UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL … · Finance lease obligation 11 11,344 ‐...

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015

ORYX PETROLEUM CORPORATION LIMITED Unaudited Condensed Consolidated Interim Financial Statements

For the three and nine months ended September 30, 2015

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Table of contents

Page

Condensed Consolidated Interim Statement of Loss and Comprehensive Loss 2

Condensed Consolidated Interim Statement of Financial Position 3

Condensed Consolidated Interim Statement of Changes in Equity 4

Condensed Consolidated Interim Statement of Cash Flows 5

Notes to the Condensed Consolidated Interim Financial Statements 6



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Condensed Consolidated Interim Statement of Loss and Comprehensive Loss

Three months ended

September 30 Nine months ended

September 30

$000s Note 2015 2014 2015 2014

Revenue 4,227 10,430 18,934 11,808

Royalties (1,731) (4,271) (7,753) (4,835)

Net revenue 2,496 6,159 11,181 6,973

Operating expenses (5,738) (3,602) (15,509) (4,762)Depreciation, depletion and amortization 4,5 (2,264) (1,881) (6,797) (2,858)Impairment of oil and gas assets 4,5 (310,841) ‐ (310,841) (1,181)Pre‐license costs (103) (966) (1,111) (3,769)General and administrative expenses (3,171) (4,693) (10,320) (12,632)Other income 18 5,430 3,076 6,415 1,516

Loss from operations (314,191) (1,907) (326,982) (16,713)

Finance income 1 112 13 275

Finance expense (2,146) (240) (3,507) (611)

Foreign exchange (losses) / gains (396) 627 (118) 376

Loss before income tax (316,732) (1,408) (330,594) (16,673)

Income tax expense 19 (1,104) (148) (1,485) (475)

Net loss for the period (317,836) (1,556) (332,079) (17,148)

Other comprehensive loss (net of income tax) (Items that will not be subsequently reclassified to profit and loss)

Loss on defined benefit obligation (856) (365) (2,599) (1,113)

Total comprehensive loss for the period (318,692) (1,921) (334,678) (18,261)

Net loss for the period attributable to: Owners of the Company (309,452) (1,556) (323,699) (17,120)

Non‐controlling interest (8,384) ‐ (8,380) (28)

(317,836) (1,556) (332,079) (17,148)

Total comprehensive loss for the period attributable to: Owners of the Company (310,308) (1,921) (326,298) (18,233)

Non‐controlling interest (8,384) ‐ (8,380) (28)

(318,692) (1,921) (334,678) (18,261)

Loss per share (basic and diluted) 15 (2.56) (0.01) (2.68) (0.16)



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Condensed Consolidated Interim Statement of Financial Position September 30 December 31

$000s Note 2015 2014

Non‐current assets

Intangible assets 4 156,546 254,107

Property, plant and equipment 5 613,060 734,221

Deferred tax assets 3,134 2,783

772,740 991,111

Current assets

Inventories 6 25,077 22,146

Trade and other receivables 7 2,362 3,402

Other current assets 8 3,432 11,687

Cash and cash equivalents 9 35,014 109,870

65,885 147,105

Total assets 838,625 1,138,216

Current liabilities

Trade and other payables 10 66,096 95,016

Finance lease obligation 11 5,086 ‐

Deferred revenue ‐ 957

Current income tax liabilities 725 994

71,907 96,967

Non‐current liabilities

Borrowings 12 45,492 ‐

Trade and other payables 10 63,160 64,718

Finance lease obligation 11 11,344 ‐

Retirement benefit obligation 8,173 6,867

Decommissioning obligation 13 5,443 9,061

133,612 80,646

Total liabilities 205,519 177,613

Equity

Share capital 14 1,227,128 1,226,248

Reserves 16 18,772 5,763

Remeasurement of defined benefit obligation, net of income tax (10,140) (7,541)

Accumulated deficit (603,334) (279,635)

Equity attributable to owners of the company 632,426 944,835

Non‐controlling interests 680 15,768

Total equity 633,106 960,603

Total equity and liabilities 838,625 1,138,216

The condensed consolidated interim financial statements were approved by the Board of Directors and authorized for issue on November 11, 2015. On behalf of the Board of Directors: (signed) (signed) Jean Claude Gandur Peter Newman Director Director



4

Condensed Consolidated Interim Statement of Changes in Equity

Attributable to equity holders of the Company

$000s Share capital Reserves Accumulated

deficit

Remeasurement of defined benefit

obligation Total

Non‐controlling interests

Total equity

Balance at January 1, 2014 1,009,684 5,186 (261,585) (3,966) 749,319 16,713 766,032

Net loss for the period ‐ ‐ (17,120) ‐ (17,120) (28) (17,148)Shares issued through public offering 14 209,725 ‐ ‐ ‐ 209,725 ‐ 209,725Issuance costs 14 (3,063) ‐ ‐ ‐ (3,063) ‐ (3,063)Share based payment expense 14 ‐ 8,515 ‐ ‐ 8,515 ‐ 8,515Shares issued for long term incentive plan (“LTIP”) 14, 16 9,491 (9,491) ‐ ‐ ‐ ‐ ‐ Shares issued for Directors’ compensation 14, 16 299 (75) ‐ ‐ 224 ‐ 224Loss on defined benefit obligation, net of income tax ‐ ‐ ‐ (1,113) (1,113) ‐ (1,113) Disposal of subsidiaries

(1) ‐ ‐ 27 ‐ 27 7 34

Balance at September 30, 2014 1,226,136 4,135 (278,678) (5,079) 946,514 16,692 963,206

Net loss for the period ‐ ‐ (945) ‐ (945) (917) (1,862)Share based payment expense 16 ‐ 1,665 ‐ ‐ 1,665 ‐ 1,665Shares issued for LTIP 14, 16 112 (112) ‐ ‐ ‐ ‐ ‐Shares issued for Directors’ compensation 14, 16 ‐ 75 ‐ ‐ 75 ‐ 75Loss on defined benefit obligation, net of income tax ‐ ‐ ‐ (2,462) (2,462) ‐ (2,462) Disposal of subsidiaries

(1) ‐ ‐ (12) ‐ (12) (7) (19)

Balance at December 31, 2014 1,226,248 5,763 (279,635) (7,541) 944,835 15,768 960,603

Net loss for the period ‐ ‐ (323,699) ‐ (323,699) (8,380) (332,079)

Share based payment expense 14 ‐ 4,223 ‐ ‐ 4,223 ‐ 4,223

Shares issued for LTIP 14, 16 580 (580) ‐ ‐ ‐ ‐ ‐

Shares issued for Directors’ compensation 14, 16 300 (75) ‐ ‐ 225 ‐ 225

Warrants issued 16 ‐ 6,741 ‐ ‐ 6,741 ‐ 6,741 Increase in ownership of KPA Western Desert Energy Limited

(2)

16 ‐ 2,700 ‐ ‐ 2,700 (6,708) (4,008)

Loss on defined benefit obligation, net of income tax

‐ ‐ ‐ (2,599) (2,599) ‐ (2,599)

Balance at September 30, 2015 1,227,128 18,772 (603,334) (10,140) 632,426 680 633,106

(1) During 2014, the Group disposed of its shares in the following subsidiaries: AmiraKPO Middle East Limited, Sandhill Petroleum Operations Limited, Desert Hill Petroleum Operations Limited, Damsel Petroleum Operations Limited, Black Hills Petroleum Operations Limited, and Raval Petroleum Operations Limited. The Group disposed of its investment in AmiraKPO Middle East Limited for Nil proceeds and recorded allowances for doubtful accounts related to the transaction for a total of $19,000 in charges to the Statement of Loss which are included in Other expenses.

(2) During the second quarter of 2015, the Group acquired an increased ownership interest in KPA Western Desert Energy Limited (“KPAWDE”) and increased its percentage ownership from 66.67% to 80.8%.



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Condensed Consolidated Interim Statement of Cash Flows

Three months ended

September 30 Nine months ended

September 30

$000s Note 2015 2014 2015 2014

Net loss (317,836) (1,556) (332,079) (17,148) Items not involving cash 17 311,536 3,389 319,417 12,821

(6,300) 1,833 (12,662) (4,327) Changes in non‐cash assets and liabilities 17 3,846 8,132 (2,136) (6,272)

Net cash (used in) / from operating activities (2,454) 9,965 (14,798) (10,599)

Cash flows used in investing activities Acquisition of intangible assets (1,815) (24,451) (6,441) (99,879)

Acquisition of property, plant and equipment (12,867) (55,761) (77,388) (176,293)

Changes in non‐cash working capital 17 (4,503) (1,642) (25,612) (35,930)

Net cash used in investing activities (19,185) (81,854) (109,441) (312,102)

Cash flows generated by financing activities

Related party financing 12 ‐ ‐ 50,000 ‐

Proceeds from issuance of ordinary shares 12 ‐ 209,725 ‐ 209,725

Transaction costs 12 ‐ (3,063) (617) (3,063)

Net cash generated from financing activities ‐ 206,662 49,383 206,662

Net (decrease) / increase in cash and cash equivalents (21,639) 134,773 (74,856) (116,039)

Cash and cash equivalents at beginning of the period 56,653 55,222 109,870 306,034

Cash and cash equivalents at end of the period 9 35,014 189,995 35,014 189,995



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NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

1. General information

Oryx Petroleum Corporation Limited (the “Company” or “OPCL”) is a public company incorporated in Canada under the Canada Business Corporation Act on December 31, 2012, and is the holding company for the Oryx Petroleum group of companies (together the “Group” or “Oryx Petroleum”). The address of the registered office of OPCL is 3400 First Canadian Centre 350, 7th Avenue Southwest, Calgary, Alberta, Canada T2J 2M2. The Group’s indirect majority shareholder is The Addax and Oryx Group PLC (“AOG”) (incorporated in Malta). The majority of AOG’s outstanding shares are owned by Samsufi Trust, an irrevocable discretionary charitable trust created at the suggestion of Jean Claude Gandur. Mr. Gandur is not one of the beneficiaries of the Samsufi Trust. The Group’s principal activities are to acquire and develop exploration and production assets in order to produce hydrocarbons and to increase oil and gas reserves.

The unaudited condensed consolidated interim financial statements were authorized for issue by the Board of Directors on November 11, 2015.

2. Summary of significant accounting policies

a. Basis of preparation

The unaudited condensed consolidated interim financial statements of the Company for the three and nine months ended September 30, 2015 have been prepared in accordance with the International Accounting Standard (IAS) 34 “Interim financial reporting”. The interim financial statements should be read in conjunction with Oryx Petroleum’s annual financial statements for the year ended December 31, 2014, which have been prepared in accordance with International Financial Reporting Standards (IFRS). Accounting policies included in the annual financial statements for the year ended December 31, 2014 are applicable to these interim statements.

The unaudited condensed consolidated interim financial statements have been prepared under the historical cost convention, as modified by the revaluation of financial assets and liabilities (including derivative instruments) at fair value through profit and loss.

The preparation of financial statements in conformity with IFRS, requires the use of critical accounting estimates. It also requires management to exercise its judgment in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the condensed consolidated interim financial statements are disclosed in the annual financial statements for the year ended December 31, 2014.

The condensed consolidated interim financial statements are presented in the US Dollar currency (USD), which is both the presentational and functional currency of the Company.

b. Going concern

These unaudited condensed consolidated interim financial statements have been prepared on a going concern basis which contemplates the realization of assets and the satisfaction of liabilities and commitments in the normal course of business for the foreseeable future. The Group meets its day to day working capital requirements, and funds its capital and operating expenditures through funding received from public offerings (note 14), its share of oil sale revenues from the Hawler License Area, and from borrowings (note 12).

The Company’s ability to continue as a going concern is uncertain and dependent on the Group’s ability to realize forecasted revenues, control the timing and extent of projected expenditures, and secure financing when required.

Management has applied significant judgment in preparing forecasts supporting the going concern assumption. Specifically, management has made assumptions regarding projected oil sale volumes and pricing, and the timing and extent of capital, operating, and general and administrative expenditures.



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2. Summary of significant accounting policies (continued)

Oil sales volume assumptions are based on actual production volumes adjusted to consider the impact of production increases expected to result from planned development drilling and well productivity optimization. Crude oil price assumptions are based on ICE Brent forward contract prices adjusted for transportation costs and quality differentials. The timing and extent of capital, operating and general administrative expenditures is based on the Group’s revised forecasts for the remainder of 2015, on the Group’s approved budget for 2016 and on management’s best estimate of expenditures expected to be incurred beyond periods covered by forecasts and approved budgets.

The Group has a substantial degree of control and flexibility over both the extent and timing of expenditure under its future capital investment program. Nevertheless, the Group requires access to additional financing to fund its budgeted capital investments and operating and general and administrative expenditures, and to meet its obligations as they fall due in the 12 months following September 30, 2015. The timing and magnitude of the requirement for additional financing is uncertain and dependent on actual oil production and sale volumes and realized prices. However, while cash on hand, the remaining undrawn portion of the AOG credit facility, and the Group’s share of oil sale revenues are expected to fund the Group’s operations into the second quarter of 2016, $50 ‐ $75 million of additional capital is required to fund all budgeted cash expenditures in 2016.

Management is monitoring the Group’s financing requirements and is implementing plans to secure funding at appropriate cost. Specifically, management is currently engaged in a number of discussions with third‐parties on potential transactions which would provide sufficient financing. The potential transactions being considered include business combinations, the issuance of common shares to public or private / strategic investors, various forms of debt, asset sales, and various combinations thereof.

Should the Group be unable to secure the financing required to fund its budgeted capital investments and operating and general and administrative expenditures, and to meet its obligations as they fall due in the 12 months following September 30, 2015, the preparation of these unaudited condensed consolidated interim financial statements on a going concern basis may not be appropriate. The condensed consolidated interim financial statements do not reflect adjustments that would be necessary if the going concern assumption were not appropriate. Such adjustments may be material.

The directors have considered the judgements, estimates, and related uncertainties discussed above and have concluded that there is a reasonable expectation that the Group will be able to access adequate resources to continue operations for the foreseeable future and, therefore, continue to adopt the going concern basis in preparing these unaudited condensed consolidated interim financial statements.

c. New and amended standards applicable to the Group

At the date of authorization of these financial statements, the following standards applicable to the Group were issued but not yet effective:

Effective for annual New and Amended Standards periods beginning on or after

IFRS 9, IFRS 7, IAS 39 – Financial Instruments: classification and measurement January 1, 2018 Additions to IFRS 9 for financial liability accounting January 1, 2018 IFRS 15 – Revenue from contracts with customers January 1, 2018 Amendments to IFRS 11 – Accounting for acquisitions of interests in joint operations January 1, 2016 Amendments to IAS 16 & IAS 38 – Clarification of acceptable methods of depreciation and amortization January 1, 2016 Amendments to IAS 27 – Equity method in separate financial statements January 1, 2016 Amendments to IFRS 10 & IAS 28 – Sale or contributions of assets between an investor and its associate or joint venture January 1, 2016 Annual improvement cycles; 2012 – 2014 January 1, 2016 Amendments to IFRS 10, IFRS 12 & IAS 28 – Application of the consolidation exemption January 1, 2016 Amendments to IAS 1 – Disclosure initiative January 1, 2016



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Management has reviewed the impact of the new and amended standards listed above and has concluded that the adoption of these standards and amendments are not expected to have a material impact on the Group’s condensed consolidated interim financial statements.

3. Joint arrangements

The Group has entered into Joint arrangements to facilitate the development and production of oil and gas.

As at September 30, 2015, the Company was involved in the following joint arrangements:

License Area

Classification Location Participating

interest(1)

Hawler Joint operation Iraq – Kurdistan Region 65% Wasit Joint operation Iraq – Wasit province 75%(2) AGC Shallow Joint operation Senegal and Guinea Bissau 85% AGC Central Joint operation Senegal and Guinea Bissau 85% OML 141 Joint operation Nigeria 38.67% Haute Mer A Joint operation Congo (Brazzaville) 20% Haute Mer B Joint operation Congo (Brazzaville) 30%

(1) Participating interest is the Group’s current interest in the applicable license area. Participating interest differs from working interest which reflects the impact of unexercised back‐in rights or options.

(2) This amount includes an interest attributable to a non‐controlling third party. The Group’s participating interest net of the non‐controlling interest is 60.62%.

4. Intangible assets

$000s Note Exploration &

Evaluation costs Computer Software Total

Cost

At January 1, 2014 311,865 1,684 313,549

Additions 99,592 287 99,879

At September 30, 2014 411,457 1,971 413,428

Additions 10,462 121 10,583 Transfers and reclassifications(1) 5 (55,941) ‐ (55,941)

At December 31, 2014 365,978 2,092 368,070

Additions 6,722 70 6,792

At September 30, 2015 372,700 2,162 374,862

Accumulated amortization and impairment

At January 1, 2014 111,965 864 112,829 Amortization ‐ 397 397 Impairment charge(2) 1,181 ‐ 1,181

At September 30, 2014 113,146 1,261 114,407

Amortization ‐ 134 134 Impairment charge(2) (578) ‐ (578)

At December 31, 2014 112,568 1,395 113,963

Amortization ‐ 350 350 Impairment charge(3) 104,003 ‐ 104,003

At September 30, 2015 216,571 1,745 218,316

Net book value

At September 30, 2015 156,129 417 156,546

At December 31, 2014 253,410 697 254,107 At September 30, 2014 298,311 710 299,021

(1) In December 2014, following a reserve report, effective December 31, 2014, from Netherland, Sewell & Associates, Inc. (NSAI) confirming the discovery of reserves at Banan within the Hawler license area, a portion of the E&E costs in Kurdistan was transferred from intangible assets to property, plant and equipment (PP&E). As a result, $55.9 million of costs associated with the license area were transferred from intangible E&E assets to Oil and Gas assets classified as PP&E at December 31, 2014.



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4. Intangible assets (continued) (2) In conjunction with the operator, drilling on the Horse prospect (formerly Ma) in the western portion of the Haute Mer A license area

offshore Congo (Brazzaville) was completed in the fourth quarter of 2013. Although the H‐1 well encountered both Tertiary and Cretaceous reservoirs with good porosity, the reservoirs were water bearing. The Company considers the well unsuccessful. An impairment charge of $17.3 million was recorded during the fourth quarter of 2013. An additional impairment charge of $1.2 million was recorded in the first half of 2014 and adjusted by $0.6 million in the fourth quarter of 2014 based on updated information received from the operator. The H‐1 well has been written down to Nil value.

(3) At September 30, 2015, management determined that the limited exploration and evaluation activities now planned for the Wasit and OML 141 license areas during the foreseeable future constituted an indicator of impairment. Management concluded that given the fact that cash flows attributable to the assets in their current condition could not be established, the recoverable amount of these assets calculated using the value‐in‐use methodology for each of the Wasit and OML 141 CGUs was Nil. The Group consequently recorded impairment provisions of $43.8 million related to the Wasit license area and of $60.2 million for the OML 141 license area. As at September 30, 2015, the carrying value of the Wasit and OML 141 CGUs is Nil.

The carrying amounts of intangible exploration and evaluation (“E&E”) assets relate to:

September 30 September 30 December 31 $000s 2015 2014 2014

Middle East 50,170 145,483 93,181 West Africa 105,959 152,828 160,229

156,129 298,311 253,410

The carrying amounts for E&E assets represent costs incurred on exploration projects. For the purpose of impairment assessments and testing, E&E assets are aggregated in cash‐generating units (“CGU”). Determination of what constitutes a CGU is subject to management judgements and the circumstances. For the purposes of impairment assessments and testing, management has determined that each license area constitutes a CGU. The carrying amounts remain capitalized, provided there are no indications of impairment, until the process to determine whether commercial reserves are established is complete. At that stage the relevant costs are either transferred to PP&E or written‐off to the statement of comprehensive loss as an impairment of oil and gas assets.

Management has exercised significant judgement in determining that for the Hawler – Ain al Safra, Senegal – AGC Shallow, Senegal – AGC Central, Congo – Haute Mer A, and Congo – Haute Mer B CGUs, there are no substantive indicators suggesting that the carrying amounts of exploration and evaluation assets exceed their recoverable amounts. Most significantly, assessments regarding the presence of impairment indicators include complex judgments and estimates relating to i) management’s current and future capital allocation priorities, and ii) the Group’s ability to finance its commitments within the time limitations imposed by the agreements governing the Group’s activities in each of above license areas / CGUs.



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5. Property, plant and equipment

$000s Note Oil & Gas

Assets

Finance lease

asset(1) Facilities under Construction(1)

Fixtures and

Equipment Total

Cost

At January 1, 2014 440,651 ‐ 1,116 2,444 444,211 Additions 161,654 ‐ 19,145 1,332 182,131

At September 30, 2014 602,305 ‐ 20,261 3,776 626,342

Additions 45,768 ‐ 11,109 26 56,903 Transfers and reclassifications 4 55,941

‐ ‐ ‐ 55,941

At December 31, 2014 704,014 ‐ 31,370 3,802 739,186

Additions(2) 76,489 16,717 (543) (476) 92,187 Transfers and reclassifications(1)

4,623 26,204 (30,827) ‐ ‐

At September 30, 2015 785,126 42,921 ‐ 3,326 831,373

Accumulated depreciation, depletion and impairment

At January 1, 2014 ‐ ‐ ‐ 387 387 Depreciation ‐ ‐ ‐ 669 669 Depletion 1,863 ‐ ‐ ‐ 1,863

At September 30, 2014 1,863 ‐ ‐ 1,056 2,919

Depreciation ‐ ‐ ‐ 211 211

Depletion 1,835 ‐ ‐ ‐ 1,835

At December 31, 2014 3,698 ‐ ‐ 1,267 4,965

Impairment expense 206,838 ‐ ‐ ‐ 206,838 Depreciation ‐ ‐ ‐ 599 599 Depletion 5,889 22 ‐ ‐ 5,911

At September 30, 2015 216,425 22 ‐ 1,866 218,313

Net book value

At September 30, 2015 568,701 42,899 ‐ 1,460 613,060

At December 31, 2014 700,316 ‐ 31,370 2,535 734,221 At September 30, 2014 600,442 ‐ 20,261 2,720 623,423

(1) During 2013, the Kurdistan Regional Government gave its consent for the Group to lease a production facility for the Hawler license area. The related facilities were commissioned in September 2015. Refer to note 11 for further information on the finance lease obligation. Prior to commissioning, costs associated with the production facility were classified as Facilities under Construction. Upon commissioning, the costs were transferred to Finance lease asset and Oil & Gas assets as appropriate.

(2) The credits to additions relate to expenditures incurred at values below those estimated in prior periods.

No assets have been pledged as security.

The carrying amounts for Oil & Gas assets are subject to impairment assessment and testing in accordance with IAS 36. For the purpose of impairment assessments and testing, Oil & Gas assets are aggregated in CGUs. Determination of what constitutes a CGU is subject to management judgements and the circumstances. For the purposes of impairment assessments and testing of Oil & Gas assets, management has determined that the Oil & Gas assets in the Hawler license area outside of the Ain al Safra area constitute the group’s single CGU which contains property, plant and equipment.



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5. Property, plant and equipment (continued)

In conducting impairment tests, management considers internal and external sources of information regarding the manner in which assets are being used or are expected to be used and indications of economic performance of the assets. Estimates include but are not limited to the determination of future after‐tax cash flows expected to be derived from the asset being tested and the discount rate used to determine the value of the cash flows at the measurement date. Reductions in oil price forecasts, increases in estimated future costs of production, increases in estimated future capital costs, reductions in the amount of recoverable reserves and resources and/or adverse current economics can result in estimated carrying amounts exceeding the recoverable amounts of the Group’s Oil & Gas assets. An impairment loss is recognized if and when the carrying amount exceeds the recoverable amount.

Following the presence of indicators of possible impairment primarily related to the reduction in the market price of crude oil and lower than expected production from existing wells during the second and third quarters of 2015, management conducted an impairment test on the Hawler license area CGU at September 30, 2015. In performing the impairment test, management used significant assumptions and estimates initially derived from and consistent with those incorporated in the proved and probable reserves development case contained in the Group’s National Instrument 51‐101 compliant Statement of Reserves Data and Other Oil and Gas Information (a “Reserve Report”) as at December 31, 2014, adjusted to reflect reduced well production rates, current crude oil price forecasts, and a $1/bbl anticipated increase to operating costs to reflect incremental water handling activities related to future production of crude oil from Banan and Demir Dagh Cretaceous reservoirs.

Future well production rates for current and future development wells in the Banan and Demir Dagh Cretaceous reservoirs were estimated based on the actual performance of producing wells since commencement of production in June 2014. The Banan and Demir Dagh Cretaceous reservoir production rates used in management’s impairment test are consistent with the lowered production rates reflected in the Netherland, Sewell & Associates, Inc.’s (“NSAI”) sensitivity analysis provided to the Company during September 2015 (the “2015 NSAI Sensitivity Letter”). Production rates for other reservoirs in the Hawler license area were held consistent with the 2015 NSAI Sensitivity Letter and the production profiles contained in the Group’s Reserve Report as at December 31, 2014.

Expected cash inflows from oil sales were based on quoted ICE Brent Crude forward contract prices for 2015 and 2016 and an average of forecasts of ICE Brent Crude prices prepared by three Canadian independent consultants updated as at October 1, 2015 for 2017 and beyond. International Export Prices and the Local Market Prices are determined by adjusting the assumed ICE Brent Crude price for oil gravity and sulphur content specifications, and applicable transportation costs. Expected cash inflows for 2015 and 2016 have been adjusted to reflect sales volumes consistent with the Group’s approved 2016 budget which assumes that all crude oil sold during 2016 will be sold at local market prices. The weighted average sales price assumed in calculating cash inflows from oil sales in 2017 and beyond is the weighted average of international export prices and local market prices. All sales up to gross (100%) 15,000 bbl/d are assumed to be local market sales and sales above gross (100%) 15,000 bbl/d are assumed to be international export sales. Such allocation reflects management’s reasonable expectations regarding oil sale allocations and is not a contractual obligation.



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5. Property, plant and equipment (continued)

Based on the above, expected cash inflows from oil sales were determined using the following estimated weighted average sales prices:

Year ending December 31,

ICE Brent Crude Price

($/bbl)

International Export Price

($/bbl)

Local Market Price

($/bbl)

Weighted Average Sales Price ($/bbl)

2015 49.12 39.12 23.12 23.12 2016 53.34 43.34 27.34 27.34 2017 65.60 55.60 39.60 51.52 2018 70.20 60.20 44.20 57.63 2019 74.90 64.90 48.90 62.45 2020 78.35 68.35 52.35 65.84 2021 81.87 71.87 55.87 69.13 2022 85.40 75.40 59.40 72.18 2023 89.06 79.06 63.06 75.26 2024 91.94 81.94 65.94 77.31 2025 93.78 83.78 67.78 77.55 Thereafter 2% escalation

Management applied the fair value less costs of disposal methodology to establish the net present value of expected after‐tax cash flows using a 12.5% discount rate. Management selected the 12.5% discount rate based on management’s estimate of the cost of capital invested in upstream oil & gas assets in the Kurdistan region of Iraq.

In measuring the recoverable amount of the Hawler license area CGU as defined in IFRS 13, management relied on i) observable inputs other than quoted prices for identical assets, and ii) inputs that are not publically observable and are the result of management’s estimates and judgments arising from analysis of internally generated data.

Application of the fair value less costs of disposal methodology using the assumptions described above indicates an estimated recoverable amount of the Hawler license area CGU as at September 30, 2015 to be $526.7 million. Consequently, the Group has recorded a $206.8 million impairment provision during the three months ended September 30, 2015. The impairment provision represents the difference between the recoverable amount of the Hawler license area CGU and its carrying amount which includes the carrying values of decommissioning and finance lease obligations and the contingent liabilities, for which settlement is included in the discounted expected after‐tax cash‐flows.

The net present value of expected after‐tax cash‐flows associated with the proved and probable reserves development case described above were subjected to sensitivities arising from changes in crude oil price forecasts and discount rates. The following table indicates the recoverable amounts as at September 30, 2015 that result from applying various crude oil price forecasts and discount rates:

Recoverable amount ($ millions)

Discount rate

10% 12% 12.5% 13% 15%

Above prices less $5/bbl 617.5 474.7 442.5 411.6 299.6 Prices listed above 705.6 559.6 526.7 495.0 380.0 Above prices plus $5/bbl 803.5 652.9 618.9 586.2 467.0

The net present value of expected after‐tax cash‐flows associated with the proved and probable reserves development case is also highly sensitive to the Group’s internal and independently evaluated estimation of proven and probable reserves and to the production profile associated with the exploitation of these reserves. While the Group has engaged NSAI to conduct a Reserves Report to be effective as at December 31, 2015, the results of the evaluation are not available at the date these unaudited condensed consolidated interim financial statements have been approved by the Board of Directors. In the event that the Reserve Report as at December 31, 2015 indicates that proven and probable reserves and associated production profiles are substantively different than the proven plus probable reserves and production profiles used to estimate the Hawler license area CGU’s recoverable amount and implied in the NSAI Sensitivity Letter, the Group may further adjust the carrying value of its Hawler license area CGU.



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6. Inventories

September 30 December 31 $000s 2015 2014

Oil inventory 1,569 1,851 Materials 23,508 20,295

25,077 22,146

The cost of oil inventory is expensed through production and depletion expense in the period during which it is sold. As at September 30, 2015 the Group’s working interest share of oil inventory was 55,349 bbls (December 31, 2014 – 50,878 bbls).

No inventories have been pledged as security or expensed during the period.

7. Trade and other receivables


Receivables from joint operations partners 1,149 2,719 Trade and other receivables 1,213 683

2,362 3,402

The carrying amounts of trade and other receivables presented above are reasonable approximations of their fair values and are not past due or impaired.

Joint operations receivables arise from timing differences between cash calls and the expenditures incurred on behalf of joint operations partners.

8. Other current assets


Deposits 754 6,237 Prepaid charges and other current assets 2,678 5,450

3,432 11,687

The carrying amounts of other current assets are reasonable approximations of their fair value.

9. Cash and cash equivalents

Cash and cash equivalents comprise cash and short‐term deposits with an original maturity of three months or less, substantially held in interest‐bearing accounts. The carrying amounts are reasonable approximations of the fair value.

10. Trade and other payables


Trade accounts payable 15,268 17,705 Amounts payable to joint operations partners 4,002 7,941 Amounts payable to related parties 158 158 Contingent costs 63,160 64,718 Other payables and accrued liabilities 46,668 69,212

129,256 159,734

Less: Non‐current portion of contingent costs (63,160) (64,718)

Current portion 66,096 95,016



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10. Trade and other payables (continued)

The carrying amounts of trade accounts payables, amounts payable to joint operations partners, amounts payable to related parties, and other payables and accrued liabilities, as presented above are reasonable approximations of their fair values.

As at September 30, 2015, the Group has recognized a $63.2 million (December 31, 2014: $64.7 million) liability related to contingent consideration on the acquisition of OP Hawler Kurdistan Limited. The contingent liability is estimated to be paid beyond one year of the respective statement of financial position dates and is classified as a long‐term liability. The contingent consideration liability is presented at fair value estimated by discounting future cash outflows at a rate of 10% (note 20).

11. Finance lease obligation

The Group has entered into a leasing arrangement for the production facilities in the Hawler licence area. The production facilities were commissioned in September 2015. The lease contains options for the Company to settle all obligations under the lease at any point prior to September 2018. In calculating the minimum lease payments under the lease, management has assumed that the assets will be purchased two years following commissioning of the asset, in September 2017. The lease arrangement has an imputed interest rate of 11.6%.

Minimum lease payments Present value of minimum lease payments

$000s Note

September 30, 2015

December 30, 2014

September 30, 2015

December 30, 2014

No later than one year 6,731 ‐ 5,086 ‐One to five years 12,364 ‐ 11,344 ‐Greater than five years ‐ ‐ ‐ ‐

19,095 ‐ 16,430 ‐Less: future finance charges (2,665) ‐ ‐ ‐

Present value of minimum lease payments

16,430 ‐ 16,430 ‐

12. Borrowings

On March 11, 2015, the Group entered into a committed and unsecured term loan facility agreement (the “Loan Facility”) with a subsidiary of its indirect majority shareholder The Addax and Oryx Group PLC (the “Lender”).

The three year Loan Facility provides the Group with access to committed funding up to $100 million with a maturity date of March 10, 2018 (the “Maturity Date”). Interest and principal amounts owing to the Lender are payable at the Maturity Date or earlier, at the option of the borrower. An annual compound rate of interest of 10.5% is payable to the Lender under the terms of the loan facility.

On March 11, 2015, the Company issued to an affiliate of the Lender warrants to acquire one million of its common shares. The cost of the warrants has been included as a transaction cost in securing the financing and the value of the financial instrument has been recorded within equity at fair value at the date of issuance (note 14b).

On May 11, 2015, the Group drew the first $50 million tranche under the Loan Facility. Concurrent with the drawdown, the Company issued warrants to an affiliate of the Lender to acquire seven million of its common shares. The cost of the warrants has been included as a deferred financing cost and the value of the financial instrument has been recorded within equity at fair value at the date of issuance (note 14b).



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12. Borrowings (continued)

The loan proceeds have been recorded as a non‐current liability, net of warrant issue and other transaction costs. The carrying value of the loan at September 30, 2015, which has been measured at amortized cost using the effective rate method, approximates its fair value and its components are summarized in the table below: $000s Borrowings

Principal 50,000

Deferred financing costs:

Transaction costs (1,375)

Warrants issued (5,984)

Net Proceeds 42,641

Interest expense 2,073

Accretion of deferred financing costs 778

At September 30, 2015 45,492

13. Decommissioning obligation

The Group has obligations to decommission its oil and gas assets upon cessation of operations.

In calculating the value of the Group’s future decommissioning obligation at September 30, 2015, management has made significant assumptions and estimates based on an assessment of the current economic environment and factors specific to the assets to be decommissioned. These estimates are reviewed annually and when circumstances suggest that such revisions are required. Actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain. The inflation rates used in the calculation to determine the carrying value of the decommissioning obligation were updated during the three months ended June 30, 2015 to rates ranging from 3.3% ‐ 3.4% (December 31, 2014: 3.7% ‐ 5.8%). The discount rate used at September 30, 2015 is 8% (December 31, 2014: 8%). Decommissioning costs are anticipated to be incurred between 2038 and 2041.

The estimated net present value of the decommissioning obligation at September 30, 2015 is $5.4 million (December 31, 2014: $9.1 million) based on the Group’s working interest undiscounted liability of $32.6 million (December 31, 2014: $57.5 million).


Decommissioning obligation, beginning of the period 9,061 1,346 Property acquisition and development activity ‐ 4,167 Change in discount rate ‐ 2,045

Change in inflation rate (3,772) 1,380

5,289 8,938 Accretion expense 154 123

Decommissioning obligation, end of the period 5,443 9,061



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14. Share capital

a. Issued common shares

$000s Number of

shares Share capital

At January 1, 2014 99,854,918 1,009,684

Issue of shares through public offering 19,910,000 206,662

Issue of shares for LTIP and share grant 964,109 9,491

Issue of shares for directors’ compensation 24,657 299

At September 30, 2014 120,753,684 1,226,136

Issue of shares for LTIP 14,232 112

At December 31, 2014 120,767,916 1,226,248

Issue of shares for LTIP 453,641 580 Issue of shares for directors’ compensation 82,150 300

At September 30, 2015 121,303,707 1,227,128

The Company has unlimited authorized share capital outstanding as at September 30, 2015.

2015 share capital transactions

During the nine months ended September 30, 2015, the Group issued 453,641 shares to employees under the Group’s LTIP. An additional 82,150 shares were issued to Directors of the Company as remuneration.

2014 share capital transactions

On July 18, 2014, pursuant to a prospectus supplement to the short form base shelf prospectus dated January 27, 2014 the Company issued 19,910,000 Common Shares of the Company at a price of CAD$11.25 per Common Share for aggregate gross proceeds of CAD$224.0 million ($209.7 million). Costs associated with the issuance of these shares amounted to $3.1 million.

During the year ended December 31, 2014, the Group issued 978,341 shares to employees and executive officers under the Group’s LTIP. An additional 24,657 shares were granted to Directors of the Company as remuneration.

b. Warrants

On March 11, 2015, in accordance with the Loan Facility described in note 11, the Group issued warrants to an affiliate of the Lender to acquire one million common shares of the Company. The exercise price of the issued warrants is CAD$4.39 per common share. The expiry date of the issued warrants is March 10, 2018.

On May 11, 2015, also in accordance with the Loan Facility described in note 11, the Group issued warrants to an affiliate of the Lender to acquire seven million common shares of the Company. The exercise price of the issued warrants is CAD$4.75 per common share. The expiry date of the issued warrants is May 11, 2018.

The Company uses the Black‐Scholes option pricing model to calculate the fair value of warrants. Option pricing models require the input of subjective assumptions regarding the volatility, dividend yield and expected term. Changes in the input assumptions may materially affect the estimated fair value.

The following input assumptions were used to establish the fair value of warrants issued during the nine months ended September 30, 2015: March 11, 2015 May 11, 2015

Risk‐free interest rate 0.46% 0.67%

Expected life (years) 3 3

Expected volatility 39.58% 39.58%

Dividend rate ‐ ‐



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14. Share capital (continued)

The following table summarises warrants outstanding and exercisable at the dates indicated:

Nine months ended September 30, 2015

Warrants Exercise price CAD$ Expiry date

Outstanding, beginning of the period ‐ ‐ Issued 1,000,000 4.39 March 10, 2018 Issued 7,000,000 4.75 May 11, 2018

Outstanding, end of the period 8,000,000

15. Basic and diluted loss per share

The loss and weighted average number of shares used in the calculation of the basic and diluted loss per share are as follows: Three Months ended Nine Months ended

September 30 September 30

$000s 2015 2014 2015 2014

Net loss for the period attributable to equity holders

(309,452) (1,556) (323,699) (17,120)

Weighted average number of ordinary shares for basic and diluted loss per share(1)

121,112,980 116,752,833 120,923,099 105,570,405

$

Basic and diluted loss per share (2.56) (0.01) (2.68) (0.16)

(1) The unvested LTIP shares and warrants are excluded as they are anti‐dilutive.

16. Reserves

$000s Other Reserves Share based payments

Total reserves

At January 1, 2014 ‐ 5,186 5,186 Share based payment transactions ‐ 8,515 8,515 Issue of shares for LTIP ‐ (9,491) (9,491) Share based directors compensation 225 225 Issue of shares for directors’ compensation ‐ (300) (300)

At September 30, 2014 ‐ 4,135 4,135

Share based payment transactions ‐ 1,665 1,665 Issue of shares for LTIP ‐ (112) (112) Issue of shares for directors’ compensation ‐ 75 75

At December 31, 2014 ‐ 5,763 5,763

Share based payment transactions ‐ 4,223 4,223 Issue of shares for LTIP ‐ (580) (580) Share based directors compensation 225 225 Issue of shares for directors’ compensation ‐ (300) (300) Issue of warrants (note 14b) ‐ 6,741 6,741 Increase in ownership of KPAWDE(1) 2,700 ‐ 2,700

At September 30, 2015 2,700 16,072 18,772

(1) During the second quarter of 2015, the Group acquired an increased ownership interest in KPA Western Desert Energy Limited (“KPAWDE”) and increased its percentage ownership from 66.67% to 80.8%.



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17. Supplemental cash flow information

Items not involving cash Three Months ended Nine Months ended September 30 September 30

$000s Note 2015 2014 2015 2014

Depreciation, depletion and amortization 2,264 1,881 6,797 2,858Share based payment expense 318 4,127 1,633 8,515Impairment of oil and gas assets 310,841 ‐ 310,841 1,181Retirement benefit obligation ‐ 682 ‐ 2,080Unrealized foreign exchange losses / (gains) 392 (67) 591 15Non‐cash income tax expense / (benefit) 888 (437) 476 (983) Finance expense 2,145 194 3,506 440 General and administrative expense 100 81 1,970 231Other income 21 (5,412) (3,072) (6,397) (1,516)

Items not involving cash 311,536 3,389 319,417 12,821

Changes in non‐cash assets and liabilities Three Months ended Nine Months ended September 30 September 30

$000s 2015 2014 2015 2014

Inventories (1,438) (5,821) (2,833) (3,385)Trade and other receivables 5,028 1,541 1,443 (6,518)Other current assets 3,596 (1,206) 5,082 (3,126)Trade and other payables (7,578) 9,180 (29,952) (34,183)Current income tax liabilities (264) 215 (269) 844Deferred revenue ‐ 1,923 (957) 2,449

Changes in non‐cash working capital

(656) 5,832 (27,486) (43,919)

Retirement benefit obligation (1) 658 (262) 1,717

Changes in non‐cash assets and liabilities (657) 6,490 (27,748) (42,202)

Changes in operating non‐cash assets and liabilities

3,846 8,132 (2,136) (6,272)

Changes in investing non‐cash assets and liabilities

(4,503) (1,642) (25,612) (35,930)

Changes in non‐cash assets and liabilities (657) 6,490 (27,748) (42,202)

Other cash flow Information Three Months ended Nine Months ended September 30 September 30

$000s 2015 2014 2015 2014

Cash interest received 8 38 13 129 Cash interest paid ‐ ‐ ‐ 281 Cash income taxes paid ‐ 155 1,037 252



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18. Other income

The components of other income for the periods indicated are as follows:

Three Months ended Nine Months ended September 30 September 30

$000s Note 2015 2014 2015 2014

Curtailment of retirement benefit obligation 4,460 ‐ 4,460 ‐Change in fair value of contingent consideration 22 970 3,076 1,955 1,516

Other income 5,430 3,389 6,415 1,516

19. Income tax expense

Three Months ended Nine Months ended September 30 September 30

$000s 2015 2014 2015 2014

Current income tax expense (217) (586) (1,009) (1,459) Deferred tax on LTIP shares 1 278 (3) 497 Deferred tax on defined benefit obligation (888) 160 (473) 487

Total deferred tax (887) 438 (476) 984

Income tax expense (1,104) (148) (1,485) (475)

The Group is subject to income taxes in certain jurisdictions where it owns licenses or has taxable operations. Current income tax expense relates to tax on profits from oil sales in the Kurdistan Region of Iraq and on taxable profits from operations of the Group’s Swiss and Maltese subsidiaries. For the nine months ended September 30, 2015, income taxes related to oil sales in the Kurdistan Region of Iraq in the amount of $0.4 million (2014 ‐ $0.2 million) were deemed to be paid to the government through its allocation of profit oil under the Hawler PSC.



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20. Segment information

The Group has a single class of business which is to acquire, explore, develop and produce oil from oil and gas assets. The Group operates in two geographical areas. Segmented information related to the two operating segments and corporate activities is as follows:

For the nine months ended September 30, 2015 $000s Middle East West Africa Corporate Total

Revenue 18,934 ‐ ‐ 18,934

Royalty (7,753) ‐ ‐ (7,753)

Net revenue 11,181 ‐ ‐ 11,181

Operating expense (15,509) ‐ ‐ (15,509) Depreciation, depletion and amortization (5,813) (31) (953) (6,797) Impairment of oil and gas assets (250,593) (60,247) ‐ (310,841) Pre‐license costs (359) (752) ‐ (1,111) General and administrative expense (293) (363) (9,664) (10,320) Other income 1,955 ‐ 4,460 6,415

Segment result (259,431) (61,393) (6,157) (326,982)

Finance income 13 Finance expense (3,507) Foreign exchange loss (118)

Loss before income tax (330,594)

Income tax expense (1,485)

Net loss for the period (332,079)

Capital additions(1) 93,408 5,892 (321) 98,979 Segment assets as at September 30, 2015 716,963 109,190 12,473 838,625

Segment liabilities as at September 30, 2015 142,289 4,372 58,857 205,519

(1) The credits to additions relate to actual expenditures concluded at values below those estimated in prior periods

For the nine months ended September 30, 2014 $000s Middle East West Africa Corporate Total

Revenue 11,808 ‐ ‐ 11,808

Royalty (4,835) ‐ ‐ (4,835)

Net revenue 6,973 ‐ ‐ 6,973

Operating expense (4,762) ‐ ‐ (4,762) Depreciation, depletion and amortization (1,793) (28) (1,037) (2,858) Impairment of oil and gas assets ‐ (1,181) ‐ (1,181) Pre‐license costs (1,094) (2,675) ‐ (3,769) General and administrative expense (112) (298) (12,222) (12,632)

Other income 1,516 ‐ ‐ 1,516

Segment result 728 (4,182) (13,259) (16,713)

Finance income 275 Finance expense (611) Foreign exchange gains 376


Income tax expense (475)


Capital additions 230,347 50,043 1,620 282,010 Segment assets as at September 30, 2014 908,553 219,858 23,896 1,152,307

Segment liabilities as at September 30, 2014 161,955 11,950 18,272 192,177



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20. Segment information (continued) For the three months ended September 30, 2015 $000s Middle East West Africa Corporate Total

Revenue 4,227 ‐ ‐ 4,227

Royalty (1,731) ‐ ‐ (1,731)

Net revenue 2,496 ‐ ‐ 2,496

Operating expense (5,738) ‐ ‐ (5,738) Depreciation, depletion and amortization (1,964) (11) (289) (2,264) Impairment of oil and gas assets (250,593) (60,247)) ‐ (310,841) Pre‐license costs (70) (33) ‐ (103) General and administrative expense (5) (88) (3,078) (3,171) Other income 970 ‐ 4,460 5,430

Segment result (254,904) (60,380) 1,093 (314,191)

Finance income 1 Finance expense (2,146) Foreign exchange loss (396)


Income tax expense (1,104)


Capital additions(1) 30,642 1,522 (395) 31,769

(1) The credits to additions relate to actual expenditures concluded at values below those estimated in prior periods

For the three months ended September 30, 2014 $000s Middle East West Africa Corporate Total

Revenue 10,430 ‐ ‐ 10,430

Royalty (4,271) ‐ ‐ (4,271)

Net revenue 6,159 ‐ ‐ 6,159

Operating expense (3,602) ‐ ‐ (3,602) Depreciation, depletion and amortization (1,583) (10) (288) (1,881) Impairment of oil and gas assets ‐ ‐ ‐ ‐ Pre‐license costs (373) (593) ‐ (966) General and administrative expense (64) (59) (4,570) (4,693)

Other income 3,076 ‐ ‐ 3,076

Segment result 3,613 (662) (4,858) (1,907)

Finance income 112 Finance expense (240) Foreign exchange gains 627


Income tax expense (148)


Capital additions 75,434 4,925 1,069 81,428



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20. Segment information (continued)

Non‐current assets, aggregated by country, are as follows:

September 30 September 30 December 31 $000s 2015 2014 2014

Iraq 661,769 766,186 824,866 Nigeria ‐ 59,058 59,574 Senegal and Guinea Bissau 35,503 28,248 31,957 Congo (Brazzaville) 70,501 65,649 68,824 Other 4,967 5,225 5,890

772,740 924,366 991,111

21. Commitments

(a) Contractual obligations

The Group has entered into agreements which contain provisions for the following spending commitments:


No later than one year 14,382 37,111 One to five years 59,427 84,138

Greater than five years 21,522 21,370

95,331 142,619

The commitments noted above reflect the Group’s execution of current budgeted and contracted exploration and development activities. Expenditure commitments may be subject to change and may be reduced by selective relinquishments of acreage and/or licenses or by curtailing the execution of activity under existing supplier contracts. Determining expenditure commitments requires the use of significant estimates and judgements primarily related to expectations of the timing and manner of execution of budgeted activities.

21. Commitments (continued)

(b) Operating lease commitments – Group company as lessee

The Group leases buildings and equipment under non‐cancellable operating lease agreements with varying terms and renewal rights. The corresponding lease expenditure charged to the statement of comprehensive loss during the three and nine months ended September 30, 2015 was $1.6 million and $5.0 million respectively (2014: $0.6 million and $2.5 million).

The future aggregate minimum lease payments under non‐cancellable operating leases are as follows:


No later than one year 2,004 2,385

One to five years 2,811 3,910

4,815 6,295



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22. Contingent liabilities

In the normal course of operations, the Company may be subject to litigation and claims. In management estimation, no such litigation or claim, individually or in aggregate, would result in a liability that would have a significant adverse effect on the financial position or results of operations of the Company.

During 2011, the Group acquired interests in various exploration licenses. The acquisition terms included additional consideration and liabilities which are contingent upon the outcome of future drilling activities and, in some cases, the quantities of reserves discovered. At September 30, 2015 these contingencies, including a $63.2 million (December 31, 2014: $64.7 million) liability which has been recorded and is discussed in note 10, amounted to a maximum of $176.2 million (December 31, 2014: $176.2 million). During the three and nine months ended September 30, 2015 the Group recorded income of $1.0 million and $2.0 million respectively reflecting a decrease in the fair value of the contingent consideration described above.

23. Events after the reporting date

Subsequent to the balance sheet date, the Group issued 455,327 Common Shares to employees under the Group’s Long Term Incentive Plan.

UNAUDITED CONDENSED CONSOLIDATED INTERIM FINANCIAL … · Finance lease obligation 11 11,344 ‐...

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