategy successfully or compete effectively with companies that are not similarly restricted. No assurance can be given that it will be granted the necessary waivers or amendments if for any reason ShaMaran is unable to comply with the terms of the bond agreement. A breach of any of the covenants and restrictions could result in an event of default under the bond agreement. Mandatory prepayment events: Under the terms of the bond agreements the bonds are subject to mandatory prepayment by ShaMaran on the occurrence of certain specified events, including if (i) the ownership in the Atrush Block is reduced to below 20.10% or (ii) an event of default occurs under the bond agreement. Following an early redemption after the occurrence of a mandatory prepayment event, it is possible that ShaMaran will not have sufficient funds to make the required redemption of the bonds which could, among other things, result in an event of default under the bond agreement. FORWARD LOOKING INFOMATION This report contains forward-looking information and forward-looking statements. Forward-looking information concerns possible events or financial performance that is based on management’s assumptions concerning anticipated developments in the Company’s operations; the adequacy of the Company’s financial resources; financial projections, including, but not limited to, estimates of capital and operating costs, production rates, commodity prices, exchange rates, net present values; and other events and conditions that may occur in the future. Information concerning the interpretation of drill results and reserve estimates also may be deemed to be forward-looking information, as it constitutes a prediction of what might be found to be present if a project is actually developed. Forward-looking statements are statements that are not historical and are frequently, but not always, identified by the words such as “expects,” “anticipates,” “believes,” “intends,” “estimates,” “potential,” “possible,” “outlook”, “budget” and similar expressions, or statements that events, conditions or results “will,” “may,” “could,” or “should” occur or be achieved. Forward-looking statements are statements about the future and are inherently uncertain, and actual achievements of the Company or other future events or conditions may differ materially from those reflected in the forward-looking statements due to a variety of risks, uncertainties and other factors, including, without limitation, those described in this MD&A. 24 The Company’s forward-looking information and forward-looking statements are based on the beliefs, expectations and opinions of management on the date the statements are made. Management is regularly considering and evaluating assumptions that will impact on future performance. Those assumptions are exposed to generic risks and uncertainties as well as risks and uncertainties that are specifically related to the Company’s operations. The Company cautions readers regarding the reliance placed by them on forward‐looking information as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company. Except as required by applicable securities legislation the Company assumes no obligation to update its forward- looking information and forward-looking statements in the future. For the reasons set forth above, investors should not place undue reliance on forward-looking information and forward-looking statements. Reserves and resources: ShaMaran Petroleum Corp.'s reserve and contingent resource estimates are as at December 31, 2018 and have been prepared and audited in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Unless otherwise stated, all reserves estimates contained herein are the aggregate of "proved reserves" and "probable reserves", together also known as "2P reserves". Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. Contingent resources: Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. There is no certainty that it will be commercially viable for the Company to produce any portion of the contingent resources. BOEs: BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf per 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. ADDITIONAL INFORMATION Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com and on the Company’s web-site at www.shamaranpetroleum.com . The Company plans to publish on May 8, 2019 its financial statements for the three months ended March 31, 2019. 25 ShaMaran Petroleum Corp. Audited Consolidated Financial Statements For the year ended December 31, 2018 26 Independent auditor’s report To the Shareholders of ShaMaran Petroleum Corp. Our opinion In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of ShaMaran Petroleum Corp. and its subsidiaries, (together, the Company) as at December 31, 2018 and 2017, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards (IFRS). What we have audited The Company’s consolidated financial statements comprise: (cid:120) (cid:120) (cid:120) (cid:120) (cid:120) the consolidated statement of comprehensive income for the years ended December 31, 2018 and 2017; the consolidated balance sheet as at December 31, 2018 and 2017; the consolidated statements of changes in equity for the years then ended; the consolidated statement of cash flows for the years then ended; and the notes to the consolidated financial statements, which include a summary of significant accounting policies. Basis for opinion We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the consolidated financial statements section of our report. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Independence We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada. We have fulfilled our other ethical responsibilities in accordance with these requirements. Other information Management is responsible for the other information. The other information comprises the information, other than the consolidated financial statements and our auditor’s report thereon, included in or filed on the same date as the annual report, which includes the Management Discussion & Analysis and Annual Information Form. PricewaterhouseCoopers SA, Avenue Giuseppe-Motta 50 CH-1211 Genève 2, Switzerland Telephone: +41 58 792 91 00, Facsimile: +41 58 792 91 10, www.pwc.ch PricewaterhouseCoopers SA is a member of the global PricewaterhouseCoopers network of firms, each of which is a separate and independent legal entity. 27Our opinion on the consolidated financial statements does not cover the other information and we do not and will not express an opinion or any form of assurance conclusion thereon. In connection with our audit of the consolidated financial statements, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated. If, based on the work we have performed on the other information, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard. Responsibilities of management and those charged with governance for the consolidated financial statements Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. In preparing the consolidated financial statements, management is responsible for assessing the Company’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so. Those charged with governance are responsible for overseeing the Company’s financial reporting process. Auditor’s responsibilities for the audit of the consolidated financial statements Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements. As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism throughout the audit. We also: (cid:120) Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. 28(cid:120) (cid:120) (cid:120) (cid:120) (cid:120) Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a going concern. Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation. Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Company to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the group audit. We remain solely responsible for our audit opinion. We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards. The engagement partner on the audit resulting in this independent auditor’s report is Luc Schulthess. PricewaterhouseCoopers SA March 8, 2019 CoCoCoCoColililililinnnn n JoJoJoJoJohnhnhnhnhnsososososonnnnn Colin Johnson 29SHAMARAN PETROLEUM CORP. Consolidated Statement of Comprehensive Income (Expressed in thousands of United States dollars, except for per share data) ___________________________________________________________________________ Note For the year ended December 31, 2017 2018 Revenues Cost of goods sold: Lifting costs Other costs of production Depletion Gross margin on oil sales General and administrative expense Depreciation and amortisation expense Share based payments expense Income / (loss) from operating activities Finance income Finance cost Net finance cost Income / (loss) before income tax expense Income tax expense Income / (loss) for the year Other comprehensive income Items that may be reclassified to profit or loss: Currency translation differences Items that will not be reclassified to profit or loss: Re-measurements on defined pension plan Total other comprehensive income Total comprehensive income / (loss) for the year 6 7 7 7 8 9 10 20 69,600 (12,047) (1,854) (28,171) 27,528 (4,564) (8) - 22,956 2,091 (23,114) (21,023) 1,933 (64) 1,869 18 357 375 2,244 17,689 (5,547) (834) (7,628) 3,680 (4,511) (26) (11) (868) 1,649 (12,195) (10,546) (11,414) (85) (11,499) 31 (13) 18 (11,481) Loss in dollars per share: Basic and diluted - (0.01) The accompanying Notes are an integral part of these consolidated financial statements. 30 SHAMARAN PETROLEUM CORP. Consolidated Balance Sheet (Expressed in thousands of United States dollars) ___________________________________________________________________________ Note As at December 31, 2018 2017 Assets Non-current assets Property, plant and equipment Intangible assets Loans and receivables Current assets Cash and cash equivalents, restricted Cash and cash equivalents, unrestricted Loans and receivables Other current assets Total assets Liabilities and equity Current liabilities Accrued interest expense on bonds Accounts payable and accrued expenses Current tax liabilities Borrowings Non-current liabilities Borrowings Provisions Pension liability Total liabilities Equity Share capital Share based payments reserve Cumulative translation adjustment Accumulated deficit Total equity Total liabilities and equity 11 12 13 16 13 14 16 15 16 16 17 20 18 195,908 67,829 25,184 288,921 67,884 24,586 36,099 2,286 130,855 419,776 14,080 3,875 16 - 17,971 236,717 9,559 1,330 247,606 265,577 637,538 6,495 (12) (489,822) 154,199 419,776 184,921 89,119 44,696 318,736 2,162 3,094 32,277 212 37,745 356,481 2,799 4,827 - 185,692 193,318 - 9,427 1,781 11,208 204,526 637,538 6,495 (30) (492,048) 151,955 356,481 The accompanying Notes are an integral part of these consolidated financial statements. Signed on behalf of the Board of Directors: /s/Terry Allen Terry L. Allen, Director /s/Keith Hill Keith C. Hill, Director 31 SHAMARAN PETROLEUM CORP. Consolidated Statement of Changes in Equity (Expressed in thousands of United States dollars) ______________________________________________________________________________ Share based payments reserve Share capital Cumulative translation adjustment Accumulated deficit Note Total Balance at January 1, 2017 611,179 6,484 (61) (480,536) 137,066 Total comprehensive loss for the year: Loss for the year Other comprehensive income / (loss) Transactions with owners in their capacity as owners: Share based payments expense Shares issued on private placement Transaction costs 18 18 - - - - 27,281 (922) 26,359 - - - 11 - - 11 - 31 31 - - - - (11,499) (13) (11,512) (11,499) 18 (11,481) - - - - 11 27,281 (922) 26,370 Balance at December 31, 2017 637,538 6,495 (30) (492,048) 151,955 Total comprehensive income for the year: Income for the year Other comprehensive income - - - - - - - 18 18 1,869 357 2,226 1,869 375 2,244 Balance at December 31, 2018 637,538 6,495 (12) (489,822) 154,199 The accompanying Notes are an integral part of these consolidated financial statements. 32 SHAMARAN PETROLEUM CORP. Consolidated Statement of Cash Flows (Expressed in thousands of United States dollars) ___________________________________________________________________________ Note For the year ended December 31, 2017 2018 Operating activities Income / (loss) for the year Adjustments for: Depreciation, depletion and amortisation expense Borrowing costs – net of amount capitalised Re-measurements on defined pension plan Foreign exchange loss Unwinding discount on decommissioning provision Share based payments expense Interest income Changes in current tax liabilities Changes in pension liability Changes in accounts receivables on Atrush oil sales Changes in accounts payable and accrued expenses Changes in other current assets Net cash inflows from / (outflows to) operating activities Investing activities Loans and receivables – payments received Interest received on cash deposits Loans and receivables – payments issued Purchases of intangible assets Purchase of property, plant and equipment Net cash inflows from / (outflows to) investing activities Financing activities Net proceeds received on bonds issued Proceeds from shares issued Share issue related transaction costs Payments to bondholders - interest and call premiums Cash paid out on bonds retired Net cash inflows from financing activities 9 8 8 16 16 16 Effect of exchange rate changes on cash and cash equivalents Change in cash and cash equivalents Cash and cash equivalents, beginning of the year Cash and cash equivalents, end of the year* *Inclusive of restricted cash 16 1,869 28,179 23,084 357 26 5 - (2,091) 16 (438) (574) (952) (2,074) 47,407 18,029 720 (394) (632) (12,259) 5,464 100,376 - - (15,575) (50,437) 34,364 (21) 87,214 5,256 92,470 67,884 The accompanying Notes are an integral part of these consolidated financial statements. (11,499) 7,654 12,089 (13) 102 4 11 (1,649) - 37 (13,957) (1,607) 12 (8,816) 2,806 107 (10,914) (82) (8,621) (16,704) - 27,281 (922) - - 26,359 1 840 4,416 5,256 2,162 33 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 1. General information ShaMaran Petroleum Corp. (“ShaMaran” and together with its subsidiaries the “Company”) is incorporated under the Business Corporations Act, British Columbia, Canada. The address of the registered office is 25th Floor, 666 Burrard Street, Vancouver, British Columbia V6C 2X8. The Company’s shares trade on the TSX Venture Exchange and NASDAQ Stockholm First North Exchange (Sweden) under the symbol “SNM”. The Company is engaged in the business of oil and gas exploration and development and is currently in the first phase of the development program in respect of the Atrush Block production sharing contract (“Atrush PSC”) related to a petroleum property located in the Kurdistan Region of Iraq (“Kurdistan”). Oil production on the Atrush Block commenced on July 3, 2017. 2. Basis of preparation and going concern a. Basis of preparation These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and the IFRS Interpretations Committee that are effective beginning on January 1, 2018, under the historical cost convention. The significant accounting policies of the Company have been applied consistently throughout the year. The policies applied in these consolidated financial statements are based on IFRS which were outstanding and effective as of March 7, 2019, the date these consolidated financial statements were approved and authorised for issuance by the Company’s board of directors (“the Board”). b. Going concern These consolidated financial statements have been prepared on the going concern basis which assumes that the Company will be able to realise its assets and liabilities in the normal course of business as they come due in the foreseeable future. 3. Significant accounting policies (a) Basis of consolidation The consolidated financial statements incorporate the financial statements of the Company and its subsidiaries, entities controlled by the Company which apply accounting policies consistent with those of the Company. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity to obtain benefits from its activities. Subsidiaries are fully consolidated from the date on which control is obtained by the Company and are de-consolidated from the date that control ceases. Intercompany balances and unrealised gains and losses on intercompany transactions are eliminated upon consolidation. 34 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ (b) Interest in joint operations A joint operation is a contractual arrangement whereby the Company and other parties undertake an economic activity that is subject to joint control. Where the Company undertakes its activities under joint operation arrangements directly, the Company’s share of jointly controlled operations and any liabilities incurred jointly with other joint operations are recognised in the financial statements of the relevant company and classified according to their nature. Liabilities and expenses incurred directly in respect of interests in jointly controlled operations are accounted for on an accrual basis. Income from the sale or use of the Company’s share of the output of jointly controlled operations and its share of the joint operations are recognised when it is probable that the economic benefit associated with the transactions will flow to/from the Company and the amount can be reliably measured. (c) Business combinations The acquisition method of accounting is used to account for business combinations. The consideration transferred is measured at the aggregate of the fair values at the date of acquisition of assets given, liabilities incurred or assumed and equity instruments issued by the Company in exchange for control of the acquiree. Acquisition related costs are expensed as incurred. The identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 Business Combinations are recognised at their fair value at the acquisition date. If the Company acquires control of an entity in more than one transaction the related investment held by the Company immediately before the last transaction when control is acquired is considered sold and immediately repurchased at the fair value of the investment on the date of acquisition. Any difference between the fair value and the carrying amount of the investment results in income or loss recognised in the statement of comprehensive income. (d) Foreign currency translation Functional and presentation currency Items included in the financial statements of each of the Company’s subsidiaries are measured using the currency of the primary economic environment in which the subsidiary operates (the “functional currency”). The functional and presentation currency of the Company is the United States dollar (“USD”). The results and financial position of subsidiaries that have a functional currency different from the presentation currency are translated into the presentation currency as follows: ▪ Assets and liabilities are translated at the closing exchange rate at the date of that balance sheet. ▪ Income and expenses are translated at the average exchange rate for the period in which they were incurred as a reasonable approximation of the cumulative effect of rates prevailing on transaction dates. ▪ All resulting exchange differences are recognised in other comprehensive income as part of the cumulative translation reserve. Transactions and balances Transactions in currencies other than the functional currency are recorded in the functional currency at the exchange rates prevailing on the dates of the transactions or valuation where items are re-measured. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are translated at the rates prevailing at the balance sheet date. Exchange differences are recognised in the statement of comprehensive income during the period in which they arise. 35 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ (e) Exploration and evaluation costs and other intangible assets Exploration and evaluation assets The Company applies the full cost method of accounting for exploration and evaluation (“E&E”) costs in accordance with the requirements of IFRS 6 Exploration for and Evaluation of Mineral Resources. All costs of exploring and evaluating oil and gas properties are accumulated and capitalised to the relevant property contract area and are tested on a cost pool basis as described below. Pre-license costs: Costs incurred prior to having obtained the legal rights to explore an area are expensed directly to the statement of comprehensive income. Exploration and evaluation costs: All E&E costs are initially capitalised as E&E assets and include payments to acquire the legal right to explore, costs of technical services and studies, seismic acquisition, exploratory drilling and testing. Tangible assets used in E&E activities such as the Company’s vehicles, drilling rigs, seismic equipment and other property, plant and equipment (“PP&E”) used by the Company’s exploration function are classified as PP&E. To the extent that such tangible assets are consumed in exploring and evaluating a property the amount reflecting that consumption is recorded as part of the cost of the intangible asset. Such intangible costs include directly attributable overhead including the depreciation of PP&E utilised in E&E activities together with the cost of other materials consumed during the E&E phases such as tubulars and wellheads. E&E costs are not depreciated prior to the commencement of commercial production. Treatment of E&E assets at conclusion of appraisal activities: E&E assets are carried forward until commercial viability has been established for a contractual area which normally coincides with the commencement of commercial production. The E&E assets are then assessed for impairment and the carrying value after any impairment loss is then reclassified as oil and gas assets within PP&E. Until commercial viability has been established E&E assets remain capitalised at cost and are subject to the impairment test set out below. Other intangible assets Other intangible assets are carried at measured cost less accumulated amortisation and any recognised impairment loss and are amortised on a straight-line basis over their expected useful economic lives as follows: ▪ Computer software and associated costs 3 years (f) Property, plant and equipment Oil and gas assets Oil and gas assets comprise of development and production costs for areas where technical feasibility and commercial viability have been established and include any E&E assets transferred after conclusion of appraisal activities as well as costs of development drilling, completion, gathering and production infrastructure, directly attributable overheads, borrowing costs capitalised and the cost of recognising provisions for future restoration and decommissioning. Oil and gas costs are accumulated separately for each contract area. Depletion of oil and gas assets: Oil and gas assets are depleted using the unit of production method based on proved and probable reserves using estimated future prices and costs and accounting for future development expenditures necessary to bring those reserves into production. The reserves correspond to the Company’s entitlement to oil under the terms of the PSC. Changes to depletion rates due to changes in reserve quantities and estimates of future development expenditure are reflected prospectively. 36 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Other property, plant and equipment Other property, plant and equipment include expenditures that are directly attributable to the acquisition of an asset. Subsequent costs are included in the assets’ carrying value or recognised as a separate asset as appropriate only when it is probable that future economic benefits associated with the item will flow to the Company and the cost can be measured reliably. Repairs and maintenance costs are charged to the statement of comprehensive income during the period in which they are incurred. The carrying amount of an item of PP&E is derecognised on disposal or when no future economic benefits are expected from its use or disposal. The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in the statement of comprehensive income during the period. Other property, plant and equipment assets are carried at cost less accumulated depreciation and any recognised impairment loss and are depreciated on a straight-line basis over their expected useful economic lives as follows: ▪ Furniture and office equipment ▪ Computer equipment 5 years 3 years (g) Impairment of non-financial assets E&E assets and oil and gas assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such indicators include: ▪ The period for which the Company has the right to explore in the specific area has expired during the period or will expire in the near future and is not expected to be renewed. ▪ Substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned. ▪ Exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the Company has decided to discontinue such activities in the specific area. ▪ Sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amount of either of the E&E or the oil and gas assets is unlikely to be recovered in full from successful development or by sale. ▪ Extended decreases in prices or margins for oil and gas commodities or products. ▪ A significant downwards revision in estimated volumes or an upward revision in future development costs. For impairment testing the assets are aggregated into cash generating unit (“CGU”) cost pools based on their ability to generate largely independent cash flows. The recoverable amount of a CGU is the greater of its fair value less costs to sell and its value in use. Fair value is determined to be the amount for which the asset could be sold in an arm’s length transaction. Value in use is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU. Where conditions giving rise to the impairment subsequently reverse the effect of the impairment charge is also reversed as a credit to the statement of comprehensive income net of any depreciation that would have been charged since the impairment. (h) Financial instruments Financial assets and liabilities are recognised in the Company’s balance sheet when the Company becomes a party to the contractual provisions of the instrument. Financial assets are derecognised when the contractual rights to cash flows from the assets expire or the Company transfers the financial asset and substantially all the risks and rewards of ownership. The Company derecognises financial liabilities when the Company’s obligations are discharged, cancelled or expire. 37 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Classification and measurement The Company classifies its financial assets and liabilities at initial recognition in the following categories: ▪ Financial assets and liabilities at fair value through profit or loss are those assets and liabilities acquired principally for selling or repurchasing in the short-term and are recognised at fair value. Transaction costs are expensed in the statement of comprehensive income and gains or losses arising from changes in fair value are also presented in the statement of comprehensive income within other gains and losses in the period in which they arise. Financial assets and liabilities at fair value through profit or loss are classified as current except for the portion expected to be realised or paid beyond twelve months of the balance sheet date, which is classified as non-current. ▪ Financial assets carried at amortised cost comprise of loans, receivables and cash and cash equivalents with fixed or determinable payments that are not quoted on an active market and are generally included within current assets due to their short-term nature and are classified as financial assets when the Company has a right to cash collection. If collection of the amounts is expected in one year or less they are classified as current assets. If not, they are presented as non-current assets. Loans and receivables are initially recognised at fair value and are subsequently measured at amortised cost using the effective interest method less any provision for impairment. ▪ Financial liabilities at amortised cost comprise of trade and other payables and are initially recognised at the fair value of the amount expected to be paid and are subsequently measured at amortised cost using the effective interest rate method. Financial liabilities are classified as current liabilities unless the Company has an unconditional right to defer settlement for at least 12 months after the balance sheet date. (i) Cash and cash equivalents Cash and cash equivalents are comprised of cash on hand and demand deposits and other short-term liquid investments that are readily convertible to a known amount of cash within three months or less from the acquisition date. Restricted cash is cash held in a trust account for a specific purpose and is therefore not available for general business use. Additional disclosure related to the Company’s restricted cash is included in Note 16. (j) Borrowings Borrowings are recognised initially at fair value, net of any transaction costs incurred. Borrowings are subsequently carried at amortised cost using the effective interest rate method. General and specific borrowing costs directly attributable to the acquisition or construction of qualifying assets are capitalised together with the qualifying assets. Once a qualified asset is fully prepared for its intended use and is producing borrowing costs are no longer capitalised. All other borrowing costs are recognised in profit or loss in the period in which they are incurred. (k) Taxation The income tax expense comprises current income tax and deferred income tax. The current income tax is the expected tax payable on the taxable income for the period. It is calculated based on the tax laws enacted or substantively enacted at the balance sheet date and includes any adjustment to tax payable in respect of previous years. Deferred income tax is the tax recognised in respect of temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases and is accounted for using the balance sheet liability method. Deferred income tax liabilities are generally recognised for all taxable temporary differences and deferred income tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Deferred income tax is not recorded if it arises from the initial recognition of an asset or liability in a transaction other than a business combination that, at the time of the transaction, affects neither the accounting profit nor loss. Deferred income tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates and interests in joint ventures except where the Company can control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered. 38 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Deferred income tax is calculated at the tax rates that are expected to apply in the year when the deferred tax liability is settled or the asset is realised. Deferred tax is charged or credited in the statement of comprehensive income except when it relates to items charged or credited directly to equity in which case the deferred tax is also recognised directly in equity. Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Company intends to settle its current tax assets and liabilities on a net basis. Income tax arising from the Company’s activities under production sharing contracts is settled by the KRG at no cost and on behalf of the Company. However, the Company is not able to measure with sufficient accuracy the tax that has been paid on its behalf and consequently revenue is not reported gross of income tax paid. (l) Provisions Provisions are recognised when the Company has a present obligation, legal or constructive, due to a past event when it is probable that the Company will be required to settle the obligation and a reliable estimate can be made of the obligation. The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the balance sheet date, accounting for the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flow estimates to settle the present obligation its carrying amount is the present value of those cash flows. Decommissioning and site restoration Provisions for decommissioning and site restoration are recognised when the Company has a present legal or constructive obligation to dismantle and remove production, storage and transportation facilities and to carry out site restoration work. The provision is calculated as the net present value of the Company’s share of the expenditure expected to be incurred at the end of the producing life of each field using a discount rate that reflects the market assessment of the time value of money at that date. Unwinding of the discount on the provision is charged to the statement of comprehensive income within finance costs during the period. The amount recognised as the provision is included as part of the cost of the relevant asset and is charged to the statement of comprehensive income in accordance with the Company’s policy for depreciation and amortisation. Changes in the estimated timing of decommissioning and site restoration cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to the relevant asset. (m) Pension obligations The Company’s Swiss subsidiary, ShaMaran Services SA, has a defined benefit pension plan that is managed through a private pension plan. Independent actuaries determine the cost of the defined benefit plan on an annual basis, and ShaMaran Services SA pays the annual insurance premium. The pension plan provides benefits coverage to the employees of ShaMaran Services SA in the event of retirement, death or disability. ShaMaran Services SA and its employees jointly finance retirement and risk benefits. Employees of ShaMaran Services SA pay 40% of the savings contributions, of the risk contributions and of the cost contributions and ShaMaran Services SA contributes the difference between the total of all required pension plan contributions and the total of all employees’ contributions. (n) Share capital Common shares are classified as equity. Incremental costs directly attributable to the issue of new shares or share options are shown in equity as a deduction, net of tax, from the proceeds. (o) Share-based payments The Company issues equity-settled share-based payments to certain directors, employees and third parties. The fair value of the equity settled share-based payments is measured at the date of grant. The total expense is recognised over vesting period, which is the period over which all conditions to entitlement are to be satisfied. The cumulative expense recognised for equity-settled share-based payments at each balance sheet date represents the Company’s best estimate of the number of equity instruments that will ultimately vest. The charge or credit for the period and the corresponding adjustment to contributed surplus during the period represents the movement in the cumulative expense recognised for all equity instruments expected to vest. The fair value of equity-settled share-based payments is determined using the Black-Scholes option pricing model. 39 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ (p) Revenue recognition Sales of oil Production: Revenue for sales of oil is recognised when the significant risks and rewards of ownership are deemed to have been transferred to the KRG, the amount can be measured reliably and it is assessed as probable that economic benefit associated with the sale will flow to the Company. This occurs when oil reaches the delivery point at the Atrush Block boundary in route to the KRG’s main export pipeline. Revenue is recognised at fair value which is comprised of the Company’s entitlement production due under the terms of the Atrush Joint Operating Agreement and the Atrush PSC which has two principal components: cost oil, which is the mechanism by which the Company recovers qualifying costs it has incurred in exploring and developing an asset, and profit oil, which is the mechanism through which profits are shared between the Company, its partners and the KRG. The Company pays capacity building payments on profit oil, which are due for payment once the Company has received the related profit oil proceeds. Profit oil revenue is reported net of any related capacity building payments. The Company’s oil sales are made to the KRG under the terms of a sales agreement which allows for Atrush oil volumes to be sold to the KRG at the Atrush Block boundary at a discount to the Dated Brent oil price for estimated oil quality adjustments and all local and international transportation costs. Interest income: Interest income is recognised when it is probable that the economic benefits associated with the transaction will flow to the entity and the amount of the income can be measured reliably. Interest income is recognised using the effective interest method. The effective interest rate exactly discounts estimated future cash payments or receipts through the expected life of the financial instrument or, when appropriate, a shorter period to the net carrying amount of the financial asset or financial liability. (q) Changes in accounting policies i. IFRS 15, Revenue from Contracts with Customers The Company adopted IFRS 15 effective January 1, 2018 and applied it on a retrospective basis. The application of IFRS 15 has not resulted in any differences between the previous carrying amounts and the carrying amounts at the date of initial application of IFRS 15. Revenue from Contracts with Customers is recognized when a customer obtains control of the promised asset and the Company satisfies its performance obligation. Revenue is allocated to each performance obligation. The Company considers the terms of the contract in determining the transaction price. The transaction price is based upon the amount the entity expects to be entitled to in exchange for the transferring of promised goods. The Company earns revenue from oil sales made to the KRG under the sales agreement between the KRG and the Atrush joint venture partners. The Company satisfies its performance obligations for its oil sales based upon specified sales agreement terms which are that Atrush oil volumes are sold to the KRG at the Atrush Block boundary at a discount to the Dated Brent oil price for estimated oil quality adjustments and all local and international transportation costs. Revenue from oil sales is recorded based on the sales agreement terms at the time the oil is delivered to the Atrush Block boundary. The Company typically receives payment within three months of delivery. The Company has assessed the impact of IFRS 15 – Revenue from Contracts with Customers. IFRS 15 requires a 5-step approach, which is definition of the customer, performance obligations, price, allocation of price into performance obligations and recognising the revenue when the conditions are met. The Company’s single performance obligation in its contract with its customer is the delivery of crude oil at a pre-determined netback adjustment to Dated Brent and the control is transferred to the buyer at the metering point when the revenue is recognised. Therefore, there is no material impact related to the adoption of IFRS 15. ii. IFRS 9, Financial Instruments The Company adopted IFRS 9 effective January 1, 2018 and applied it on a retrospective basis. The application of IFRS 9 has not resulted in any differences between the previous carrying amounts and the carrying amounts at the date of initial application of IFRS 9. 40 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Financial instruments are recognized on the consolidated balance sheet on the trade date, the date on which the Company becomes a party to the contractual provisions of the financial instrument. The Company classifies its financial instruments in the following categories: Financial Assets at Amortized Cost – Assets that are held for collection of contractual cash flows where those cash flows represent solely payments of principal and interest are measured at amortized cost. This includes the Company’s loans and receivables which consist of fixed or determined cash flows related solely to principal and interest amounts or contractual sales of oil. The Company’s intent is to hold these receivables until cash flows are collected. Financial assets at amortised cost are recognized initially at fair value, net of any transaction costs incurred and subsequently measured at amortized cost using the effective interest method. The Company recognizes a loss allowance for any expected credit losses on a financial asset that is measured at amortized cost. Financial Assets at Fair Value through Profit or Loss (“FVTPL”) – Financial assets measured at FVTPL are assets which do not qualify as financial assets at amortized cost or at fair value through other comprehensive income. The Company does not currently have any financial assets measured at FVTPL. Financial Liabilities at Amortized Cost – Financial liabilities are measured at amortized cost using the effective interest method, unless they are required to be measured at FVTPL, or the Company has opted to measure them at FVTPL. Borrowings and accounts payable are recognized initially at fair value, net of any transaction costs incurred, and subsequently at amortized cost using the effective interest method. Financial Liabilities at FVTPL – Financial liabilities measured at FVTPL are liabilities which include embedded derivatives and cannot be classified as amortized cost. The Company does not currently have any financial liabilities measured at FVTPL. The Company derecognizes financial assets only when the contractual rights to cash flows from the financial assets expire, or when it transfers the financial assets and substantially all the associated risks and rewards of ownership. Gains and losses on derecognition are generally recognized in the consolidated statement of income. The Company derecognizes financial liabilities only when its obligations under the financial liabilities are discharged, cancelled or expelled. The difference between the carrying amount of the financial liability derecognized and the consideration paid and payable, including any non‐cash assets transferred or liabilities assumed, is recognized in the consolidated statement of income. Impairment of financial assets IFRS 9 also introduces a new model for the measurement of impairment of financial assets based on expected credit losses which replaces the incurred losses impairment model applied under IAS 39. Under this new model, the Company’s loans and receivables are considered collectible as in line with agreements relating to the Company’s interest in the Atrush Block oil and gas asset; therefore, these financial assets are not considered to have a significant financing component and a lifetime expected credit loss (“ECL”) is measured at the date of initial recognition of the loans and receivables. ECL allowances have not been recognized for cash and cash equivalents and deposits due to the virtual certainty associated with their collectability. The Company’s loans and receivables are subject to the expected credit loss model under IFRS 9. For its loans and receivables, the Company applies the simplified approach to providing for expected credit losses prescribed by IFRS 9, which requires the use of the lifetime expected loss provision for all trade receivables. In estimating the lifetime expected loss provision, the Company considered historical industry default rates as well as the history of its customer. There were no material adjustments to the carrying value of any of the Company’s financial instruments following the adoption of IFRS 9. Additional disclosure related to the Company’s financial assets is included in Note 13. Other standards, amendments, and interpretations, which are effective for the financial year beginning on January 1, 2018, have been assessed and do not have a material impact to the Company. (r) Accounting standards issued but not yet applied New accounting standards which will come into effect for annual periods beginning on or after January 1, 2019 are discussed below. IFRS 16: Leases will replace IAS 17 Leases and requires assets and liabilities arising from all leases, with some exceptions, to be recognized on the balance sheet. The new standard will be effective for annual periods beginning on or after January 1, 2019. The Company currently has no outstanding leases. 41 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions 4. Critical accounting judgments and key sources of estimation uncertainty In the application of the Company’s accounting policies, which are described in Note 3, management has made judgments, estimates and assumptions about the carrying amounts of the assets, liabilities, revenues, expenses and related disclosures. These estimates and associated assumptions are based on historical experience, current trends and other factors that management believes to be relevant at the time these consolidated financial statements were prepared. Actual results may differ as future events and their effects cannot be determined with certainty and such differences could be material. Management reviews the accounting policies, underlying assumptions, estimates and judgments on an on-going basis to ensure that the financial statements are presented fairly in accordance with IFRS. The following are the critical judgments and estimates that management has made in the process of applying the Company’s accounting policies in these consolidated financial statements: (a) Revenue Recognition As explained in Note 3(p) the Company recognises revenues when oil reaches the delivery point at the Atrush Block boundary on the basis that control is deemed to have passed to the buyer and that the transaction price has been agreed upon. The conclusion that the economic benefits will flow to the Company at this point is based on management’s evaluation of the reliability of the KRG’s payments to the international oil companies operating in Kurdistan in exchange for their oil deliveries. Since the KRG’s announcement in February 2016 of its intention to apply the PSC terms Kurdistan oil exporters have reported regular payments for Kurdish oil sales. Payments commenced in October 2017 for the Company’s share of Atrush oil sales and have continued each month thereafter. (b) Oil and gas reserves and resources The business of the Company is the exploration and development of oil and gas reserves in Kurdistan. Estimates of commercial oil and gas reserves are used in the calculations for impairment, depreciation and amortisation and decommissioning provisions. Changes in estimates of oil and gas reserves resulting in different future production profiles will affect the discounted cash flows used for impairment purposes, the anticipated date of site decommissioning and restoration and the depreciation charges based on the unit of production method. In February 2019 the Company received an independent reserves and resources report from McDaniel & Associates Consultants Ltd. (“McDaniel”) which estimates the Proven plus Probable Gross Oil Reserves for the Atrush Block as of December 31, 2018, after accounting for Atrush 2018 production have increased by 11%, from 102.7 million barrels of oil (“MMbbls”) at the end of 2017 to 106 MMbbls at the end of 2018. McDaniel’s estimate of contingent resources has decreased from 296 MMbbls at the end of 2017 to 268 MMbbls at the end of 2018, due principally to the reclassification of contingent resources to reserves during the year. (c) Loans and receivables The Company has reported loans and receivables of $61.2 million comprised of the Company’s share of Atrush oil sales and loans made to the KRG relating to its share of Atrush exploration, development and Feeder Pipeline costs. The current portion of loans is based on a contractual repayment schedule which commenced in the fourth quarter of 2017. The recovery of these amounts depends on several factors, including: the continued production and exports of petroleum from the Atrush Block; oil price, and; the financial environment in Kurdistan and the financial budget of the KRG. Since February 1, 2016, when the KRG announced an interim measure whereby monthly payments to IOCs would be made based on an agreed mechanism, the KRG has established a consistent record of delivering regular monthly payments to IOCs for their entitlement revenues in respect of monthly petroleum production. In the year 2019 up to the date these financial statements were approved the Company received a total of $14 million in payments relating to the loans and receivables balances outstanding at December 31, 2018. Under the terms of the relevant agreements the loans and receivable balances are recoverable in several ways including by cash settlement and or through payment in kind of petroleum production. Refer also to Note 13. 42 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ (d) Impairment of assets IAS 36 Impairment of Assets and IFRS 6 Exploration of and Evaluation of Mineral Resources require that a review for impairment be carried out if events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. As described in Notes 3(g) and 3(h) management has considered whether there is any objective evidence to indicate that the carrying value of any of its Atrush related assets as at the balance sheet date were impaired and has concluded that facts and circumstances do not suggest that the carrying amount exceeds its recoverable amount. In reaching its conclusion management has considered a number of factors which could impact the ability of the assets to generate future cash flows including the following key items: • Reserves: there has been an increase, taking into account 2018 production, in the Company’s share of the latest estimated proved and probable reserves for Atrush and the related production curve estimates as determined by McDaniel. • • NPV calculations: the net present value of the Company’s share of 2P reserves, as determined by McDaniel and based on a forecasted Brent oil price, supports the book value of oil and gas assets included in property plant and equipment. Costs per barrel: the forecasted costs per barrel required to recover the Atrush oil reserves have remained consistent to last year; Cash collection: the collectability of cash for future sales of Atrush oil which has remained stable since production commenced. • • Market: there continues to be an active market and capacity for Atrush oil sales as demonstrated by the • current and future expected levels of oil exports from Kurdistan. Independent valuations: the average fair value of the Atrush asset as published by independent market brokers, Pareto Securities AB and SpareBank 1, support the carrying values of the Atrush oil and gas assets. Refer also to Notes 11, 12 and 13. (e) Decommissioning and site restoration provisions The Company recognises a provision for decommissioning and site restoration costs expected to be incurred to remove and dismantle production, storage and transportation facilities and to carry out site restoration work. The provisions are estimated taking into consideration existing technology and current prices after adjusting for expected inflation and discounted using rates reflecting current market assessments of the time value of money and where appropriate, the risks specific to the liability. The Company makes an estimate based on its experience and historical data. Refer also to Note 17. 5. Business and geographical segments The Company operates in one business segment, the exploration and development of oil and gas assets, in one geographical segment, Kurdistan. As a result, in accordance with IFRS 8 Operating Segments, the Company has presented its financial information collectively for one operating segment. 6. Revenues Revenues relate entirely to the Company’s entitlement share of oil from Atrush sold to the KRG during the year. Production from the Atrush field was delivered to the KRG’s Feeder Pipeline at the Atrush block boundary for onward export through Ceyhan, Turkey. Gross exported oil volumes from Atrush in 2018 were 8.1MMbbls (2017: 3.3MMbbls) and the Company’s entitlement share was approximately 1.3MMbbls (2017: 0.4MMbbls) which were sold with an average netback price of $54.52 per barrel (2017: $44.38). ShaMaran’s oil entitlement share is based on PSC terms covering allocation of profit oil and cost oil, capacity building bonuses owed to the KRG and a priority arrangement for sharing initial exploration cost oil and on export prices. Export prices are based on Dated Brent oil price with a discount for estimated oil quality adjustments and all local and international transportation costs. Refer also to Note 13. 43 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 7. Cost of goods sold Lifting costs are comprised of the Company’s share of expenses related to the production of oil from the Atrush Block including operation and maintenance of wells and production facilities, insurances, and the operator’s related support costs. Other costs of production include the Company’s share of production bonuses paid to the KRG and its share of other costs prescribed under the Atrush PSC. Oil and gas assets are depleted using the unit of production method based on proved and probable reserves using estimated future prices and costs and accounting for future development expenditures necessary to bring those reserves into production. 8. Finance income Interest on Atrush Development Cost Loan Interest on Atrush Feeder Pipeline Cost Loan Interest on deposits Total finance income For the year ended December 31, 2017 2018 836 535 720 2,091 1,042 500 107 1,649 Refer to Note 13 for further information on interest on the Atrush Development Cost Loan and the Feeder Pipeline Cost Loan. Interest on deposits represents bank interest earned on cash, investments and restricted cash held in interest bearing term deposits. 9. Finance cost Interest charges on bonds at coupon rate Call premiums on early retirement of bonds Amortisation of bond transaction costs Total borrowing costs Foreign exchange loss Unwinding discount on decommissioning provision Total finance costs before borrowing costs capitalised Borrowing costs capitalised Finance cost For the year ended December 31, 2017 2018 25,428 1,427 1,087 27,942 26 5 27,973 (4,859) 23,114 20,018 - 841 20,859 102 4 20,965 (8,770) 12,195 On July 5, 2018 the Company completed refinancing its bonds which increased total bonds outstanding to $240 million from the $186 million outstanding prior to the refinancing and increased the interest coupon from 11.5% to 12%. Certain call premiums of approximately $1.4 million were paid by the Company to early retire the bonds issued under the previous bond agreements. Borrowing costs directly attributable to the acquisition and preparation of Atrush development assets for their intended use have been capitalised together with the related Atrush oil and gas assets. All other borrowing costs are recognised in profit or loss in the period in which they are incurred. A significant number of development projects have been completed for their intended use, therefore the capitalisation of the related borrowing costs has ceased leading to less borrowing costs being capitalised. Refer also to Notes 11 and 16. 44 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 10. Taxation (a) Income tax expense The income tax expense reflects an effective tax rate which differs from Canadian Federal and Provincial statutory tax rates. The main differences are as follows: Income / (loss) from continuing operations before income tax Corporate income tax rate Computed income tax expense / (recovery) Increase / (decrease) resulting from: Foreign tax rate differences Effect of changes in tax rates Effect of changes in foreign exchange rates Decrease in deferred tax assets Share issuance costs charged to share capital Non-deductible compensation expense Non-deductible losses on foreign operations Non-taxable foreign exchange gain Other expense Income tax expense For the year ended December 31, 2017 2018 1,933 27.0% 522 (1,213) (243) (57) 1,027 - - - 3 25 64 (11,414) 26.0% (2,968) 646 - (107) 344 (244) 3 2,311 1 99 85 The Company’s income tax expense relates to a provision, in the line ‘Foreign tax rate differences’, for income tax on service income generated in Switzerland and is calculated at the effective tax rate of 24% prevailing in this jurisdiction. (b) Tax losses carried forward The Company has tax losses and costs which are available to apply to future taxable income as follows: As at December 31, Canadian losses from operations Canadian exploration expenses Canadian unamortised share issue costs Dutch losses from operations U.S. Federal losses from operations U.S. Federal tax basis in excess of carrying values of properties Total tax losses carried forward 2018 36,310 2,486 829 161,288 173,320 3,654 377,887 2017 20,100 2,443 1,267 177,633 173,319 3,654 378,416 The Canadian losses from operations may be used to offset future Canadian taxable income and will expire over the period from 2026 to 2038. The Canadian exploration expenses may be carried forward indefinitely to offset future taxable Canadian income. Canadian unamortised share issue costs may offset future taxable Canadian income of years 2019 to 2021. The Dutch losses from operations may be used to offset future Dutch taxable income and will expire over the period from 2019 to 2027, with the majority expiring in 2020. The U.S. Federal losses are available to offset future taxable income in the United States through 2032. The Company has not recognised any deferred tax assets amounting to approximately $91 million (2017: $104 million) as it is not probable that these amounts will be realised. 45 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 11. Property, plant and equipment At January 1, 2017 Cost Accumulated depreciation Net book value For the year ended December 31, 2017 Opening net book value Additions Depletion and depreciation expense Net book value At December 31, 2017 Cost Accumulated depletion and depreciation Net book value For the year ended December 31, 2018 Opening net book value Additions Reclass from intangible E&E asset Depletion and depreciation expense Net book value At December 31, 2018 Cost Accumulated depletion and depreciation Net book value Oil and gas assets Computer equipment Furniture and office equipment 174,780 (138) 174,642 174,642 17,903 (7,627) 184,918 192,683 (7,765) 184,918 184,918 17,356 21,794 (28,171) 195,897 231,833 (35,936) 195,897 253 (237) 16 16 3 (16) 3 266 (263) 3 3 11 - (4) 10 274 (264) 10 150 (150) - - - - - 156 (156) - - 1 - - 1 156 (155) 1 Total 175,183 (525) 174,658 174,658 17,906 (7,643) 184,921 193,105 (8,184) 184,921 184,921 17,368 21,794 (28,175) 195,908 232,263 (36,355) 195,908 The net book value of PP&E is principally comprised of development costs related to the Company’s share of Atrush PSC proved and probable reserves, as estimated by McDaniel, less the cumulative depletion costs corresponding to commercial production. During the year 2018 movements in PP&E were comprised of additions of $17.4 million (year 2017: $17.9 million), depletion and depreciation expense of $28.2 million (year 2017: $7.6 million) and a reclass to PP&E from E&E of $21.8 million (year 2017: $nil) which resulted in a net increase of $11.0 million to the net book value of PP&E assets. Net additions in 2018 included capitalised borrowing costs of $5.0 million (year 2017: $8.8 million). During the year 2018 plans were approved to produce and sell heavy oil which has resulted in the reclass to PP&E of heavy oil related project costs. Refer also to Notes 9, 12, 16 and 23. 46 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 12. Intangible assets At January 1, 2017 Cost Accumulated amortisation Net book value For the year ended December 31, 2017 Opening net book value Additions Disposals Amortisation expense Net book value At December 31, 2017 Cost Accumulated amortisation Net book value For the year ended December 31, 2018 Opening net book value Additions Reclass to PP&E Amortisation expense Net book value At December 31, 2018 Cost Accumulated amortisation Net book value Exploration and evaluation assets Other intangible assets 88,972 - 88,972 88,972 141 - - 89,113 89,113 - 89,113 89,113 506 (21,794) - 67,825 67,825 - 67,825 314 (279) 35 35 2 (21) (10) 6 307 (301) 6 6 3 - (5) 4 307 (303) 4 Total 89,286 (279) 89,007 89,007 143 (21) (10) 89,119 89,420 (301) 89,119 89,119 509 (21,794) (5) 67,829 68,132 (303) 67,829 The net book value of intangible assets is principally comprised of exploration and evaluation (“E&E”) assets which represent the Atrush Block exploration and appraisal costs related to the Company’s share of Atrush Block contingent resources as estimated by McDaniel. During the year 2018 movements in intangible assets were comprised of net additions of $509 thousand (year 2017: $143 thousand), depreciation of $5 thousand (year 2017 $10 thousand) and a reclass of $21.8 million (year 2017: $nil) from E&E to PP&E resulting in a net decrease to intangible assets of $21.3 million. Net additions in 2018 included the reversal of borrowing costs of $123 thousand (year 2017: $16 thousand). Refer also to Notes 11, 16 and 23. 47 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 13. Loans and receivables In November 2016 the Company entered into certain agreements with the KRG and other Atrush contractors for the reimbursement by the KRG to the Atrush contractors of certain Atrush exploration and development costs and pipeline costs incurred by KRG in the years 2013 through 2017 which were funded by the Atrush contractors. The Atrush Exploration Costs receivables, which relate to a share of the KRG’s development costs carried by ShaMaran prior to the year 2016 and deemed to be exploration costs under the Atrush PSC, are repaid through an accelerated petroleum cost recovery arrangement. The Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost Loan are being repaid with interest at 7% per annum in 24 equal monthly instalments ending in October 2019. The Company was owed amounts for its entitlement share of oil deliveries made to the KRG during the last three months of the year. At year end the Company had loans and receivables outstanding as follows: Atrush Exploration Costs receivable Accounts receivable on Atrush oil sales Atrush Development Cost Loan Atrush Feeder Pipeline Cost Loan Total loans and receivables - Current portion - Non-current portion As at December 31, 2018 2017 34,898 14,531 7,136 4,718 61,283 36,099 25,184 37,247 13,957 16,018 9,751 76,973 32,277 44,696 In the year 2018 the Company received principal plus interest payments totalling $11.3 million for Atrush Development Cost Loan and $6.9 million for the Atrush Feeder Pipeline Cost Loan, as well as $2.3 million of Atrush Exploration Cost receivables. The Company has assessed the need for an impairment analysis and determined none to be necessary. Therefore no impairments have been recorded. In the year 2019 up to when these financial statements were approved the Company received $14.0 million in total payments for loans and receivables balances outstanding at December 31, 2018, comprised of $10.9 million in total payments for its entitlement share of oil sales for the months of October and November 2018, $2.6 million for Atrush Development Cost Loan and Atrush Feeder Pipeline Cost Loan balances outstanding and $0.5 million in reimbursements of the Atrush Exploration Costs receivable. Refer also to Notes 6 and 8. 14. Other current assets Deposit on purchase of additional Atrush interest Prepaid expenses Other receivables Total other current assets As at December 31, 2018 2017 2,000 176 110 2,286 - 160 52 212 During the year 2018 a deposit of $2.0 million was paid to Marathon Oil KDV B.V. towards the price of acquiring an additional 7.5% interest in the Atrush PSC (“the Acquisition”) as announced by the Company on December 27, 2018. At the date these financial statements were approved certain conditions to closing remained outstanding. The Company currently holds a 20.1% interest in the Atrush PSC. 48 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 15. Accounts payable and accrued expenses Payables to joint operations partner Accrued expenses Trade payables Total accounts payable and accrued expenses 16. Borrowings As at December 31, 2018 2,734 859 282 3,875 2017 4,365 91 371 4,827 On July 5, 2018 the Company issued $240 million of senior unsecured bonds (“the ShaMaran bonds”). The ShaMaran bonds have a five-year maturity without amortization and carry 12% fixed semi-annual coupon. Holders of $136 million of the $186.4 million of previously outstanding bonds (“GEP bonds”) of General Exploration Partners, Inc. (“GEP”), a wholly owned subsidiary of the Company, agreed to early redeem their bonds in exchange for receiving an equivalent amount of ShaMaran bonds. As a result the Company received $104 million ($100.4 million net of related transaction costs) of cash proceeds from the ShaMaran bond issue. An amount of $50.4 million of the cash proceeds, with an additional $3 million of the Company’s cash, have been used to early retire the remaining GEP bonds and the remaining $53 million of the cash proceeds were held by the Company in an escrow account pledged to the bondholders (the “Marathon Pledged Account”) on the balance sheet date, pending release to the Company upon the closing of the purchase by the Company of an additional interest in the Atrush asset under terms prescribed in the bond agreement. On December 31, 2018 in accordance with the terms of the ShaMaran bonds the Company contributed $14.4 million, representing one semi-annual interest payment, to a Debt Service Retention Account (“DSRA”) and pledged to the bondholders as security for the Company’s obligations under the ShaMaran bonds. The amounts on deposit in the Marathon Pledged Account and the DSRA resulted in total restricted cash of $67.9 million on the balance sheet date, which includes interest earned of $484 thousand. The movements in borrowings are explained as follows: Opening balance Bond issued – net of transaction costs Interest charges at coupon rate Call premiums on early retirement of bonds Amortisation of bond transaction costs Bonds issued as interest payments Payment to Bondholders – interest and call premiums Bonds retired Ending balance - Current portion: accrued bond interest expense - Current portion: borrowings - Non-current portion: borrowings For the year ended December 31, 2017 2018 188,491 236,361 25,428 1,427 1,087 - (15,575) (186,422) 250,797 14,080 - 236,717 167,632 - 20,018 - 841 19,721 (19,721) - 188,491 2,799 185,692 - 49 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ The Company has complied with the financial covenants within its bond agreements during the years 2018 and 2017. The contractual obligations under the ShaMaran Bonds, prior to the amendments to the bond agreement discussed under the “Events After the Reporting Period” section below, are comprised of the repayment of principal and interest expense based on undiscounted cash flows at payment date, reflect a step up in bond coupon interest to 13% and the repayment in February 2019 of $50.6 million of bond principal plus interest both resulting from not having closed the Marathon Acquisition by February 5, 2019 (the Marathon transaction longstop date”) and leaving $190 million of bonds outstanding thereafter, and contributing one further payment to the DSRA before July 2019 to bring the balance to the required one year of bond interest by that time, are as follows: Less than one year Between one and two years Between three and five years Total For the year ended December 31, 2018 2017 76,350 37,800 238,000 352,150 207,860 - 207,860 At the date of these financial statements the above noted schedule of contractual obligations are no longer applicable. Events after the reporting period On January 5, 2019 the Company issued the first semi-annual interest payment to ShaMaran bondholders in the amount of $14.4 million. • • On February 1, 2019, bondholders approved of certain amendments to the ShaMaran Bonds agreement as follows: • funds on deposit in the DSRA may be used by the Company to fund the Acquisition and for general corporate purposes; funds in the Marathon Pledged Account will be used by the Company to prepay $50 million of ShaMaran Bonds plus accrued interest; the Company will reduce the aggregate outstanding amount of the Bond Issue to a maximum of $175 million on or before July 2020; in case the Acquisition is not closed by July 4, 2019 there will be a one-time step up in bond coupon interest by 1% per annum; and the Liquidity Guarantee will remain in force until the Company has funded the DSRA with 12 months of bond coupon interest. • • On February 8, 2019, the Company repaid $50 million of ShaMaran Bonds and $550 thousand of related accrued interest. At the date the financial statements were approved there were $190 million of ShaMaran Bonds outstanding. Nemesia S.à.r.l. (“Nemesia”), a company controlled by a trust settled by the estate of the late Adolf H. Lundin, agreed to guarantee the Company’s obligations under the ShaMaran Bonds agreement up to an amount of $22.8 million (the “Liquidity Guarantee”) representing one year of coupon interest of $190 million of ShaMaran Bonds now outstanding. In exchange for providing the Liquidity Guarantee the Company issued Nemesia 2,000,000 common shares of ShaMaran. In case of a draw down on the Liquidity Guarantee, the Company is required to issue to Nemesia a further 50,000 shares of ShaMaran for each $500 thousand drawn down per month until the drawn amount is repaid. Nemesia are a related party after this event in 2019. The remaining contractual obligations under the amended ShaMaran Bonds at the date these financial statements were approved on March 7, 2019, which are comprised of the repayment of principal and interest expense based on undiscounted cash flows at payment date, reflect the repayment of $50.6 million of principal and interest on February 8, 2019, and are based on the current $190 million of bonds outstanding thereafter until a further reduction in ShaMaran Bonds outstanding to $175 million is completed in July 2020, are as follows: March 8 to December 31, 2019 Year ended December 31, 2020 Three years ended December 31, 2023 Total Refer also to Notes 9, 11, 21 and 25. 11,400 37,800 238,000 287,200 50 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 17. Provisions The provision relates to the Company’s share of future decommissioning and site restoration costs in respect of the Company’s 20.1% interest in the Atrush Block and assumes these works will commence in the year 2032. The estimated costs have been discounted to net present value using a Bank of Canada long term bond yield rate of 2.18% (2017 year-end: 2.26%) and an inflation rate of 1.91% (2017 year-end: 2.11%). Opening balance Changes in estimates and obligations incurred Changes in discount and inflation rates Unwinding discount on decommissioning provision Total decommissioning and site restoration provisions 18. Share capital As at December 31, 2018 9,427 290 (163) 5 9,559 2017 8,869 425 129 4 9,427 The Company is authorised to issue an unlimited number of common shares with no par value. The Company’s issued share capital is as follows: At January 1, 2017 Shares issued on private placement Transaction costs on private placement At December 31, 2017 At December 31, 2018 Refer also to Note 16 and 25. Earnings per share The earnings per share amounts were as follows: Number of shares Share capital 1,798,631,534 360,000,000 - 2,158,631,534 2,158,631,534 611,179 27,281 (922) 637,538 637,538 For the year ended December 31, 2017 2018 Net income / (loss), in dollars Weighted average number of shares outstanding during the year Weighted average diluted number of shares outstanding during the year Basic and diluted income / loss per share, in dollars 1,869,000 2,158,631,534 2,183,631,534 - (11,499,000) 2,129,042,493 2,157,207,493 (0.01) 51 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 19. Share based payments expense The Company has established share unit plans and a share purchase option plan whereby a committee of the Company’s Board may, from time to time, grant up to a total of 10% of the issued share capital to directors, officers, employees or consultants. The number of shares issuable under these plans at any specific time to any one recipient shall not exceed 5% of the issued and outstanding common shares of the Company. Under the share unit plans the Company may grant performance share units (“PSU”), restricted share units (“RSU”) or deferred share units (“DSU”). PSU grants may be awarded annually to employees, directors or consultants (“Participants”) based on the fulfilment of defined Company and individual performance parameters. RSU grants may be awarded to Participants annually based on the fulfilment of defined Company performance parameters. RSUs and PSUs will vest based on the conditions described in the relevant grant agreement and, in any case, no later than the end of the third calendar year following the date of the grant. DSU’s may be awarded annually to non-employee directors of the Company based on the performance of the Company and vest immediately at the time of grant; however DSUs may not be redeemed until a minimum period of three months has passed following the end of service as a director of the Company. The share unit plans provide for redemption of the share units by way of payment in cash, shares or a combination of cash and shares. Under the option plan the term of any options granted under the option plan will be fixed by the Board and may not exceed five years from the date of grant. A four month hold period may be imposed by the stock exchange from the date of grant. Vesting terms are at the discretion of the Board. All issued share options have terms of five years and vest over two years from grant date. The exercise prices reflect trading values of the Company’s shares at grant date. Movements in the Company’s outstanding share options are explained as follows: Number of share options outstanding Weighted average exercise price CAD At January 1, 2017 Change in the year 2017 At December 31, 2017 Expired in the year 2018 At December 31, 2018 Share options exercisable: At December 31, 2017 At December 31, 2018 Weighted average remaining contractual life of options: At December 31, 2017 At December 31, 2018 28,165,000 - 28,165,000 (3,165,000) 25,000,000 28,165,000 25,000,000 1.91 years 1.05 years 0.13 - 0.13 0.28 0.12 0.13 0.12 The Company recognises compensation expense on share options granted to both employees and non-employees using the fair value method at the date of grant, which the Company records as an expense. The share-based payments expense is calculated using the Black-Scholes option pricing model. Option pricing models require the input of highly subjective assumptions including the expected price volatility. Changes in the subjective input assumptions can materially affect the fair value estimate and therefore the existing models do not necessarily provide a reliable single measure of the fair value of the Company’s share options. There were no options granted during the year 2018. Share based payments expense for the year ended December 31, 2018 was $nil (2017: $11 thousand). There were no grants of share units at the balance sheet date. 52 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 20. Pension liability The Company operates a pension plan in Switzerland that is managed through a private pension plan and accounts for its pension plan in accordance with IAS 19. The amount recognized in the balance sheet associated with the Swiss pension plan is as follows: Present value of defined benefit obligation Fair value of plan assets Pension liability For the year ended December 31, 2017 2018 7,376 (6,046) 1,330 8,082 (6,301) 1,781 The movement in the defined benefit obligation over the year is as follows: As at December 31, 2018 Opening balance Additional contributions paid by employees Current service cost Ordinary contributions paid by employees Interest expense on defined benefit obligation Administration costs Foreign exchange (gain)/ loss Past service cost Actuarial (gain)/ loss on defined benefit obligation Benefits paid from plan assets Defined benefit obligation, ending balance 8,082 583 172 106 56 4 (67) (111) (315) (1,134) 7,376 2017 7,304 217 172 110 49 5 327 - 32 (134) 8,082 The weighted average duration of the defined benefit obligation is 15.98 years. There is no maturity profile since the average remaining life before active employees reach final age according to the plan is 10.1 years. The movement in the fair value of the plan assets over the year is as follows: Opening balance Additional contributions paid by employees Ordinary contributions paid by employer Ordinary contributions paid by employees Interest income on plan assets Return on plan assets excluding interest income Foreign exchange (loss)/gain Benefits paid from plan assets Fair value of plan assets, ending balance As at December 31, 2018 6,301 583 159 106 44 42 (55) (1,134) 6,046 2017 5,634 217 165 110 38 18 253 (134) 6,301 The plan assets are under an insurance contract comprised entirely of free funds and reserves, such as fluctuation reserves and employer contribution reserves, for which there is no quoted price in an active market. The amount recognized in the income statement associated with the Company’s pension plan is as follows: Current service cost Interest expense on defined benefit obligation Administration costs Interest income on plan assets Past service cost Total expense recognised For the year ended December 31, 2017 2018 172 56 4 (44) (111) 77 172 49 5 (38) - 188 53 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ The expense associated with the Company’s pension plan of $77 thousand was included within general and administrative expenses. The Company also recognised in other comprehensive income a $357 thousand net actuarial gain on defined benefit obligations and pension plan assets. The principal actuarial assumptions used to estimate the Company’s pension obligation are as follows: Discount rate Inflation rate Future salary increases Future pension increases Retirement ages, male (‘M’) and female (‘F’) For the year ended December 31, 2017 2018 0.85% 1.00% 1.00% 0.00% M65/F64 0.70% 1.00% 1.00% 0.00% M65/F64 Assumptions regarding future mortality are set based on actuarial advice in accordance with the BVG 2015 GT generational published statistics and experience in Switzerland. The discount rate is determined by reference to the yield on high-quality corporate bonds. The rate of inflation is based on the expected value of future annual inflation adjustments in Switzerland. The rate for future salary increases is based on the average increase in the salaries paid by the Company, and the rate of pension increases is based on the annual increase in risk, retirement and survivors’ benefits. Contributions to the Company’s pension plan during 2019 are expected to total $0.3 million. The sensitivity of the defined benefit obligation to changes in the weighted principal assumptions is: Discount rate Salary growth rate Life expectancy Change in assumption 0.50% 0.50% One year Increase in assumption Decrease in assumption Increase by 8.4% Decrease by 0.2% Decrease by 2.0% Decrease by 7.4% Increase by 0.2% Increase by 1.9% The above sensitivity analyses are based on a change in an assumption while holding all other assumptions constant. In practice, this is unlikely to occur, and changes in some of the assumptions may be correlated. When calculating the sensitivity of the defined benefit obligation to significant actuarial assumptions, the same method has been applied as when calculating the pension liability recognized within the consolidated balance sheet. There have been no changes to the sensitivity analysis method this year. 54 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ 21. Financial instruments Financial assets The financial assets of the Company on the balance sheet dates were as follows: Cash and cash equivalents, restricted ² Cash and cash equivalents, unrestricted ² Loans and receivables ² Other receivables ² Total financial assets Carrying and fair values ¹ At December 31, 2018 At December 31, 2017 67,884 24,586 26,385 110 118,965 2,162 3,094 39,726 52 45,034 Financial assets classified as other receivables are initially recognised at fair value and are subsequently measured at amortised cost using the effective interest method less any provision for impairment. Financial liabilities The financial liabilities of the Company on the balance sheet dates were as follows: Borrowings ³ Accrued interest on bonds Accounts payable and accrued expenses ² Current tax liabilities Total financial liabilities Fair value hierarchy ⁴ Level 2 Carrying values At December 31, 2018 At December 31, 2017 236,717 14,080 3,875 16 254,688 185,692 2,799 4,827 - 193,318 Financial liabilities are initially recognised at the fair value of the amount expected to be paid and are subsequently measured at amortised cost using the effective interest rate method. ¹ The carrying amount of the Company’s financial assets approximate their fair values at the balance sheet dates. ² No valuation techniques have been applied to establish the fair value of these financial instruments as they are either cash and cash equivalents, correspond to payment terms fixed by contract or, due to the short-term nature, are readily convertible to or settled with cash and cash equivalents. ³ The fair value of the Company’s borrowings at the balance sheet date was $240 million (December 31, 2017: $151.8 million). The fair value has been determined based on quoted market prices of similar bonds held by similar companies within the industry. ⁴ Fair value measurements IFRS 13 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a fair value hierarchy of three levels to classify the inputs to valuation techniques used to measure fair value: ▪ ▪ Level 1: fair value measurements are based on unadjusted quoted market prices; Level 2: fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted prices or indices; Level 3: fair value measurements are derived from valuation techniques that include inputs that are not based on observable market data. ▪ 55 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Capital risk management The Company manages its capital to ensure that entities within the Company will be able to continue as a going concern, while maximising return to shareholders. The capital structure of the Company consists of cash and cash equivalents and equity, comprising issued share capital, reserves and retained earnings as disclosed in the consolidated statement of changes in equity. The Company had debt relating to borrowings and accrued interest of $250.8 million as at December 31, 2018 (2017: $188.5 million). Refer also to Note 16. Financial risk management objectives The Company’s management monitors and manages the Company’s exposure to financial risks facing the operations. These financial risks include market risk (including commodity price, foreign currency and interest rate risks), credit risk and liquidity risk. The Company does not presently hedge against these risks as the benefits of entering into such agreements is not considered to be significant enough as to outweigh the significant cost and administrative burden associated with such hedging contracts. Commodity price risk The prices that the Company receives for its oil and gas production may have a significant impact on the Company’s revenues and cash flows provided by operations. World prices for oil and gas are characterised by significant fluctuations that are determined by the global balance of supply and demand and worldwide political developments and, in particular, the price received for the Company’s oil and gas production in Kurdistan is dependent upon the Kurdistan government and its ability to export production outside of Iraq. A decline in the price of ICE Brent Crude oil, a reference in determining the price at which the Company can sell future oil production, could adversely affect the amount of funds available for capital reinvestment purposes as well as the Company’s value in use calculations for impairment test purposes. Refer also to Note 4(d). The table below summarises the effect that a change in the Dated Brent oil price would have had on the net income during the year ended December 31, 2018: Net income reported in the financial statements Possible shift - (decrease) / increase in Dated Brent oil price in % Total (decrease) / increase in net income The Company does not hedge against commodity price risk. Foreign currency risk 1,869 (10%) (6,893) 1,869 10% 6,893 The substantial portion of the Company’s operations require purchases denominated in USD, which is the functional and reporting currency of the Company and the currency in which the Company maintains the substantial portion of its cash and cash equivalents. Certain of its operations require the Company to make purchases denominated in foreign currencies, which are currencies other than USD and correspond to the various countries in which the Company conducts its business, most notably, Swiss Francs (“CHF”) and Canadian dollars (“CAD”). As a result, the Company holds some cash and cash equivalents in foreign currencies and is therefore exposed to foreign currency risk due to exchange rate fluctuations between the foreign currencies and the USD. The Company considers its foreign currency risk is limited because it holds relatively insignificant amounts of foreign currencies at any point in time and since its volume of transactions in foreign currencies is currently relatively low. The Company has elected not to hedge its exposure to the risk of changes in foreign currency exchange rates. The carrying amounts of the Company’s principal monetary assets, liabilities and equity denominated in foreign currency at the reporting date are as follows: Assets December 31, 2018 2017 Liabilities December 31, 2018 2017 Equity December 31, 2018 2017 Canadian dollars in thousands (“CAD 000”) Swiss francs in thousands (“CHF 000”) 31 280 36 83 258 133 68 221 223,146 - 225,318 - 56 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Foreign currency sensitivity analysis The Company is exposed to movements in CHF and CAD against the USD, the presentational currency of the Company. Sensitivity analyses have been performed to indicate how the profit or loss would have been affected by changes in the exchange rates between the USD and CHF and CAD. The analysis below is based on a strengthening of the CHF and CAD by 1% against the USD in which the Company has assets, liabilities and equity at the end of respective period. A movement of 1% reflects a reasonably possible sensitivity when compared to historical movements over a three to five-year timeframe. The sensitivity analysis includes only outstanding foreign currency denominated monetary items and adjust their translation at the period end for a 1% change in foreign currency rates. A positive number in the table below indicates an increase in profit where USD weakens 1% against the CHF or CAD based on the CHF and CAD assets, liabilities and equity held by the Company at the balance sheet dates. For a 1% strengthening of the USD against the CHF or CAD there would be an equal and opposite impact on the profit or loss. Statement of comprehensive income - CAD Statement of comprehensive income - CHF Interest rate risk Assets 2018 - 3 Liabilities Equity 2017 2018 2017 2018 2017 - 1 (1) (1) - (2) (1,209) - (1,442) - The Company earns interest income at variable rates on its cash and cash equivalents and is therefore exposed to interest rate risk due to a fluctuation in short-term interest rates. The Company’s policy on interest rate management is to maintain a certain amount of funds in the form of cash and cash equivalents for short-term liabilities and to have the remainder held on relatively short-term deposits. The Company is highly leveraged though financing at the project level, for the continuation of Atrush project, and at the corporate level due to the $240 million of bond which have been issued since July 2018. However, the Company is not exposed to interest rate risks associated with the bonds as the interest rate is fixed. Interest rate sensitivity analysis: Based on exposure to the interest rates for cash and cash equivalents at the balance sheet date an increase or decrease of 0.5% in the interest rate would not have a material impact on the Company’s profit or loss for the year. An interest rate of 0.5% is used as it represents management’s assessment of the reasonably possible changes in interest rates. Credit risk Credit risk is the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Company. The Company is primarily exposed to credit risk on its cash and cash equivalents, loans and receivables and other receivables. The Company manages credit risk by monitoring counterparty ratings and credit limits and by maintaining excess cash and cash equivalents on account in instruments having a minimum credit rating of R-1 (mid) or better (as measured by Dominion Bond Rate Services) or the equivalent thereof according to a recognised bond rating service. The carrying amounts of the Company’s financial assets recorded in the consolidated financial statements represent the Company’s maximum exposure to credit risk. 57 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Liquidity risk Liquidity risk is the risk that the Company will have difficulties meeting its financial obligations as they become due. In common with many oil and gas exploration companies, the Company raises financing for its exploration and development activities in discrete tranches to finance its activities for limited periods. The Company seeks to acquire additional funding as and when required. The Company anticipates making substantial capital expenditures in the future for the acquisition, exploration, development and production of oil and gas reserves and as the Company’s project moves further into the development stage, specific financing, including the possibility of additional debt, may be required to enable future development to take place. The financial results of the Company will impact its access to the capital markets necessary to undertake or complete future drilling and development programs. There can be no assurance that debt or equity financing, or future cash generated by operations, would be available or sufficient to meet these requirements or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The Company manages liquidity risk by maintaining adequate cash reserves and by continuously monitoring forecast and actual cash flows. Annual capital expenditure budgets are prepared, which are regularly monitored and updated as considered necessary. In addition, the Company requires authorisations for expenditure on both operating and non-operating projects to further manage capital expenditures. The maturity profile of the Company’s financial liabilities is indicated by their classification in the consolidated balance sheet as “current” or “non-current”. 22. Commitments and contingencies As at December 31, 2018 the outstanding commitments of the Company were as follows: Atrush Block development and PSC Office and other Total commitments For the year ended December 31, 2019 47,583 39 47,622 2020 120 - 120 2021 Thereafter 120 - 120 1,328 - 1,328 Total 49,151 39 49,190 Amounts relating to Atrush Block development represent the Company’s unfunded paying interest share of 20.1% of the approved 2019 work program and other obligations under the Atrush PSC. Under the terms of the Atrush PSC the Company will owe a share of production bonuses payable to the KRG when cumulative oil production from Atrush reaches production milestones defined in the Atrush PSC as follows: $13.3 million at 25 million barrels (ShaMaran share: $3.6 million); and $23.3 million at 50 million barrels (ShaMaran share: $6.2 million). Refer also to Notes 16 and 23. 23. Interests in joint operations and other entities Interests in joint operations - Atrush Block Production Sharing Contract ShaMaran holds a 20.1% direct interest in the Atrush PSC through GEP. TAQA Atrush B.V. is the Operator of the Atrush Block with a 39.9% direct interest, the KRG holds a 25% direct interest and MOKDV holds a 15% direct interest. TAQA, the KRG, GEP and MOKDV together are “the Contractors” to the Atrush PSC. Under the terms of the 4th PSC Amendment and the Facilitation Agreement, which became effective on November 7, 2016, the Non-Government Contractors paid their pro-rata share of the Feeder Pipeline costs and the KRG’s share of Atrush development costs up to October 31, 2017, the date when the Final Completion Certificate for the Atrush Feeder Pipeline for the Feeder Pipeline was issued. These costs are now being reimbursed to the Non-Government Contractors in 24 equal monthly instalments with the last instalment due to be paid in October 2019. 58 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Under the terms of the Atrush PSC the development period is for 20 years with an automatic right to a five-year extension and the possibility to extend for an additional five years. All qualifying petroleum costs incurred by the Contractors shall be recovered from a portion of available petroleum production, defined under the terms of the Atrush PSC. All modifications to the Atrush PSC are subject to the approval of the KRG. The Company is responsible for its pro-rata share of the costs incurred in executing the development work program on the Atrush Block which commenced on October 1, 2013. Refer also to Notes 13, 22 and 25. Information about subsidiaries The consolidated financial statements of the Company include: Subsidiary Principal activities Country of Incorporation % equity interest as at 31 Dec 2018 31 Dec 2017 ShaMaran Petroleum Holdings Coöperatief U.A. Oil exploration and production Oil exploration and production ShaMaran Ventures B.V. Oil exploration and production General Exploration Partners, Inc. Oil exploration and production ShaMaran Petroleum B.V. Technical and admin. services ShaMaran Services S.A. Inactive Bayou Bend Petroleum U.S.A. Ltd The Netherlands The Netherlands Cayman Islands The Netherlands Switzerland United States 100 100 100 100 100 100 100 100 100 100 100 100 24. Related party transactions Transactions with corporate entities Bennett-Jones Namdo Management Services Ltd. Lundin Petroleum AB Total Purchases of services during the year 2018 2017 Amounts owing at December 31, 2017 2018 51 34 104 189 45 50 204 299 - - - - - - 18 18 Bennett-Jones is a law firm in which an officer of the Company is a partner and has provided legal services to the Company. Amounts reported under Bennett Jones are inclusive of services provided to the Company by McCullough O’Connor Irwin LLP, which merged with Bennett Jones on June 1, 2018, where the same officer of the Company was previously a partner. Namdo Management Services Ltd. is a private corporation affiliated with a shareholder of the Company and has provided corporate administrative support and investor relations services to the Company. The Company received services from various subsidiary companies of Lundin Petroleum AB (“Lundin”), a shareholder of the Company until June 21, 2018 when Lundin sold its ShaMaran shares. Lundin charges from January 1 to June 21, 2018 of $104 (year 2017: $204) were comprised of office rental, administrative and building services of $88 (year 2017: $177), technical service costs of $nil (year 2017: $1) and investor relations services of $16 (year 2017: $26). All transactions with related parties are in the normal course of business and are made on the same terms and conditions as with parties at arm’s length. Refer also to Note 25. 59 SHAMARAN PETROLEUM CORP. Notes to the Consolidated Financial Statements For the year ended December 31, 2018 (Expressed in thousands of United States dollars unless otherwise stated) ______________________________________________________________________________ Key management compensation The Company’s key management was comprised of its directors and executive officers who have been remunerated as follows: Management’s salaries Management’s short-term benefits Directors’ fees Management’s pension benefits Management’s share-based payments Directors’ share-based payments Total For the year ended December 31, 2017 2018 881 464 166 121 - - 1,632 877 959 81 120 9 3 2,049 Short-term employee benefits include non-equity incentive plan compensation and other short-term benefits. Share- based payments compensation represents the portion of the Company’s share-based payments expense incurred during the year attributable to the key management, accounted for in accordance with IFRS 2 ‘Share Based Payments’. 25. Events after the reporting period On January 23, 2019, the Company issued to Nemesia 2,000,000 common shares of ShaMaran in accordance with the terms of the Liquidity Guarantee. Refer to Note 16, Borrowings, for further information about the developments after the year ending December 31, 2018, regarding the Company’s bonds. Refer also to Notes 13, 16, 18, 23 and 24. 60 SHAMARAN PETROLEUM CORP. DIRECTORS CORPORATE INFORMATION Keith C. Hill Director, Chairman Florida, U.S.A. Chris Bruijnzeels Director, President & Chief Executive Officer CORPORATE OFFICE 885 West Georgia Street Suite 2000 Vancouver, British Columbia V6C 3E8 Telephone: +1-604-689-7842 Facsimile: +1-604-689-4250 Geneva, Switzerland Website: www.shamaranpetroleum.com Brian D. Edgar Director Vancouver, British Columbia Terry L. Allen Director Calgary, Alberta Michael Ebsary Director Geneva, Switzerland OPERATIONS OFFICE 5 Chemin de la Pallanterie 1222 Vésenaz Switzerland Telephone: +41-22-560-8600 Facsimile: +41-22-560-8601 BANKER HSBC Bank Canada Vancouver, British Columbia INDEPENDENT AUDITORS PricewaterhouseCoopers SA Geneva, Switzerland TRANSFER AGENT OFFICERS Computershare Trust Company of Canada Brenden Johnstone Chief Financial Officer Revelstoke, British Columbia Kevin E. Hisko Corporate Secretary Vancouver, British Columbia Vancouver, British Columbia STOCK EXCHANGE LISTINGS TSX Venture Exchange and NASDAQ First North Exchange Trading Symbol: SNM INVESTOR RELATIONS Sophia Shane Vancouver, British Columbia 61 

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