Results for the Period Ending December 31, 2018

RNS Number : 6010W

Jadestone Energy Inc.

18 April 2019

Jadestone Energy Inc.

Jadestone Energy Results for the Period Ending December 31, 2018
Record Quarterly Revenue and Cash from Operations

April 18, 2019-Singapore: Jadestone Energy Inc. (AIM:JSE, TSXV:JSE) ("Jadestone" or the "Company"), an independent oil and gas production company focused on the Asia Pacific region, reported today its consolidated audited financial statements (the "Financial Statements"), as at and for the twelve-month period ended December 31, 2018.

From January 1, 2018, the Company has moved to reporting its financial information from a March year end, to a calendar year end. For that reason, comparative financial information is provided for the nine-month period ended December 31, 2017.

The acquisition of the Montara Assets was completed on September 28, 2018, at which time Jadestone obtained control and 100% legal ownership, apart from interest in the associated licenses which remains subject to regulatory approval. For accounting purposes, Montara's results are reported in Jadestone's Financial Statements from September 28, 2018.

Financial highlights

● Net revenue during the fourth quarter was US$45.0 million, a record for the Company, an increase of 38% over the prior quarter, and more than double the revenue in the same quarter a year ago;

● Full year revenue was US$113.4 million, also a record for the Company, an increase of 64% over the annualised result for the nine-month period to December 31, 2017;

● Positive net cash generated from operations of US$32.5 million in the fourth quarter, a record for the Company and an increase from a US$12.2 million net use of funds in the prior quarter, and US$0.6 million for the same quarter a year ago;

● Full year positive net cash generated from operations of US$17.8 million, also a record for the Company, and compares to a US$6.6 million use of funds in the nine-month period to December 31, 2017;

● Total comprehensive income for the fourth quarter was US$28.9 million, a record for the Company, an increase of US$30.4 million on the prior quarter, and compares to US$0.8 million for the same quarter a year ago;

● Total comprehensive income for the full year was US$4.4 million, compared to a loss of US$14.9 million in the nine-month period to December 31, 2017;

● Gross debt reduced to US$101.8 million by year-end, following the first quarterly repayment on the US$120.0 million reserve based loan. After the March 2019 scheduled repayment of US$14.9 million, the principal balance outstanding is US$88.2 million;

● Gross cash and bank balances of US$71.6^[1] million at year-end, result in a net debt position of US$30.2 million; and

● Montara voluntary maintenance and inspection shutdown in Q4 2018-the seller agreed to fund cash calls to the tune of US$22.0 million.

Operational highlights

● The Stag production facility has achieved a safety performance of 2,438 days without an LTI^[2];

● Production during the fourth quarter averaged 5,215 bbls/d, including production from Montara in October only. This was prior to the voluntary maintenance and inspection shutdown commencing November 1, 2018, but averaged over the full quarter. Stag production was below plan at 2,644bbls/d due to two of the largest production wells suffering downhole pump failure, but despite all of this, overall production saw an increase of 69% over the prior quarter;

● Adjusting for the impact of the maintenance and inspection shutdown at Montara, the Company would have had average production for the quarter of 10,272 bbls/d, a multiple of the prior quarter or the same quarter a year ago;

● Shutdown at Montara completed January 11, 2019, clearing an extensive backlog of overdue maintenance and inspection tasks; and

● 2P reserves at December 31, 2018 of 42.8mm bbls comprising both Stag and Montara, an increase of 25.7mm bbls over the total at December 31, 2017.

Outlook highlights

● Stag infill well 49H commenced mid March 2019, and after a period of weather downtime, is now expected to be completed in early May, with first production targeted shortly thereafter;

● Montara development programme commencing Q2/Q3 with the replacement of the subsea umbilical and riserless light well intervention restoring gas lift to Skua-11 and Swift-2, unlocking new oil in the heel of Skua-11 and perforating additional sands in the Swallow-1 well;

● First infill well at Montara expected in Q4 2019 subject to rig availability, targeting 1.8mm bbls of 2P reserves and initial production of approximately 3,000 bbls/d;

● Plans to acquire a new 3D seismic survey in H2 2019, to improve reservoir imaging and assess further step-out potential beyond the existing H6 and Skua 12 target infills;

● Robust downside protection of oil price, and continued exposure to upside via capped swap, executed at the time of the Montara acquisition;

● Average swap price for 2019 is US$71.72/bbl (Dated Brent), while Montara crude is currently selling at a premium of circa US$3.50/bbl; and

● Substantial progress on the Nam Du/U Minh development in Vietnam, including a draft heads-of-agreement for the gas sales and purchase agreement expected to be signed shortly.

Paul Blakeley, President and CEO commented:

"Reporting our Q4 2018 and full year 2018 results caps what has been a transformational year for Jadestone. With the first production from Montara's ongoing operations benefiting the quarter, we have demonstrated a step-change in the cash generative capacity of our business. Even with decreasing commodity prices over the quarter and the extended maintenance and inspection shutdown, we managed to strengthen our balance sheet by putting cash in the bank and starting to pay down debt. Our financial position is strong, and we are poised to show growth and material cash flow going forward."

"At Montara, we remedied a significant backlog of overdue and inherited maintenance and inspection tasks. This was completely cleared, and gives us far greater confidence in the asset condition and its anticipated performance in the future, while the extensive early work undertaken has also helped to instill the Jadestone operating culture there. Since restarting the facility in January, production from Montara has exceeded our expectations and should be around 11,000bbls/d for the first quarter. We are more convinced than ever in the value proposition at Montara, and see a number of investment opportunities and efficiencies to add further value."

"Meanwhile, performance at the Stag oilfield has been below plan in the quarter due to downhole pump failures in two key production wells, one of which will require a workover in 2019, after the infill well. This should restore volumes, along with the benefits of the 49H infill well, the first well to be drilled on Stag in 6 years."

"Our plans for our Southwest Vietnam assets continue to take shape too. We have built an experienced project management organisation and have made great progress on the project, in anticipation of field development sanction late this year. In addition, I am delighted to see the progress the team is making with Petrovietnam on commercial matters, including negotiating definitive terms for the gas sales and purchase agreement."

Operations update

Acquisition of the Montara assets closed just three days before the start of the fourth quarter, with average production during October of 7,628 bbls/d, and one crude oil lifting of 451,291 bbls. Thereafter, the Company voluntarily shut down the facility to address an extensive backlog of overdue maintenance and inspection tasks. Montara's production resumed on January 11, 2019.

Upcoming activity at Montara in Q2 and early Q3, 2019 includes the replacement of the subsea umbilical from the Skua and Swift/Swallow subsea wells to the Company's owned FPSO, together with a riserless light well intervention ("RLWI") programme that will restore gas lift to the Skua-11 and Swift-2 wells, perforate additional sands in the Swallow-1 well, and unlock new heel volumes in the Skua-11 well. The RLWI is expected to deliver approximately 3,200 bbls/d in H2 2019, ensuring continued production from Swift-2 and Skua-11, in addition to the new volumes.

The Company is also developing a plan for drilling its first infill well at Montara later in the year, subject to rig availability. The H6 well will use an existing slot on the Montara wellhead platform and develop 1.8 mm bbls of 2P reserves, targeting an initial rate of approximately 3,000 bbls/d in 2020. The Company is also planning to acquire a new 3D seismic survey in H2 2019, to improve reservoir imaging, to more accurately target future infill wells beyond the planned H6 and Skua-12 infill targets, and assess further step-out potential.

Production at the Stag oilfield was below plan averaging 2,644 bbls/d for the quarter, due to the loss of production from two key production wells, 36H and 37H, following failure of their electric submersible pumps. A workover on 36H returned production later in the quarter, while 37H will be the subject of a future workover campaign, following the drilling of the 49H infill well.

Work on the new Stag 49H infill well commenced in mid March 2019, the first infill at Stag in six years. Following a delay due to severe weather conditions, drilling activity recommenced on April 10, 2019 and the infill well is expected to be completed in early May with first oil expected shortly thereafter. The well is targeting 1.2 mm bbls of 2P reserves and initial production rates of over 1,000 bbls/d.

In Vietnam, the Company made good progress towards delivery of the Nam Du and U Minh gas developments. During the fourth quarter, the Vietnam team was expanded to fill critical project management positions, and made substantial progress on all work fronts, including facilities front end engineering and design work, conducting technical and environmental studies, tendering for major contracts, and negotiating key commercial terms with Petrovietnam.

Financial overview

Results for the quarter were impacted by a voluntary shutdown of Montara to address the maintenance and inspection backlog. This resulted in only one month of production at Montara for the quarter, but costs continuing throughout the quarter, including an additional US$4.0 million of costs directly attributable to the maintenance and inspection shutdown.

The US$22.0 million adjustment agreed with the seller in connection with the Montara shutdown, has been accounted for as an adjustment to the fair value of assets acquired in the balance sheet, rather than via an immediate credit to the income statement, and was effected via the seller funding cash calls.

The Company reported quarterly revenue of US$45.0 million versus US$17.8 million in the same quarter a year ago, in part due to price realisations increasing from US$57.55/boe in Q4 2017 to US$67.51/bbl in Q4 2018. Total oil lifted in the quarter was 657,160 bbls, compared to 363,615 boe in the same quarter a year ago.

Full year revenue for 2018 was US$113.4 million compared to US$52.0 million for the comparable nine-month period. This was in large part due to total oil lifted in 2018 being 1.7 mm boe, compared to 1.1 mm boe in the comparable nine-month period to December 31, 2017, as well as price realisations increasing from US$53.40/boe in 2017 to US$69.39/boe in 2018.

Production costs for the quarter were US$42.6 million, clean of changes in the prices of inventory and the US$4.0 million of directly attributable costs for the maintenance and inspection shutdown, and versus US$9.0 million for the same quarter a year ago. This equates to US$28.94/bbl^[3] assuming October production at Montara had prevailed for the full quarter, i.e. adjusting for the impact of the two month shutdown, and includes 217,077 bbls of Montara crude acquired on September 28, 2019 and recorded at the realised price of US$68.13/bbl, as well as elevated costs at Montara during the transition period, versus US$22.29/boe¹ in Q4 2017.

Full year production costs for 2018 were US$82.9 million, clean of changes in the prices of inventory and the US$4.0 million of directly attributable costs for the maintenance and inspection shutdown, and versus US$43.5 million for the nine-months to December 31, 2017. This equates to US$28.72/boe^[4] and again includes 217,077 bbls of Montara crude acquired on September 28, 2019 and recorded at the realised price of US$68.13/bbl and versus US$28.13/boe² for the nine-months to December 31, 2017.

Jadestone generated an adjusted EBITDAX loss of US$1.7 million for the quarter ended December 31, 2018, compared to a positive EBITDAX of US$11.9 million in the prior quarter, and positive EBITDAX of US$4.6 million for the same quarter a year ago.

For the full year, the Company reports adjusted positive EBITDAX of US$9.2 million, compared to an EBITDAX loss of US$9.7 million for the nine-months to December 31, 2017.

On an unadjusted basis, the Company reported a net loss before tax of US$4.9 million, compared to a net profit of US$3.2 million in the third quarter and a net loss before tax of US$2.8 million for Q4 2017.

Results were impacted by the Montara voluntary shutdown and lower production volumes from the Stag oilfield, due to two key producer wells being down for a part of the quarter.

The Company generated positive cash from operations of US$32.5 million for the quarter, compared to US$0.6 million for the same quarter a year ago, despite the maintenance and inspection shutdown. This is partly driven by the seller agreeing to pay cash calls during the latter portion of the quarter as well as changes in working capital, and an ongoing focus on costs throughout the business, including at Stag.

For the full year, the Company generated positive cash from operations of US$17.8 million, compared to cash used in operations of US$6.6 million for the comparative nine-month period. This US$24.4 million turnaround in positive cash from operations, with only one month of production at Montara in the current year, demonstrates the ongoing transformation of the business.

Cash used in investing activities for Q4 2018 was US$7.5 million, excluding the investment into the debt service reserve ("DSRA") under the RBL, and compares to US$0.6 million for Q4 2017. This includes preliminary work on the Montara umbilical replacement and on the Stag 49H infill well, as well as increased activities in Vietnam toward the commercialisation of the Nam Du and U Minh gas fields.

For the full year, the Company invested US$161.4 million, inclusive of US$133.1 million paid to the Montara seller and the US$18.6 million deposited to the DSRA, and compared to US$2.1 million invested in the comparable nine-month period to December 31, 2017.

Cash used in financing activities in Q4 2018 was US$18.9 million, the majority of which comprised RBL repayment of US$16.9 million, and compares to cash used of US$0.6 million for Q4 2017.

For the full year, the Company raised a net US$184.9 million from financing activities, net of the repayment of the convertible bond of US$17.4 million, and the first RBL repayment at year end. This compares to US$4.7 million for the nine-month period to December 31, 2017.

At year end, the Company had $53.0 million cash, plus $18.6 million of debt service reserve cash and a further US$10.0 million of cash in support of a bank guarantee. Net debt was US$30.2 million, excluding the US$10.0 million of cash in support of the bank guarantee, and a further US$14.9 million of RBL principal was repaid on March 29, 2019.

Additionally, the Company's existing capped swap provides very robust support for 2019 cash generation establishing, as it does, a floor benchmark crude oil price of US$71.72/bbl for 50% of planned 2PD production at Stag, before allowing for the circa US$3.50/bbl premium that Montara currently enjoys.

[1] Excludes a US$10.0 million deposit in support of a bank guarantee

[2] Reporting for Montara will commence post transfer of operatorship

[3] This excludes the impact of workovers and repairs and maintenance at Stag given their unpredictable timing, and costs associated with Montara umbilical and RLWI which are opex related and will be tracked separately as per 2019 guidance

[4] This excludes the impact of workovers and repairs and maintenance at Stag given their unpredictable timing, and costs associated with Montara umbilical and RLWI which are opex related and will be tracked separately as per 2019 guidance

Selected financial information

The following table provides selected financial information of the Company, which was derived from, and should be read in conjunction with, the consolidated audited financial statements for the period ended December 31, 2017.

Quarterly comparison	Dec 2018 quarter	Dec 2017 quarter	Change (%)
Production, mboe¹	479.8	402.0	19.4%
Sales, mboe¹	657.2	363.8	80.7%
Avg realised liquids price², US$/boe¹	67.51	57.55	17.3%
Sales revenue¹, US$ million	45.0	17.8	52.8%
Capital expenditure², US$ million	7.5	0.6	N/M
Quarterly comparison	Dec 2018 quarter	Sep 2018 quarter	Change (%)
Production, mbbls	479.8	306.1	56.8%
Sales, mbbls	657.2	422.3	55.6%
Avg realised liquids price², US$/bbl	67.51	77.07	-12.4%
Sales revenue², US$ million	45.0	32.7	37.6%
Capital expenditure³, US$ million	7.5	1.7	N/M
Yearly comparison	Year to Dec 2018	9M to Dec 2017⁴	Change (%)
Production, mboe¹	1,480.0	1,165.7	27.0%
Sales, mboe¹	1,683.1	1,133.5	48.5%
Avg realised liquids price², US$/boe¹	69.39	53.40	29.9%
Sales revenue², US$ million	113.4	52.0	18.1%
Capital expenditure³, US$ million	10.0	2.6	N/M

¹ Production, sales and average realised prices are expressed on a barrels of oil equivalent basis as the underlying data includes gas production from Ogan Komering for the prevailing period based on Jadestone's 50% participating interest up until May 19, 2018
² Revenue has been restated from gross to net after deducting royalties, but including the effective gain on hedging contracts
³ Payment for oil and gas property, plant and equipment and intangible exploration assets. Excludes acquisition related capital expenditure
⁴ Comparable reporting period for the current period is the nine months ended December 31, 2017

Conference call and webcast

The management team will host an investor and analyst conference call at 9:00 p.m. (Singapore), 2:00 p.m. (London), and 9:00 a.m. (Toronto) today, Thursday, April 18, 2019, including a question and answer session.

The live webcast of the presentation will be available at the below webcast link. Dial-in details are provided below. Please register approximately 15 minutes prior to the start of the call. The results for the period ended December 31, 2018 will be available on the Company's website at: www.jadestone-energy.com/investor-relations/.

Webcast link: https://event.on24.com/wcc/r/1964214/68A3F57926E8403B758AC386B99793F5
Event conference title: Jadestone Energy Inc. - Fourth Quarter Results
Start time: 9:00 p.m. (Singapore), 2:00 p.m. (London), 9:00 a.m. (Toronto)
Date: Thursday, April 18, 2019
Confirmation ID: 54105682

Country	Dial-in numbers¹
Australia	1800076068
Canada (Toronto)	416 764 8609
Canada (Toll free)	888 390 0605
France	0800916834
Germany	08007240293
Germany (Mobile)	08007240293
Hong Kong	800962712
Indonesia	0078030208221
Ireland	1800939111
Ireland (Mobile)	1800939111
Japan	006633812569
Malaysia	1800817426
Singapore	18001013217
Switzerland	0800312635
Switzerland (Mobile)	0800312635
United Kingdom	08006522435
United States (Toll free)	888 390 0605

¹ Area access numbers are subject to carrier capacity and call volumes.

- Ends -

Enquiries

Jadestone Energy Inc.	+65 6324 0359 (Singapore)
Paul Blakeley, President and CEO	+1 403 975 6752 (Canada)
Dan Young, CFO	ir@jadestone-energy.com
Robin Martin, Investor Relations Manager

Stifel Nicolaus Europe Limited (Nomad, Joint Broker)	+44 (0) 20 7710 7600 (UK)
Callum Stewart
Nicholas Rhodes
Ashton Clanfield

BMO Capital Markets Limited (Joint Broker)	+44 (0) 20 7236 1010 (UK)
Thomas Rider
Jeremy Low
Thomas Hughes

Camarco (Public Relations Advisor)	+ 44 (0) 203 757 4980 (UK)
Billy Clegg	jadestone@camarco.co.uk
James Crothers

About Jadestone Energy Inc.

Jadestone Energy Inc. is an independent oil and gas company focused on the Asia Pacific region. It has a balanced, low risk, full cycle portfolio of development, production and exploration assets in Australia, Vietnam and the Philippines.

The Company has a 100% operated working interest in Stag, offshore Australia, and a 100% legal and beneficial interest in the Montara assets, and a 99% legal, subject to regulatory approval, beneficial right, title, and interest in the associated production licences AC/L7 and AC/L8 (the "Montara Titles"). The remaining 1% legal interest in the Montara Titles is being held on trust by the seller, in favour of the Company, until Australian regulatory approvals relating to the transfer of operatorship of the Montara assets are obtained. Both the Stag and Montara assets include oil producing fields, with further development and exploration potential. The Company has a 100% operated working interest (subject to registration of PVEP's withdrawal) in two gas development blocks in Southwest Vietnam and is partnered with Total in the Philippines where it holds a 25% working interest in the SC56 exploration block.

Led by an experienced management team with a track record of delivery, who were core to the successful growth of Talisman's business in Asia, the Company is pursuing an acquisition strategy focused on growth and creating value through identifying, acquiring, developing and operating assets throughout the Asia- Pacific region.

Jadestone Energy Inc. is currently listed on the TSXV and AIM. The Company is headquartered in Singapore. For further information on Jadestone please visit www.jadestone-energy.com.

Cautionary statements

Certain statements in this press release are forward-looking statements and information (collectively "forward-looking statements"), within the meaning of the applicable Canadian securities legislation, as well as other applicable international securities laws. The forward-looking statements contained in this press release are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of phrases such as "will likely result", "are expected to", "will continue", "is anticipated", "is targeting", "estimated", "intend", "plan", "guidance", "objective", "projection", "aim", "goals", "target", "schedules", and "outlook"). In particular, forward-looking statements in this press release include, but are not limited to statements regarding target reserves volumes, production forecasts, cost projections, timing and results of exploration activities on both Stag and Montara, timing and results of the Montara light well intervention programme and replacement of subsea umbilical, expected costs, commodity prices and timing of the gas sales agreement for Nam Du and U Minh.

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Jadestone. The forward-looking information contained in this news release speaks only as of the date hereof. The Company does not assume any obligation to publicly update the information, except as may be required pursuant to applicable laws. This announcement contains inside information as defined in Article 7 of the Market Abuse Regulation No. 596/2014 and is disclosed in accordance with the Company's obligations under Article 17 of that Regulation.

The technical information contained in this announcement has been prepared in accordance with the March 2007 guidelines endorsed by the Society of Petroleum Engineers, World Petroleum Congress, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers Petroleum Resource Management System.

Henning Hoeyland of Jadestone Energy Inc., a Subsurface Manager with a Masters degree in Petroleum Engineering who has been involved in the energy industry for more than 17 years, has read and approved the exploration and appraisal disclosure in this regulatory announcement.

The information contained within this announcement is considered to be inside information prior to its release, as defined in Article 7 of the Market Abuse Regulation No. 596/2014, and is disclosed in accordance with the Company's obligations under Article 17 of those Regulations.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

Glossary

2PD proved and probable developed reserves

2P reserves the sum of proved and probable reserves, denotes the best estimate scenario of reserves

bbls                  barrels of oil
bbls/d                barrels of oil per day
boe                   barrels of oil equivalent
boe/d                barrels of oil equivalent per day
EBITDAX        earnings before interest, tax, depreciation, amortisation and exploration expenses
FPSO               floating production, storage and offloading vessel
mbbl                 thousands of barrels of oil

mboe thousands of barrels of oil equivalent

mm bbls millions of barrels of oil

mm boe millions of barrels of oil equivalent

PVEP Petrovietnam Exploration Production Corporation

Jadestone Energy Inc.

CONSOLIDATED FINANCIAL STATEMENTS

for the year ended December 31, 2018 and the nine months ended December 31, 2017

MANAGEMENT'S REPORT

The accompanying consolidated financial statements are the responsibility of management. The consolidated financial statements were prepared by management in accordance with International Financial Reporting Standards ("IFRS") outlined in the notes to the consolidated financial statements.

Management maintains appropriate systems of internal controls. Policies and procedures are designed to give reasonable assurance that transactions are appropriately authorised, assets are safeguarded and financial records properly maintained to provide reliable information for the presentation of consolidated financial statements.

Deloitte & Touche LLP, an independent firm of chartered accountants, was appointed by the shareholders to audit the consolidated financial statements and to provide an independent professional opinion.

The Audit Committee reviewed the consolidated financial statements with management. The Board of Directors has approved the consolidated financial statements on the recommendation of the Audit Committee.

These financial statements were approved by the directors & authorised for issue on April 18, 2019.

"A. Paul Blakeley" "Daniel Young"

________________________ _________________________

A. Paul Blakeley Daniel Young

Director Director

April 18, 2019 April 18, 2019

Jadestone Energy Inc.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF JADESTONE ENERGY INC.

Opinion

We have audited the accompanying consolidated financial statements of Jadestone Energy Inc. and its subsidiaries (the "Group"), which comprise the consolidated statements of financial position as at December 31, 2018 and 2017, and the consolidated statements of profit or loss and other comprehensive income, consolidated statement of changes in equity and consolidated statements of cash flows for the year ended December 31, 2018 and nine month period ended December 31, 2017, and notes to the consolidated financial statements, including a summary of significant accounting policies.

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial positions of Jadestone Energy Inc. as at December 31, 2018 and 2017, and of its financial performance and its cash flows for the year ended December 31, 2018 and nine month period ended December 31, 2017, in accordance with International Financial Reporting Standards ("IFRS") as issued by International Accountant Standards Board ("IASB").

Basis for Opinion

We conducted our audit in accordance with Canadian generally accepted auditing standards ("Canadian GAAS"). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Financial Statements section of our report. We are independent of the Group in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Key Audit Matters

Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the consolidated financial statements of the current year. These matters were addressed in the context of our audit of the consolidated financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.

Key Audit Matters

How the matter was addressed in the audit

Impairment assessment of oil and gas properties

As at December 31, 2018, the Group recorded US$415.4 million of oil and gas properties, which approximate 57% of the Group's total assets.

Management performed an assessment of the internal and external factors of the oil and gas properties' carrying values to determine whether there is any indicator of impairment.

Based on management's assessment, there were no impairment indicators identified.

Notwithstanding the above, as the oil and gas properties is a material component of the Group's total assets, management further assessed recoverability of its oil and gas properties by looking at future cash flows from the respective oil and gas properties ("Financial Model") at December 31, 2018 and its future plans for these assets. They have also engaged an independent qualified person to estimate, where appropriate, the proved, probable and possible reserves for certain of the oil and gas properties, including the future net cash flows arising from such. The above assessment requires the exercise of significant judgement about and assumptions on, amongst others, the discount rate, oil reserves, expected production volumes and future Brent oil prices.

The Group has made disclosures on the above judgement in Note 3, and further disclosures in Note 17 to the consolidated financial statements.

Our audit procedures focused on evaluating impairment indicators in accordance with IAS 36, and challenging the judgements and key assumptions used by management in determining the recoverable amount. Such procedures included, amongst others:

· Reviewing the internal and external factors used by management to determine impairment indicators;

· Checking the Group's budget to evaluate whether management has a budget and plan for the assets, including the funding options for future capital expenditure to be able to realise the future cash flows;

· Checking the reserve reports prepared by the independent qualified person relating to the Group's estimated oil reserves, to determine whether they indicate there has been a significant change with an adverse effect on the recoverable amount;

· Assessing the objectivity, competency and experience of the independent qualified person who prepared the reserve reports;

· Challenging management's oil and gas price assumptions against external data, to determine whether they indicate that there has been a significant change with an adverse effect on the recoverable amount;

· Comparing field and plant production performance during the year against budget, to determine whether they indicate that there has been a significant change with an adverse effect on the recoverable amount; and

· Challenging management's assumptions on key data used in their computation of the discount rate.

Based on our procedures, we noted that the carrying amounts of oil and gas properties are stated appropriately.

We have further assessed the adequacy of the Group's disclosures that have been set out in Note 17 to the consolidated financial statements.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Key Audit Matters

How the matter was addressed in the audit

Impairment assessment of intangible exploration assets

As at December 31, 2018, the Group recorded US$95.6 million of intangible exploration assets, which approximate 13% of the Group's total assets.

Management performed an assessment of the internal and external factors of the oil and gas properties' carrying values to determine whether there is any indicator of impairment.

Based on management's assessment, there were no impairment indicators identified.

Notwithstanding the above, as the intangible exploration assets represents a material component of the Group's total assets, management performed an assessment of the technical feasibility and commercial viability of extracting a mineral resource and whether there is any adverse information that will affect the final investment decision to commercialise the asset.

They also engaged an independent qualified person to estimate, where appropriate, the gross contingent resources for all of the intangible exploration assets.

The Group has made disclosures on the above judgement in Note 3, and further disclosures in Note 16 to the consolidated financial statements.

Our audit procedures focused on evaluating and challenging the judgements and key assumptions used by management in performing the impairment review under IFRS 6. Such procedures included, amongst others:

· Reviewing the internal and external factors used by management to determine impairment indicators;

· Performing a retrospective review of prior year's work budget and current year's actual activity to determine the reliability of management's plan and budget for the purpose of assessing impairment indicators;

· Checking the reserve reports prepared by independent qualified person relating to the Group's estimated oil reserves, to determine whether they indicate if there has been a significant change with an adverse effect on the recoverable amount; and

· Assessing the objectivity, competency and experience of the independent qualified person who prepared the reserve reports.

Based on our procedures, we noted that the carrying amounts of intangible exploration assets are stated appropriately.

We have also checked the adequacy of the Group's disclosures that has been set out in Note 16 to the consolidated financial statements.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Key Audit Matters

How the matter was addressed in the audit

Purchase price allocation on Montara acquisition

During the year, Jadestone completed its acquisition of the Montara oil project, offshore Australia, from an independent third party. Upon which, all conditions precedent to the sale and purchase agreement have been satisfied, including payment of the purchase price of US$133 million and certain customary closing adjustments and contingency payments. The Group engaged an independent external valuer to assess the fair value of the identifiable assets acquired and liabilities assumed.

The fair value of the consideration was subsequently adjusted down to US$128 million as a result of prepaid assets for future cash calls of US$22 million, offset by deferred contingent consideration and working capital adjustment.

The above future cash calls of US$22 million resulted from an unplanned shutdown of the oil project, which management is of the view reflected facts and circumstances existing as at the acquisition date. As such, the amount was adjusted against the consideration transferred.

The accounting for this acquisition relied significantly on management estimation and judgments in respect of fair value assessments and the allocation of the purchase price.

Details of the acquisition are disclosed in Note 7 to the consolidated financial statements.

Our audit procedures included, amongst others:

· Assessing the sensitivities of management's estimates by evaluating the impact to the purchase price allocation within a certain range;

· Reading the sales and purchase agreement to understand the assets being acquired, liabilities assumed and the consideration payable for the acquisition;

· Obtaining a copy of the external valuation report to assess the determination of the fair values of the assets and liabilities associated with the acquisition;

· Assessing the independence, objectivity and experience of the independent external valuer used by management; and

· In conjunction with our internal valuation specialists, assessing the valuation methodology adopted in determining fair values of the identified assets and liabilities, the underlying assumptions against market data and the mathematical accuracy of the valuation models.

We have also checked the adequacy of the Group's disclosures that have been set out in Note 7 to the consolidated financial statements.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Key Audit Matters

How the matter was addressed in the audit

Asset restoration obligations ("ARO") relating to Montara Assets

As at December 31, 2018, Jadestone recognised an ARO provision of US$193 million, relating to Montara Assets which was acquired during the year. Accordingly, management conducted a detailed exercise to evaluate the ARO provision.

ARO provision is subject to judgement, as they are calculated using present value of the estimated future costs, which are based on assumptions that are impacted by future activities and the legislative environment in which the Group operates, as well as changes in the estimated date on which production will cease. Key assumptions include base cost of the ARO liability, inflation rate, discount rate and timing of future decommissioning activities. The Group engaged an independent external consultant in determining the cost base of the obligations.

The Group discounts future estimated restoration costs at 2.60%.

Our audit procedures included, amongst others:

· Assessing a sensitivity analysis on management estimates to assess likelihood of the provision being materially misstated;

· Using our internal ARO specialist to assess the cost estimates prepared by management and challenged the key assumptions;

· Confirming the closure and related decommissioning dates are consistent with the latest life of field estimates;

· Comparing the inflation and discount rates to available market information; and

· Testing the mathematical accuracy of the asset retirement provision.

We have also checked the adequacy of the Group's disclosures that has been set out in Note 27 to the consolidated financial statements.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Other Information

Management is responsible for the other information. The other information comprises Management's Discussion and Analysis (MD&A), but does not include the financial statements and our auditor's report thereon.

Our opinion on the consolidated financial statements does not cover the other information and we do not and will not express any form of assurance conclusion thereon. In connection with our audit of the consolidated financial statements, our responsibility is to read the other information 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.

We obtained the MD&A prior to the date of this auditor's report. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact in this auditor's report. 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 these consolidated financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is responsible for assessing the Group'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 Group or to cease operations, or has no realistic alternative but to do so.

Those charged with governance are responsible for overseeing the Group's financial reporting process.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Auditor's Responsibility for the Audit of the Financial Statements

Our objectives are to obtain reasonable assurance about whether the 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 GAAS 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 financial statements.

As part of an audit in accordance with Canadian GAAS, we exercise professional judgement and maintain professional skepticism throughout the audit. We also:

a) Identify and assess the risks of material misstatement of the 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.

b) 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 Group's internal control.

c) Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.

d) 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 Group'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 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 Group to cease to continue as a going concern.

e) Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether the financial statements represent the underlying transactions and events in a manner that achieves fair presentation.

f) Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group 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.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

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.

From the matters communicated with those charged with governance, we determine those matters that were of most significance in the audit of the financial statements of the current year and are therefore the key audit matters. We describe these matters in our auditor's report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

The engagement partner on the audit resulting in this independent auditor's report is Kanagasabai s/o Haridas.

"Deloitte & Touche LLP"

Deloitte & Touche LLP

Public Accountants and

Chartered Accountants

Singapore

April 18, 2019

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

for the year ended December 31, 2018 and nine months ended December 31, 2017

		Year ended December 31, 2018	Nine months ended December 31, 2017 Restated*
	Notes	USD'000	USD'000

Consolidated statement of profit or loss
Revenue	4	113,423	52,014
Production costs	5	(90,339)	(43,520)
Depletion, depreciation and amortisation	6	(14,376)	(9,986)
Staff costs	8	(13,538)	(9,019)
Other expenses	9	(10,374)	(6,330)
Impairment of assets	10	(11,901)	-
Other income	11	1,718	753
Finance costs	12	(9,061)	(4,304)
Other financial gains	13	12,982	-
Loss before tax		(21,466)	(20,392)

Income tax (expense)/credit	14	(9,567)	5,462
Loss for the year/period		(31,033)	(14,930)

Loss per ordinary share
Basic and diluted (US$)	15	(0.10)	(0.07)

Consolidated statement of comprehensive income
Loss for the year/period		(31,033)	(14,930)

Other comprehensive income
Cash flow hedges on commodity swaps
Items that may be reclassified subsequently to profit or loss:			-
Gain on cash flow hedges	25	51,775
Hedging gain reclassified to profit or loss		(1,088)	-
		50,687	-
Tax relating to components of other comprehensive income	14	(15,207)	-
Other comprehensive income		35,480	-

Total comprehensive income/(loss) for the year/period		4,447	(14,930)

* The 2017 amounts have been restated as a result of initial adoption of IFRS 15. Refer to Note 42 for further information.

All comprehensive income is attributable to the equity holders of the parent.

The accompanying notes are an integral part of the consolidated financial statements.

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

as at December 31, 2018 and December 31, 2017

		2018	2017
	Notes	USD'000	USD'000

ASSETS

Non-current assets
Intangible exploration assets	16	95,607	105,673
Oil and gas properties	17	415,365	62,238
Plant and equipment	18	1,709	648
Derivative financial instruments	35	15,339	-
Restricted cash	23	23,561	10,729
Deferred tax assets	20	21,287	23,821
		572,868	203,109


Current assets
Inventories	21	29,831	9,610
Trade and other receivables	22	32,800	4,719
Derivative financial instruments	35	35,985	-
Restricted cash	23	5,083	-
Cash and cash equivalents	23	52,981	10,450
		156,680	24,779
TOTAL ASSETS		729,548	227,888

EQUITY AND LIABILITIES

Equity
Share capital	24	466,562	364,466
Share based payments reserve	26	22,375	21,855
Hedging reserves	25	35,480	-
Accumulated losses		(309,156)	(278,123)
		215,261	108,198


Non-current liabilities
Provision for asset restoration obligations	27	277,697	84,728
Borrowings	30	49,420	-
Secured convertible bonds	31	-	12,770
Other payables	28	10,351	7,259
Derivative financial liabilities	29	-	3,067
Deferred tax liabilities	20	92,468	200
		429,936	108,024

Current liabilities
Borrowings	30	52,393	829
Trade and other payables	34	30,674	10,837
Provision for taxation		1,284	-
		84,351	11,666
Total liabilities		514,287	119,690
TOTAL EQUITY AND LIABILITIES		729,548	227,888

The accompanying notes are an integral part of the consolidated financial statements.

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

for the year ended December 31, 2018 and nine months ended December 31, 2017

	Share capital	Share based payments reserve	Hedging reserves	Accumulated losses	Total
	USD'000	USD'000	USD'000	USD'000	USD'000

At April 1, 2017	364,466	21,419	-	(263,193)	122,692

Loss for the period, representing total comprehensive loss	-	-	-	(14,930)	(14,930)

Share-based compensation, representing transaction with owners, recognised directly in equity	-	436	-	-	436

At December 31, 2017	364,466	21,855	-	(278,123)	108,198

Loss for the year	-	-	-	(31,033)	(31,033)
Other comprehensive income for the year	-	-	35,480	-	35,480
Total comprehensive income for the year	-	-	35,480	(31,033)	4,447

Share-based compensation, representing transaction with owners, recognised directly in equity	-	520	-	-	520
Shares issued, net of transaction costs (Note 24)	102,096	-	-	-	102,096
Total transactions with owners, recognised directly in equity	102,096	520	-	-	102,616


At December 31, 2018	466,562	22,375	35,480	(309,156)	215,261

The accompanying notes are an integral part of the consolidated financial statements.

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF CASH FLOWS

for the year ended December 31, 2018 and nine months ended December 31, 2017

		Year ended December 31, 2018	Nine months ended December 31, 2017 Restated*
	Notes	USD'000	USD'000

Operating activities
Loss before tax		(21,466)	(20,392)
Adjustments for:
-Interest income	11	(422)	(57)
-Gain on ineffective hedge recycled to profit or loss	13	(637)	-
-Interest expense	12	2,968	563
-Other finance costs	12	6,093	3,684
-Unrealised foreign exchange loss		-	114
-Gain on early repayment of convertible bonds	13	(288)	-
-Change in fair value of contingent payments	13	(12,057)	-
-Depletion, depreciation and amortisation	6	14,376	9,986
-Share based payments	8	520	436
-Impairment of intangible exploration assets	10	11,901	-
-Gain on disposal of asset	11	-	(412)
-Write-back of material and spare parts		-	(29)
Operating cash flows before movements in working capital		988	(6,107)
Changes in working capital:
-(Increase)/Decrease in trade and other receivables		(3,918)	2,320
-Decrease in inventories		15,152	1,220
-Increase /(Decrease) in trade and other payables		14,200	(2,482)
Cash generated from (used in) operations		26,422	(5,049)
Release of restricted cash for Ogan Komering		729	-
Interest paid		(2,263)	-
Tax paid		(7,125)	(1,610)
Net cash generated from (used in) operating activities		17,763	(6,659)

Investing activities
Acquisition of Montara	7	(133,092)	-
Payment for oil and gas properties	17	(6,968)	(1,772)
Payment for plant and equipment	18	(1,437)	(167)
Proceeds from disposal of motor vehicle		-	12
Payment for intangible exploration assets	16	(1,635)	(619)
Proceeds from disposal of intangible exploration assets		-	400
Transfer to debt service reserve account	23	(18,644)	-
Interest received	11	422	57
Net cash used in investing activities		(161,354)	(2,089)

Financing activities
Net proceeds from issuance of shares	24	102,096	-
Pledge deposit for bank guarantee		-	(10,000)
Net draw down from convertible bonds		-	14,550
Net draw down from borrowings	30	118,040	818
Repayment of borrowings	30	(17,761)	(435)
Payment of bond facility and stand-by fees	31	(17,514)	(239)
Net cash generated from financing activities		184,861	4,694

Effect of translation on foreign currency cash and cash balances		1,261	26

Net increase/(decrease) in cash and cash equivalents		42,531	(4,028)
Cash and cash equivalents at beginning of the year		10,450	14,478
Cash and cash equivalents at end of the year	23	52,981	10,450

* The 2017 amounts have been restated as a result of initial adoption of IFRS 15. Refer to Note 42 for further information.

The accompanying notes are an integral part of the consolidated financial statements.

1. CORPORATE INFORMATION

Jadestone Energy Inc. (the "Company" or "Jadestone") is an oil and gas company incorporated in Canada.

The Company's ordinary shares are listed on the TSX Ventures Exchange ("TSX-V") and on August 8, 2018 the Company listed on AIM, a market by the London Stock Exchange. Pursuant to the listing on AIM, the Group issued 239,711,474 new ordinary shares raising gross proceeds of approximately £83.9 million at a price of 35 pence per share. The Company trades on both markets under the symbol "JSE".

The financial statements are expressed in United States Dollars ("US$" or "USD").

The Company and its subsidiaries (the "Group") are engaged in production, development, exploration and appraisal activities in Australia, Vietnam and the Philippines. The Company's current producing assets are in the Carnarvon and Vulcan basins, offshore Western Australia.

On August 2, 2018, the Group entered into a reserve based lending agreement to borrow US$120.0 million, repayable quarterly over the period to and including March 31, 2021. The Group drew down the full facility of US$120.0 million on September 28, 2018, as part of the funding for the acquisition of the Montara assets. The first principal repayment of US$16.9 million was made on December 31, 2018.

As part of the financing arrangements for Montara Assets, the Group entered into a hedging facility to hedge approximately 50% of its planned production over the period October 1, 2018 through September 30, 2020. The weighted average swap price under the capped swap is US$71.72/bbl referenced to Dated Brent. Call options have been purchased for approximately two thirds of the hedged barrels at Dated Brent strike prices of US$80/bbl for the nine months to September 30, 2019 and US$85/bbl for the twelve months to September 30, 2020.

On September 28, 2018, the Group acquired the Montara Assets, located in shallow water offshore Australia, from PTTEP Australasia (Ashmore Cartier) Pty Ltd ("PTTEP Australia"). Following completion, the Group obtained control and 100% beneficial ownership. PTTEP Australia was contracted to continue to operate the field under an operator and transitional service agreement until regulatory approvals are finalised. Management anticipate that this will occur in the second quarter of 2019. The Group acquired the Montara Assets on September 28, 2018 and paid a cash consideration of US$133.1 million. The balance was subsequently adjusted for deferred contingent consideration, prepaid assets for future cash calls and working capital adjustments. Note 7 gives more information on the Montara Assets acquisition.

During 2017 the Company changed its financial reporting year end from March to December. The transition period is the nine months to December 31, 2017 and the current reporting period is the full calendar year from January 1 to December 31, 2018.

The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower, Singapore 079909. The registered office of the Company is 10th Floor, 595 Howe Street, Vancouver, British Columbia V6C 2T5, Canada.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PREPARATION

The financial statements have been prepared on a going concern basis and in accordance with the historical cost convention basis, except as disclosed in the accounting policies below, and are drawn up in accordance with the provisions of International Financial Reporting Standards ("IFRS") as issued by International Accounting Standards Board ("IASB").

Historical cost is generally based on the fair value of the consideration given in exchange for goods and services.

Fair value is 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, regardless of whether that price is directly observable or estimated using another valuation technique. In estimating the fair value of an asset or a liability, the Group takes into account the characteristics of the asset or liability which market participants would take into account when pricing the asset or liability at the measurement date. Fair value for measurement and/or disclosure purposes in these consolidated financial statements is determined on such a basis, except for share-based payment transactions that are within the scope of IFRS 2 Share-based Payment, leasing transactions that are within the scope of IAS 17 Leases, and measurements that have some similarities to fair value but are not fair value, such as net realisable value in IAS 2 Inventories, or value in use in IAS 36 Impairment of Assets

In addition, for financial reporting purposes, fair value adjustments are categorised into level 1, 2 or 3 based on the degree to which the inputs to the fair value adjustments are observable and the significance of the inputs to the fair value measurement in its entirety, which are described as follows:

- Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Group can access at the measurement date;

- Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly; and

- Level 3 inputs are unobservable inputs for the asset or liability.

The comparative figures are based on the nine-month period ending December 31, 2017.

Adoption of new and revised standards

New and amended IFRS standards that are effective for the current year

The Group has applied the following standards and amendments for the first time with effect from January 1, 2018.

- IFRS 9 Financial Instruments; and

- IFRS 15 Revenue from Contracts with Customers.

IFRS 9 - Financial Instruments

In the current year, the Group has applied IFRS 9 Financial Instruments (as revised in July 2014) using the fully retrospective approach and the related consequential amendments to other IFRS standards that are effective for an annual period that begins on or after January 1, 2018.

Additionally, the Group adopted consequential amendments to IFRS 7 Financial Instruments: Disclosures that were applied to the disclosures for 2018 and to the comparative period.

IFRS 9 introduced new requirements for:

1) The classification and measurement of financial assets and financial liabilities;

2) Impairment of financial assets; and

3) General hedge accounting.

Details of these new requirements as well as their impact on the Group's consolidated financial statements are described below (refer overleaf):

(a) Classification and measurement of financial assets

The date of initial application (i.e. the date on which the Group has assessed its existing financial assets and financial liabilities in terms of the requirements of IFRS 9) is January 1, 2018. Accordingly, the Group has applied the requirements of IFRS 9 to instruments that continue to be recognised as at January 1, 2018 and has not applied the requirements to instruments that have already been derecognised as at January 1, 2018.

The directors of the Company reviewed and assessed the Group's existing financial assets as at January 1, 2018 and based on the facts and circumstances that existed at that date they have concluded that the initial application of IFRS 9 did not have a significant impact on its statement of financial position or equity on applying the classification and measurement requirements. Trade receivables are held to collect contractual cash flows and are expected to give rise to cash flows representing solely payments of principal and interest. Thus, the Group expects that these will continue to be measured at amortised cost under IFRS 9.

(b) Impairment of financial assets

IFRS 9 requires the Group to record expected credit losses on all of its trade and other receivables, either on a 12-month or lifetime basis. There was no significant impact of impairment due to the high quality of the financial assets and trade and other receivables had been settled subsequent to the financial year end. All of the current bank balances have been assessed with a low credit risk at the reporting date as they are held with highly reputable banking institutions.

The classification and measurement of financial liabilities under IFRS 9 determines how the fair value of a financial liability is designated as fair value through the profit and loss ("FVTPL") attributable to changes in the credit risk of the issuer.

Specifically, IFRS 9 requires that the changes in the fair value of the financial liability that is attributable to changes in the credit risk of that liability be presented in other comprehensive income, unless the recognition of the effects of changes in the liability's credit risk in other comprehensive income would create or enlarge an accounting mismatch in profit or loss. Changes in fair value attributable to a financial liability's credit risk are not subsequently reclassified to profit or loss, but are instead transferred to retained earnings when the financial liability is derecognised. Previously, under IAS 39, the entire amount of the change in the fair value of the financial liability designated as at FVTPL was presented in profit or loss.

The Directors have assessed the financial liabilities that existed at January 1, 2018 and based on the facts and circumstances that existed at that date there is not a significant impact on the consolidated statement of financial position or consolidated statement of changes in equity on applying the classification and measurement requirements.

(d) General hedge accounting

The new general hedge accounting requirements retain the three types of hedge accounting. However, greater flexibility has been introduced to the types of transactions eligible for hedge accounting, specifically broadening the types of instruments that qualify for hedging instruments and the types of risk components of non-financial items that are eligible for hedge accounting. In addition, the effectiveness test has been replaced with the principle of an "economic relationship". Retrospective assessment of hedge effectiveness is also no longer required. Enhanced disclosure requirements about the Group's risk management activities have also been introduced.

(e) Disclosures in relation to the initial application of IFRS 9

There were no financial assets or financial liabilities which the Group had previously designated as at FVTPL under IAS 39 that were subject to reclassification or which the Group has elected to reclassify upon the application of IFRS 9. There were no financial assets or financial liabilities which the Group has elected to designate as at FVTPL at the date of initial application of IFRS 9.

The Group has assessed that there is no material impact on the financial statements of the Group in the period of their initial adoption of IFRS 9. Enhanced disclosures surrounding IFRS 9 have been adopted throughout the financial statements.

IFRS 15 - Revenue from contracts with customers

In the current year, the Group has applied IFRS 15 Revenue from Contracts with Customers (as amended in April 2016) which is effective for an annual period that begins on or after January 1, 2018. IFRS 15 introduced a 5‑step approach to revenue recognition.

1) Identify the customer. A sales contract must meet the following criteria: approved by the parties, transfer rights for the hydrocarbons can be identified, payments terms are defined, commercial substance and consideration is likely to be collected;

2) Identify the performance obligations in contract. At the inception of the contract, the Company should assess the hydrocarbons that have been promised to the customer and identify a performance obligation;

3) Determine the transaction price. The transaction price is the amount to which an entity expects to be entitled in exchange for the transfer of goods and services;

4) Allocate the transaction price to the performance obligations in the contract. The transaction price will be allocated to the performance obligations; and

5) Recognise revenue when (or as) the entity satisfies a performance obligation. Revenue is recognised when control is passed.

The Group has applied IFRS 15 in accordance with the fully retrospective transitional approach without using the practical expedients for completed contracts in IFRS 15:C5(a), and (b), or for modified contracts in IFRS 15:C5(c) but using the expedient in IFRS 15:C5(d) allowing both non-disclosure of the amount of the transaction price allocated to the remaining performance obligations, and an explanation of when it expects to recognise that amount as revenue for all reporting periods presented before the date of initial application, i.e. January 1, 2018. IFRS 15 uses the terms "contract asset" and "contract liability" to describe what might more commonly be known as "accrued revenue" and "deferred revenue"; however, the standard does not prohibit an entity from using alternative descriptions in the statement of financial position. The Group has decided not to adopt the terminology used in IFRS 15 but to continue with previous terminology for consistency.

The Group generates revenue through the sale of oil and gas. The impact of IFRS 15 on contracts with customers, in which the sale of oil and gas is the sole performance obligation, did not have an impact on the Group's profit or loss for such transactions. All revenue are recognised at a point in time.

The Group has assessed that the only impact to the financial statements of the Group in the period of their initial adoption of IFRS 15 would be to the presentation of "Revenue" (refer overleaf):

	As previously reported under IAS 18	Initial application of IFRS 15	As adjusted under IFRS 15 (restated)
	USD'000	USD'000	USD'000

Gross revenue	116,972	(116,972)	-
Royalties	(3,549)	3,549	-
Revenue	-	113,423	113,423

Enhanced disclosures surrounding IFRS 15 have been adopted throughout the financial statements.

New and revised IFRSs in issue but not yet effective

The Group has not applied the following new and revised IFRSs that are relevant to the Group, and were issued, but not effective:

- IFRS 16 Leases; and

- Amendments to IFRS 3 Business Combinations

Effective for annual periods beginning on or after January 1, 2019 and generally require prospective application.

The Group is currently performing an assessment of the impact of these standards and does not anticipate a material impact on the financial statements of the Group in future periods with the exception of the items listed below:

IFRS 16 Leases

General impact of application of IFRS 16 Leases

IFRS 16 provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessors and lessees. IFRS 16 will supersede the current lease guidance including IAS 17 Leases and the related Interpretations when it becomes effective for accounting periods beginning on or after January 1, 2019. The date of initial application of IFRS 16 for the Group will be January 1, 2019.

The Group has adopted IFRS 16 on January 1, 2019 using the modified retrospective approach to transition permitted by the standard in which the cumulative effect of initially applying the standard is recognised in the opening retained earnings at the date of application.

Impact of the new definition of a lease

The change in definition of a lease mainly relates to the concept of control. IFRS 16 distinguishes between leases and service contracts on the basis of whether the use of an identified asset is controlled by the customer. Control is considered to exist if the customer has:

- The right to obtain substantially all of the economic benefits from the use of an identified asset; and

- The right to direct the use of that asset.

The Group will apply the definition of a lease and related guidance set out in IFRS 16 to all lease contracts entered into or modified on or after January 1, 2019 (whether it is a lessor or a lessee in the lease contract). In preparation for the first time application of IFRS 16, the Group has carried out an implementation project. The project has shown that the new definition in IFRS 16 will not change significantly the scope of contracts that meet the definition of a lease for the Group.

IFRS 16 will change how the Group accounts for leases previously classified as operating leases under IAS 17, which were off balance sheet.

On initial application of IFRS 16, for all leases (except as noted below), the Group will:

- Recognise right of use assets and lease liabilities in the consolidated statement of financial position, initially measured at the present value of the future lease payments;

- Recognise depreciation of right of use assets and interest on lease liabilities in the consolidated statement of profit or loss; and

- Separate the total amount of cash paid into a principal portion (presented within financing activities) and interest (presented within operating activities) in the consolidated cash flow statement.

Lease incentives (e.g. rent free period) will be recognised as part of the measurement of the right of use assets and lease liabilities whereas under IAS 17 they resulted in the recognition of a lease liability incentive, amortised as a reduction of rental expenses on a straight line basis. Under IFRS 16, right of use assets will be tested for impairment in accordance with IAS 36 impairment of assets.

This will replace the previous requirement to recognise a provision for onerous lease contracts.

For short term leases (lease term of 12 months or less) and leases of low value assets (such as personal computers and office furniture), the Group will opt to recognise a lease expense on a straight line basis as permitted by IFRS 16.

As at 31 December 2018, the Group has non-cancellable operating lease commitments of US$44.4 million (December 31, 2017: US$43.5 million).

Hence, the Group is expected to recognise a right-of-use asset and a corresponding liability in respect of all these leases unless they qualify for low value or short-term leases upon the application of IFRS 16. The new requirement to recognise a right-of-use asset and a related lease liability is expected to have an impact on the amount recognised in the Group's consolidated financial statements and the Group is currently assessing the potential impact including the determination of appropriate incremental borrowing rate or the rate implicit in the lease to be used.

On a preliminary basis, the Group anticipates that upon adoption on January 1, 2019 an incremental right-of-use asset in the range of US$35.0 million to US$40.0 million.

The financial statement impact of IFRS 16 is subject to certain management judgments and estimates. Most notably, extension and termination provisions are included in certain lease contracts. In determining the lease term to be recognised, Management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not to exercise a termination option.

Amendments to IFRS 3 Business Combinations

The definition of a business was amended under IFRS 3 on October 22, 2018 clarifying that to be considered a business rather than an asset sale or purchase, an acquisition would have to include an input and a substantive process that together significantly contribute to the ability to create outputs. The definition of the term "outputs" is narrowed to focus on goods and services provided to customers, generating investment income and other income. The amended definition will be applied to reporting period's beginning on or after January 1, 2020 prospectively.

BASIS OF CONSOLIDATION

The consolidated financial statements incorporate the financial statements of the Company and enterprises controlled by the Company and its subsidiaries. Control is achieved where the Company:

- Has power over the investee;

- Is exposed, or has rights, to variable returns from its involvement with the investee; and

- Has the ability to use its power to affect its returns.

The Company reassesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control listed above.

Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary. Specifically, income and expenses of a subsidiary acquired or disposed of during the year are included in the consolidated statement of profit or loss and other comprehensive income from the date the Company gains control until the date when the Company ceases to control the subsidiary.

Profit or loss and each component of other comprehensive income are attributed to the owners of the Company. Total comprehensive income of subsidiaries is attributed to the owners of the Company and to the non-controlling interests even if this results in the non-controlling interests having a deficit balance.

When necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies into line with the Group's accounting policies.

All intragroup assets and liabilities, equity, income, expenses and cash flows relating to transactions between members of the Group are eliminated in full on consolidation.

BUSINESS COMBINATIONS

Acquisitions of businesses (including joint operations which are assessed to be businesses) are accounted for using the acquisition method. The consideration for each acquisition is measured as the aggregate of the acquisition date fair values of assets given, liabilities incurred by the Company to the former owners of the acquiree, and equity interests issued by the Company in exchange for control of the acquiree. Acquisition-related costs are recognised in profit or loss as incurred.

The definition of a business in accordance with IFRS 3 is an integrated set of activities and assets that is capable of being conducted and managed for the purpose of providing good or services to customers, generating investment income (such as dividends or interest) or generating other income from ordinary activities. At the acquisition date, the identifiable assets acquired and the liabilities assumed are recognised at their fair value, except that:

- Deferred tax assets or liabilities and liabilities or assets related to employee benefit arrangements are recognised and measured in accordance with IAS 12 Income Taxes and IAS 19 Employee Benefits respectively;

- Liabilities or equity instruments related to share-based payment transactions of the acquiree or the replacement of an acquiree's share-based payment awards transactions with share-based payment awards transactions of the acquirer, in accordance with the method in IFRS 2 Share-based Payment at the acquisition date.

- Assets (or disposal groups) that are classified as held for sale in accordance with IFRS 5 Non-current Assets Held for Sale and Discontinued Operations.

Where applicable, the consideration for the acquisition includes any asset or liability resulting from a contingent consideration arrangement, measured at its acquisition-date fair value. Subsequent changes in such fair values are adjusted against the cost of acquisition where they qualify as measurement period adjustments (see above). The subsequent accounting for changes in the fair value of the contingent consideration that do not qualify as measurement period adjustments depends on how the contingent consideration is classified.

Contingent consideration that is classified as equity is not re-measured at subsequent reporting dates and its subsequent settlement is accounted for within equity. Contingent consideration that is classified as an asset or a liability is re-measured at subsequent reporting dates with the corresponding gain or loss being recognised in profit or loss.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Group reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the measurement period (see below), or additional assets or liabilities are recognised, to reflect new information obtained about facts and circumstances that existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date.

The measurement period is the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as of the acquisition date and is subject to a maximum of one year from acquisition date.

Where an interest in a production sharing contract ("PSC") is acquired by way of a corporate acquisition, the interest in the PSC is treated as an asset purchase unless the acquisition of the corporate vehicle meets the requirements to be treated as a business combination and definition of a business.

FOREIGN CURRENCY TRANSACTIONS

The Group's consolidated financial statements are presented in USD, which is the parent's functional currency and presentation currency. The functional currencies of subsidiaries are determined based on the economic environment in which they operate.

In preparing the financial statements of each individual Group entity, transactions in currencies other than the entity's functional currency are recorded at the rates of exchange prevailing on the dates of the transactions. At the end of each reporting period, monetary items denominated in foreign currencies are retranslated at the rates prevailing at the end of the reporting period. Non-monetary items carried at fair value that are denominated in foreign currencies are retranslated at the rates prevailing on the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated.

Exchange differences arising on the settlement of monetary items, and on retranslation of monetary items are included in profit or loss for the period.

Exchange differences arising on the retranslation of non-monetary items carried at fair value are included in profit or loss for the period except for differences arising on the retranslation of non-monetary items in respect of which gains or losses are recognised in other comprehensive income. For such non-monetary items, any exchange component of that gain or loss is also recognised in other comprehensive income.

JOINT OPERATIONS

A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control.

When a Group's entity undertakes its activities under joint operations, the Group as a joint operator recognises in relation to its interest in a joint operation:

- Its assets, including its share of any assets held jointly;

- Its liabilities, including its share of any liabilities incurred jointly;

- Its revenue from the sale of its share of the output arising from the joint operation; and

- Its expenses, including its share of any expenses incurred jointly.

The Group accounts for the assets, liabilities, revenue and expenses relating to its interest in a joint operation in accordance with the IFRSs applicable to the particular assets, liabilities, revenues and expenses.

When a Group entity transacts with a joint operation in which a Group entity is a joint operator (such as a sale or contribution of assets), the Group is considered to be conducting the transaction with the other parties to the joint operation, and gains and losses resulting from the transactions are recognised in the Group's consolidated financial statements only to the extent of other parties' interests in the joint operation.

When a Group entity transacts with a joint operation in which a Group entity is a joint operator (such as a purchase of assets), the Group does not recognise its share of the gains and losses until it resells those assets to a third party.

Changes to the Group's interest in PSCs usually require the approval of the appropriate regulatory authority. A change in interest is recognised when:

- Approval is considered highly likely; and

- All affected parties are effectively operating under the revised arrangement.

Where this is not the case, no change in interest is recognised and any funds received or paid are included in the statement of financial position as contractual deposits.

PRE-LICENCE AWARD COSTS

Costs incurred prior to the effective award of oil and gas licences, concessions and other exploration rights are expensed in profit and loss.

EXPLORATION AND EVALUATION COSTS

The costs of exploring for and evaluating oil and gas properties, including the costs of acquiring rights to explore, geological and geophysical studies, exploratory drilling and directly related overheads such as directly attributable employee remuneration, materials, fuel used, rig costs and payments made to contractors are capitalised and classified as intangible exploration assets ("E&E assets").

If no potentially commercial hydrocarbons are discovered, the E&E assets are written off through profit or loss as a dry hole. If extractable hydrocarbons are found and, subject to further appraisal activity (e.g. the drilling of additional wells), it is probable that they can be commercially developed, the costs continue to be carried as intangible exploration costs while sufficient/ continued progress is made in assessing the commerciality of the hydrocarbons.

Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalised as E&E assets.

All such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at the end of each reporting period. This is to confirm the continued intent to develop or otherwise extract value from the discovery. When such intent no longer exists or if there is a change in circumstances signifying an adverse change in initial judgment, the costs are written off.

When commercial reserves of hydrocarbons are determined and development is approved by management, the relevant expenditure is transferred to oil and gas properties. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proved or probable reserves are determined to exist. The determination of proved or probable reserves is dependent on reserve evaluations which are subject to significant judgments and estimates.

Costs related to geological and geophysical studies that relate to blocks that have not yet been acquired, and costs related to blocks for which no commercially viable hydrocarbons are expected, are taken direct to the profit or loss and have been disclosed as expensed exploration costs.

FARM-OUTS IN THE EXPLORATION AND EVALUATION PHASE

The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements, but re-designates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.

OIL AND GAS PROPERTIES

Producing assets

The Group recognises oil and gas properties at cost less accumulated depletion, depreciation and impairment losses. Directly attributable costs incurred for the drilling of development wells and for the construction of production facilities are capitalised together with the discounted value of estimated future costs of decommissioning obligations. Workover expenses are recognised in profit or loss in the period in which they are incurred unless it generates additional reserves or prolongs the economic life of the well, in which case it is capitalised. When components of oil and gas properties are replaced, disposed of, or no longer in use, they are derecognised.

Depletion and amortisation expense

Depletion of oil and gas properties is calculated using the units of production method for an asset or group of assets from the date in which they are available for use. The costs of those assets are depleted based on proved and probable reserves.

Costs subject to depletion include expenditures to date, together with approved estimated future expenditure to be incurred in developing proved and probable reserves. Costs of major development projects are excluded from the costs subject to depletion until they are available for use.

The impact of changes in estimated reserves is dealt with prospectively by depreciating the remaining carrying value of the asset over the expected future production. If reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the property's carrying value.

Asset restoration obligations

The Group estimates the future removal and restoration costs of oil production facilities, wells, pipelines and related assets at the time of installation or acquisition of the assets and based on prevailing legal requirements and industry practice. In most instances, the removal of these assets will occur many years in the future. The estimates of future removal costs are made considering relevant legislation and industry practice and require management to make judgments regarding the removal date, the extent of restoration activities required and future removal technologies.

Site restoration costs are capitalised within the cost of the associated assets and the provision is stated in the statement of financial position at total estimated present value. These costs are based on judgements and assumptions regarding removal dates, technologies, and industry practice. This estimate is evaluated on a periodic basis and any adjustment to the estimate is applied prospectively. Changes in the estimated liability resulting from revisions to estimated timing, amount of cash flows, or changes in the discount rate are recognised as a change in the asset restoration liability and related capitalised asset restoration cost.

The change in net present value of the future obligations due to passage of time is expensed as accretion expense within financing charges. Actual restoration obligations settled during the period reduce the decommissioning liability.

The asset restoration costs are depleted using the units of production method (see above accounting policy).

BORROWING COSTS

Finance costs of borrowing are allocated to periods over the term of the related debt at a constant rate on the carrying amount. Debt is shown on the consolidated statement of financial position, net of arrangement fees and issue costs, and amortised through to the income statement and statement of other comprehensive income as finance costs over the term of the debt.

Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

All other borrowing costs are recognised in the profit and loss in the period in which they are incurred.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation. All other borrowing costs are recognised in profit or loss in the period in which they are incurred and this includes borrowing costs in relation to exploration activities which are capitalised in intangible exploration assets as management is of the view that these do not meet the definition of a qualifying asset.

PLANT AND EQUIPMENT

Plant and equipment is stated at cost less accumulated depreciation and any recognised impairment loss.

Depreciation is charged so as to write off the cost of assets evenly over their estimated useful lives, on the following

- Computer equipment: 3 years;

- Fixtures and equipment: 3 years; and

- Motor vehicles: 3 years.

The estimated useful lives, residual values and depreciation method are reviewed at each year end, with the effect of any changes in estimate accounted for on a prospective basis.

An item of plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of asset. Any gain or loss arising on the disposal or retirement of an item of plant and equipment is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in profit or loss.

IMPAIRMENT OF TANGIBLE ASSETS AND INTANGIBLE ASSETS

At the end of each reporting period, the Group reviews the carrying amounts of its assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs. When a reasonable and consistent basis of allocation can be identified, corporate assets are also allocated to individual cash-generating units, or otherwise they are allocated to the smallest group of cash-generating units for which a reasonable and consistent allocation basis can be identified.

Intangible assets with indefinite useful lives and intangible assets not yet available for use, are tested for impairment annually, and whenever there is an indication that the asset may be impaired.

Recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which estimates of future cash flows have not been adjusted.

If the recoverable amount of an asset (or cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (or cash-generating unit) is reduced to its recoverable amount. An impairment loss is recognised immediately in profit or loss.

Where an impairment loss subsequently reverses, the carrying amount of the asset (cash-generating unit) is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (cash-generating unit) in prior years. A reversal of an impairment loss is recognised immediately in profit or loss.

INVENTORY

Inventories are valued at the lower of cost and net realisable value. Cost is determined as follows:

- Petroleum products, comprising primarily of extracted crude oil stored in tanks, pipeline systems and aboard vessels, and natural gas, are valued using weighted average costing inclusive of depletion expense; and

- Materials, which include drilling and maintenance stocks, are valued at the weighted average cost of acquisition.

Net realisable value represents the estimated selling price less applicable selling expenses. If the carrying value exceeds net realisable value, a write-down is recognised. The write-down may be reversed in a subsequent period if the inventory is still on hand but the circumstances which caused the write-down no longer exist.

FINANCIAL INSTRUMENTS

Financial assets and financial liabilities are recognised in the Group's consolidated statement of financial position when the Group becomes a party to the contractual provisions of the instrument.

Financial assets and financial liabilities are initially measured at fair value. Transaction costs are directly attributable to the acquisition or issue of the financial assets and financial liabilities (other than financial assets and financial liabilities at fair value through the profit and loss) are added to or deducted from the fair value of the financial assets or financial liabilities, as appropriate, on initial recognition.

Transaction costs directly attributable to the acquisition of financial assets or financial liabilities at fair value through profit and loss are recognised immediately in profit or loss.

Financial assets

All financial assets are recognised and derecognised on a trade date basis where the purchases or sales of financial assets is under a contract whose terms require delivery of assets within the time frame established by the market concerned.

All recognised financial assets are measured subsequently in their entirely at either amortised cost or fair value, depending on the classification of the financial assets.

Classification of financial assets

Debt instruments that meet the following conditions are measured subsequently at amortised cost:

- The financial asset is held within a business model whose objective is to hold financial assets in order to collect contractual cash flows; and

- The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

Amortised cost and effective interest method

The effective interest method is a method of calculating the amortised cost of a debt instrument and of allocating interest income over the relevant period.

For financial assets other than purchased or originated credit impaired financial assets (i.e. assets that are credit impaired on initial recognition), the effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) excluding expected credit losses, through the expected life of the debt instrument, or, where appropriate, a shorter period, to the gross carrying amount of the debt instrument on initial recognition. For purchased or originated credit impaired financial assets, a credit adjusted effective interest rate is calculated by discounting the estimated future cash flows, including expected credit losses, to the amortised cost of the debt instrument on initial recognition.

The amortised cost of a financial asset is the amount at which the financial asset is measured at initial recognition minus the principal repayments, plus the cumulative amortisation using the effective interest method of any difference between that initial amount and the maturity amount, adjusted for any loss allowance. The gross carrying amount of a financial asset is the amortised cost of a financial asset before adjusting for any loss allowance.

Interest income is recognised using the effective interest method for debt instruments measured subsequently at amortised cost and at fair value through other comprehensive income. For financial assets other than purchased or originated credit impaired financial assets, interest income is calculated by applying the effective interest rate to the gross carrying amount of a financial asset, except for financial assets that have subsequently become credit impaired. For financial assets that have subsequently become credit impaired, interest income is recognised by applying the effective interest rate to the amortised cost of the financial asset. If, in subsequent reporting periods, the credit risk on the credit impaired financial instrument improves so that the financial asset is no longer credit impaired, interest income is recognised by applying the effective interest rate to the gross carrying amount of the financial asset.

Interest income is recognised in profit and loss and is included in "other income" (Note 11).

Foreign Exchange gains and losses

The carrying amount of financial assets that are denominated in a foreign currency is determined in that foreign currency and translated at the spot rate at the end of each reporting period.

All financial assets measured at amortised cost that are not part of a designated hedging relationship, exchange differences are recognised in profit or loss in either other income (Note 11) or other finance cost (Note 12) line item.

Impairment of financial assets

The Group financial assets that are subject to the expected credit loss model are trade and other receivables. While cash and bank balances are also subject to the impairment requirements of IFRS 9 Financial Instruments, the expected credit loss allowances are not expected to be significant.

The Group's trade and other receivables are primarily with (i) counterparties to oil and gas sales and (ii) governments for recoverable amounts of value added taxes, and with (iii) joint venture partners in the oil and gas industry.

The concentration of credit risk relates to the main counterparty to oil and gas sales in Australia, where the sole customer has an A1 credit rating (Moody's). All trade receivables are initially settled 30 days after issuance date, followed by a final reconciliation payment after a further 30 days, mitigating largely any credit risk.

The Group recognises lifetime expected credit loss ("ECL") for trade receivables. The expected credit losses on these financial assets are estimated based on days past due and applies expected non-recoveries for each group of receivables.

The Group measures the loss allowance for other receivables at an amount equal to 12 months ECL as there is no significant increase in credit risk since initial recognition.

Measurement and recognition of expected credit losses

The measurement of ECL is a function of the probability of default, loss given default (i.e. the magnitude of the loss if there is a default) and the exposure at default. The assessment of the probability of default and loss given default is based on historical data adjusted by forward looking information as described above.

As for the exposure at default, for financial assets, this is represented by the assets' gross carrying amount at the reporting date together with any additional amounts expected to be drawn down in the future by default date determined based on historical trend, the Group's understanding of the specific future financing needs of the debtors, and other relevant forward looking information.

For financial assets, the expected credit loss is estimated as the difference between all contractual cash flows that are due to the Group in accordance with the contract and all the cash flows that the Group expects to receive, discounted at the original effective interest rate.

If the Group has measured the loss allowance for a financial instrument at an amount equal to lifetime ECL in the previous reporting period, but determines at the current reporting date that the conditions for lifetime ECL are no longer met, the Group measures the loss allowance at an amount equal to 12 month ECL at the current reporting date, except for assets for which simplified approach was used.

De-recognition of financial assets

The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. If the Group neither transfers nor retains substantially all the risks and rewards of ownership, and continues to control the transferred asset, the Group recognises its retained interest in the asset and an associated liability for amounts it may have to pay. If the Group retains substantially all of the risks and rewards of ownership of a transferred financial asset, the Group continues to recognise the financial asset and also recognise the financial asset and also recognises a collateralised borrowing for the proceeds received.

On de-recognition of a financial asset measured at amortised cost, the difference between the asset's carrying amount and the sum of the consideration received and receivables is recognised in the profit or loss.

Financial liabilities

All financial liabilities are measured subsequently at amortised cost using the effective interest method or at FVTPL.

However, financial liabilities that arise when a transfer of a financial asset does not qualify for derecognition or when the continuing involvement approach applies are measured in accordance with the specific accounting policies set out below.

Financial liabilities at FVTPL

Financial liabilities are classified as at FVTPL when the financial liability is (i) contingent consideration of an acquirer in a business combination, (ii) held for trading or (iii) it is designated as at FVTPL.

A financial liability other than a contingent consideration of an acquirer in a business combination may be designated as at FVTPL upon initial recognition if:

- such designation eliminates or significantly reduces a measurement or recognition inconsistency that would otherwise arise; or

- the financial liability forms part of a group of financial assets or financial liabilities or both, which is managed and its performance is evaluated on a fair value basis, in accordance with the Group's documented risk management or investment strategy, and information about the grouping is provided internally on that basis; or

- it forms part of a contract containing one or more embedded derivatives, and IFRS 9 permits the entire combined contract to be designated as at FVTPL.

Financial liabilities at FVTPL are measured at fair value, with any gains or losses arising on changes in fair value recognised in profit or loss to the extent that they are not part of a designated hedging relationship (see hedge accounting policy). The net gain or loss recognised in profit or loss incorporates any interest paid on the financial liability and is included in the "Other financial gains" line item (note 13) in profit or loss.

Financial liabilities measured subsequently at amortised cost

Other financial liabilities are measured subsequently at amortised cost using the effective interest method.

The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial liability, or (where appropriate) a shorter period, to the amortised cost of a financial liability.

Equity instruments

Equity instruments issued by the Group are recorded at the fair value of the proceeds received, net of direct issue costs, except where the accounting treatment is defined by a separate accounting standard, as in the case of share-based payments.

Convertible bonds

Convertible bonds are regarded as compound instruments, consisting of a debt host component and an equity conversion option upon maturity, which are classified separately as financial liabilities at amortised cost and financial liabilities at FVTPL respectively, in accordance with the substance of the contractual arrangement on initial recognition. Conversion option that will be settled by the exchange of a fixed amount of cash or another financial asset for a number of the Company's own equity instruments, is classified as a derivative financial liability.

On initial recognition, the fair value of the liability host component is determined using the prevailing market interest rate of similar non-convertible debts. The difference between the gross proceeds of the issue of the convertible loans and the fair value assigned to the liability host component, representing the conversion option for the holder to convert the loans into equity, is recognised separately as a derivative financial liability.

In subsequent periods, the derivative financial liability which represents the equity conversion option is measured at its fair value and with fair value changes recognised in the profit or loss. The liability host component is carried at amortised cost using the effective interest method until the liability is extinguished on conversion or redemption.

Upon conversion, the derivative financial liability and the carrying amount of the liability host component will be transferred to share capital.

Transaction costs

Transaction costs that relate to the issue of the convertible bonds are allocated to the liability host and equity or derivative liability components in proportion to the allocation of the gross proceeds. Transaction costs relating to the equity components are charged directly to equity. Transaction costs relating to the liability components are included in the carrying amount of the liability and amortised over the period of the convertible loans using the effective interest method.

Transaction costs incurred prior to any issue of the convertible bonds are capitalised as prepayments.

De-recognition of financial liabilities

The Group derecognises financial liabilities when, and only when, the Group's obligations are discharged, cancelled or they expire. The difference between the carrying amount of the financial liability derecognised, and the consideration paid and payable is recognised in profit or loss.

Derivative financial instruments

The Group enters into derivative financial instruments to manage its exposure to commodity price risks.

Derivative financial instrument is initially recognised at fair value on the date the contract is entered into, and is subsequently remeasured to fair value as at each reporting date. The resulting gain or loss is recognised in profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship.

Hedge accounting

All hedges are classified as cash flow hedges, which hedges exposure to variability in cash flows that is either attributable to a particular risk associated with a recognised asset or liability, or a component of a recognised asset or liability, or a highly probable forecasted transaction.

At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk, which is when the hedging relationships meet all of the following hedge effectiveness requirements:

- there is an economic relationship between the hedged item and the hedging instrument;

- the effect of credit risk does not dominate the value changes that result from that economic relationship; and

- the hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item.

If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again.

The Group designates the full change in the fair value of a forward contract (i.e. including the forward elements) as the hedging instrument for all of its hedging relationships involving forward contracts. The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the cost of hedging reserve. If the hedged item is transaction‑related, the time value is reclassified to profit or loss when the hedged item affects profit or loss. If the hedged item is time‑period related, then the amount accumulated in the cost of hedging reserve is reclassified to profit or loss on a rational basis - the Group applies straight‑line amortisation. Those reclassified amounts are recognised in profit or loss in the same line as the hedged item. If the hedged item is a non‑financial item, then the amount accumulated in the cost of hedging reserve is removed directly from equity and included in the initial carrying amount of the recognised non‑financial item. Furthermore, if the Group expects that some or all of the loss accumulated in cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.

Note 35 sets out details of the fair values of the derivative instruments used for hedging purposes.

Movements in the hedging reserve in equity are detailed in Note 25.

Cash flow hedges

The effective portion of changes in the fair value of derivatives and other qualifying hedging instruments that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated under the heading of cash flow hedging reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss, and is included in other financial gains (Note 13).

Amounts previously recognised in other comprehensive income and accumulated in equity are reclassified to profit or loss in the periods when the hedged item affects profit or loss, in the same line as the recognised hedged item. However, when the hedged forecast transaction results in the recognition of a non‑financial asset or a non‑financial liability, the gains and losses previously recognised in other comprehensive income and accumulated in equity are removed from equity and included in the initial measurement of the cost of the non‑financial asset or non‑financial liability. This transfer does not affect other comprehensive income. Furthermore, if the Group expects that some or all of the loss accumulated in the cash flow hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.

The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in cash flow hedge reserve is reclassified immediately to profit or loss.

EQUITY AND LISTING COSTS

Ordinary shares are classified as equity and recorded at the value of consideration received. The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds.

Incremental and direct attributable costs that specifically relate to the admission of the Company into AIM and the issuance of new shares are recorded in profit or loss. Remaining costs that relate jointly to both the AIM admission and the new shares issuance are allocated on a proportionate basis in accordance with IAS 32.

FAIR VALUE ESTIMATION OF FINANCIAL ASSETS AND LIABILITIES

The fair value of current financial assets and liabilities carried at amortised cost, approximate their carrying amounts, as the effect of discounting is immaterial.

SHARE-BASED PAYMENTS

Share based incentive arrangements are provided to employees which allow them to acquire shares of the Company.

The fair value of options granted is recognised as an employee expense with a corresponding increase in equity.

Share options are valued at the date of grant using the Black-Scholes pricing model, and are charged to operating costs over the vesting period of the award. The charge is modified to take account of options granted to employees who leave the Group during the vesting period and forfeit their rights to the share options, and in the case of non-market related performance conditions, where it becomes unlikely they will vest. At the end of the reporting period, the Group revises its estimates of the number of equity instruments expected to vest. The impact of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to the share options reserve.

Equity-settled share-based payment transactions with parties other than employees are measured at the fair value of goods or services received, except where that fair value cannot be estimated reliably, in which case they are measured at the fair value of the equity instruments granted, measured at the date at which the entity obtains the goods or the counterparty renders the service.

LEASES

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.

The Group as lessee

Rentals payable under operating leases are charged to profit or loss on a straight-line basis over the term of the relevant lease unless another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed. Contingent rentals arising under operating leases are recognised as an expense in the period in which they are incurred.

In the event that lease incentives are received to enter into operating leases, such incentives are recognised as a liability. The aggregate benefit of incentives is recognised as a reduction of rental expense on a straight-line basis, except where another systematic basis is more representative of the time pattern in which economic benefits from the leased assets are consumed.

PROVISIONS

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that the Group will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material).

When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, the receivable is recognised as an asset if it is virtually certain that reimbursement will be received and the amount of the receivable can be measured reliably.

RETIREMENT BENEFIT OBLIGATIONS

Payments to defined contribution retirement benefit plans are charged as an expense as and when employees have tendered the services entitling them to the contributions. Payments made to state-managed retirement benefit schemes, such as the Malaysia's Employees Provident Fund, are dealt with as payments to defined contribution plans where the Group's obligations under the plans are equivalent to those arising in a defined contribution retirement benefit plan. The Group does not have any defined benefit plans.

REVENUE

Revenue from contracts with customers is recognised in the income statement when performance obligations are considered met, which is when control of the hydrocarbons are transferred to the customer.

Revenue from the production of oil and gas, in which the Group has an interest with other producers, is recognised based on the Group's working interest and the terms of the relevant production sharing contracts.

Production revenue (liquids revenue) is recognised when the Group gives up control of the unit of production at the delivery point agreed under the terms of the contract. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. The amount of production revenue recognised is based on the agreed transaction price and volumes delivered.

Gas revenue is meter measured based on the hydrocarbon volumes delivered. The volumes delivered over a calendar month and are invoiced based on meter readings monthly. The price is either fixed (gas) or linked to an agreed benchmark (Brent Crude) in advance and premium or discounts are set based on commercial negotiations at arms-length. This methodology is considered appropriate as it is normal business practice under such arrangements. In line with the aforementioned, revenue is recognised at a point in time when deliveries of the gas are transferred to the customers.

A receivable is recognised once transfer has occurred as this represents the point in time at which the right to consideration becomes unconditional and only the passage of time is required before the payment is due.

ROYALTIES

Royalty arrangements that are based on production are recognised by reference to the underlying arrangement.

The Group's oil and gas operations are reflected in the profit or loss, based on the Group's working interest in such production. All government stakes, other than income taxes, and including government's share of production, are considered to be royalties. Royalties to government on production from these joint operations represent the entitlement of the respective governments to a portion of the Group's share of oil and gas and are recorded using rates in effect under the terms of contracts at the time of production.

INCOME TAX

Income tax expense represents the sum of the tax currently payable and deferred tax.

Current tax

The tax currently payable is based on taxable profit for the year. Taxable profit differs from profit as reported in the statement of profit or loss and other comprehensive income, because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are not taxable or tax deductible. The Group's liability for current tax (and tax laws) is calculated using tax rates that have been enacted or substantively enacted, in countries where the Company and its subsidiaries operate, by the end of the reporting period.

Petroleum resource rent tax (PRRT)

PRRT incurred in Australia is considered for accounting purposes to be a tax based on income. Accordingly, current and deferred PRRT expense is measured and disclosed on the same basis as income tax.

Deferred tax

Deferred tax is recognised on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred 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 tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

Deferred tax assets arising from deductible temporary differences associated with such investments and interests, are only recognised to the extent that it is probable that there will be sufficient taxable profits against which to utilise the benefits of the temporary differences and they are expected to reverse in the foreseeable future.

The carrying amount of deferred tax assets is reviewed at the end of each reporting period 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.

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled, or the asset realised, based on the tax rates (and tax laws) that have been enacted or substantively enacted, by the end of the reporting period.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.

Current and deferred tax for the year

Current and deferred tax are recognised as an expense or income in profit or loss, except when they relate to items credited or debited outside profit or loss (either in other comprehensive income or directly in equity), in which case the tax is also recognised outside profit or loss (either in other comprehensive income or directly in equity, respectively).

CASH AND BANK BALANCES IN THE STATEMENT OF CASH FLOWS

Cash and bank balances comprise cash in hand and at bank and other short term deposits held by the Group with maturities of less than 3 months.

3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

In the application of the Group's accounting policies, management is required to make judgments, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised, if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods.

Critical judgements in applying the Group's accounting policies

The following are the critical judgements, apart from those involving estimates (see below), that management has made on the process of applying the Group's accounting policies that have the most significant effect on the amounts recognised in the financial statements.

a) Acquisitions, divestitures, farm-in arrangements and/or assignment of interests

The Group accounts for acquisitions, divestitures, and farm-in arrangements by considering if the acquired or transferred interest relates to that of an asset, or of a business as defined in IFRS 3 Business Combinations. Accordingly, the Group considers if there is the existence of business elements (e.g., inputs, processes and outputs) or a group of assets that includes inputs, outputs and processes that are capable of being managed together for providing a return to investors or other economic benefits. The Group is of the view that the acquisition of the Montara Assets, (Note 7) meets the definition of a business. Accordingly, it has been accounted for as a business combination.

The Group considers farm-in arrangements that pertain to exploration interests, with no production license, and no proved reserves, to be assets, rather than a business, and would account for such farm-ins based on the consideration paid, which would be capitalised as an intangible exploration asset and subject to impairment reviews.

Key sources of estimation uncertainty

The key assumptions concerning the future, and other key sources of estimation uncertainty at the end of the reporting period, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.

a) Purchase price allocation & contingent payments

The determination of the purchase price allocation and the contingent liability components requires significant management judgement and assumptions. The contingent payments are based on multiple future triggering events that may or may not occur. The Group assesses these factors independently taking into account probabilities and future circumstances. Where the Chief Financial Officer deems necessary, independent valuation models and advisors will be requested to determine the fair value of such commitments. All contingent payments are set out in Note 7.

b) Valuation of derivative financial instruments

The Group entered into commodity price cash flow hedges during the year. In estimating the fair value of the derivative financial instruments, the Group uses market observable data to the extent it is available. If market observable data is unavailable, the Group engages advisors and qualified valuers to perform the valuation.

The carrying amount of derivative financial asset at December 31, 2018 is US$51.3 million (December 31, 2017: liability of US$3.1 million), and is shown in Note 35 (December 31, 2017: Note 29).

c) Depreciation of oil and gas properties

Oil and gas properties are depreciated using the units of production method.

The calculation of the units of production rate of amortisation could be impacted to the extent that actual production in the future is different from current forecast production based on proved and probable reserves. This would generally result from significant changes in any of the factors or assumptions used in estimating reserves.

These factors could include:

- Changes in proved and probable reserves;

- The effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions;

- Future estimates of capital expenditure requirements; and

- Unforeseen operational issues.

The carrying amount of oil and gas properties at December 31, 2018 is US$415.4 million (December 31, 2017: US$62.2 million), and is shown in Note 17.

d) Taxes

The Group recognises the net future economic benefit of deferred tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future and the carry forward of unused tax credits and unused tax losses can be utilised accordingly. Assessing the recoverability of deferred income tax and PRRT assets requires the Group to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Group to realise the net deferred tax assets as recorded in the statement of financial position, could be impacted. The carrying amounts of the Group's deferred tax assets are disclosed in Note 20 to the financial statements.

e) Reserves estimates

The estimated reserves are management assessments, and take into consideration reviews by an independent third party, under the Group's reserves audit programme, as well as other assumptions, interpretations and assessments. These include assumptions regarding commodity prices, exchange rates, discount rates, future production and transportation costs, and interpretations of geological and geophysical models to make assessments of the quality of reservoirs and their anticipated recoveries. Changes in reported reserves can impact asset carrying values, the provision for restoration and the recognition of deferred tax assets, due to changes in expected future cash flows. Reserves are integral to the amount of depreciation, depletion and amortisation charged to the statement of profit or loss and other comprehensive income, and the calculation of inventory.

f) Impairment of assets

The Group undertakes a regular review of asset carrying values to determine whether there is any indication of impairment. For intangible exploration assets impairment assessment, the Group takes into consideration the technical feasibility and commercial viability of extracting a mineral resource and whether there is any adverse information that will affect the Final Investment Decision. For oil and gas properties, expected future cash flow estimation is based on reserves, future production profiles, commodity prices and costs. The carrying amounts of intangible exploration assets and oil and gas properties are disclosed in Notes 16 and 17 respectively.

g) Asset restoration obligations

The Group estimates the future removal and restoration costs of oil production facilities, wells, pipelines and related assets at the time of installation of the assets. In most instances the removal of these assets will occur many years in the future.

The estimate of future removal costs is made considering relevant legislation and industry practice and requires management to make judgments regarding the removal date, the extent of restoration activities required and future removal technologies. The carrying amounts of the Group's asset restoration obligations is disclosed in Note 27 to the financial statements.

4. REVENUE

The Group derives its revenue from contracts with customers for the sale of oil and gas products. Revenue is presented net of royalties.

In line with the revenue accounting policies set out in Note 2, all revenue are recognised at a point in time.

	Year ended December 31, 2018	Nine months ended December 31, 2017 Restated*
	USD'000	USD'000

Liquids revenue - after hedging
Stag	74,772	42,203
Montara	31,198	-
Ogan Komering	8,520	12,782

Gas revenue
Ogan Komering	2,482	5,458
	116,972	60,443

Royalties	(3,549)	(8,429)

Total revenue derived from contracts with customers - after hedging and net of royalties	113,423	52,014

* The 2017 amounts have been restated as a result of initial adoption of IFRS 15. Refer to Note 42 for further information.

5. PRODUCTION COSTS

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Floating storage offloading ("FSO") vessel expenses	16,238	14,593
Workovers	10,577	9,430
Air, marine and onshore support	9,034	2,653
Repairs and maintenance	5,117	1,558
Operating manpower	13,501	7,665
Other operating expenses	19,148	7,843

Movement in inventory	16,724	(222)
	90,339	43,520

The cost of inventories recognised in production costs includes US$3.4 million (December 31, 2017: Nil) in respect of write downs of crude oil included as part of the Montara acquisition at fair value, to net realisable value.

The Ogan Komering PSC expired on February 28, 2018 and a temporary co-operation contract was entered into, continuing the terms of the PSC. A new PSC was issued on May 20, 2018 to Pertamina, at which point Jadestone no longer held an interest in the PSC. Included in the total production cost of US$90.3 million is US$2.8 million related to Ogan Komering (December 31, 2017: US$5.7 million) (Note 37).

6. DEPLETION, DEPRECIATION AND AMORTISATION ("DD&A")

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Depletion and amortisation
Stag	8,614	6,699
Montara	4,768	-
Ogan Komering	618	3,088
	14,000	9,787
Depreciation of plant and equipment (Note 18)	376	199
	14,376	9,986

The Ogan Komering DD&A charge is based on unit of production basis during the period from January 1 to May 19, 2018, after which the Group no longer held an interest in the PSC.

The Montara DD&A charge is based on unit of production basis during the period from September 28 to October 31, 2018, as the facility was shut down to address a maintenance and inspection backlog from November 1, 2018 for the remainder of the year.

7. ACQUISITION OF MONTARA ASSETS

7.1 Effective date and acquisition date

On September 28, 2018, Jadestone Energy (Eagle) Ltd, a wholly owned subsidiary of the Company, closed the acquisition of Montara Assets, obtaining control and 100% of the legal ownership from PTTEP Australia in the Montara Assets, apart from interest in the associated licenses which remains subject to regulatory approval. The acquisition of Montara Assets fits with the Group's strategic objective to build a portfolio of producing assets in the Asia-Pacific region and to realise additional value through cost reductions, operating efficiencies and investment programmes.

Although the transaction had an effective date of January 1, 2018, at which point the economic benefits of owning Montara Assets passed to the Group, the legal transfer of ownership and control of Montara Assets occurred at the date of completion being September 28, 2018 (the Acquisition Date), apart from interest in the associated licenses which remains subject to regulatory approval. It was at this point that the Group became able to control the key operating decisions relating to the Montara Assets. Therefore, for the purpose of calculating the purchase price allocation, management has determined the fair value adjustments using the balance sheet of Montara Assets as at the completion date of September 28, 2018.

7.2 Business acquisition

Management have concluded that the acquisition of the Montara Assets is that of a business as defined in IFRS 3 Business Combinations. The Montara Assets transaction contains inputs, processes being the workforce's ability to utilise the assets for extraction and there is output as this is a producing field. Accordingly, the transaction has been accounted for as a business combination.

Therefore, the Group has applied the acquisition method of accounting as at the acquisition date, performed a purchase price allocation exercise to identity, and measure at fair value, the assets acquired and liabilities assumed in the business combination. The consideration transferred has also been measured at fair value. The Group has adopted the definition of fair value under IFRS 13 Fair Value Measurement to determine the fair values.

7.3 Fair value of consideration transferred

The consideration for Montara Assets reflected a cash payment of US$133.1 million as set out below:

	USD'000

Asset purchase price	195,000
Crude inventory value	6,657
Capital charge	6,982
Net income adjustment (from January 1, 2018 to the date of acquisition)	(75,547)
Cash payment on acquisition date	133,092

The crude inventory value relates to the inventory on hand at the effective date of January 1, 2018. The capital charge reflects interest on the asset purchase price of US$195 million calculated on a daily basis at a rate of 3% above LIBOR from (and including) the effective date to (but excluding) the date of completion. The net income adjustment reflects the net of the interim period receipts and interim period expenses received, invoiced or paid by PTTEP Australia from the period from the effective date to the date of completion.

In addition there are deferred contingent payments payable in addition to the upfront cash consideration set out above depending on the outcome of a number of trigger events. The trigger events relate to 2018 production volumes, future dated Brent prices in 2019 and 2020, production from the infill well drilling scheduled for 2019 and final investment decision for developments with significant 2P reserves. The Group has reviewed all contingent payments and recorded an amount of US$15.8 million at fair value for the following two contingent events:

- Annual average Brent crude price exceeding US$80/bbl in 2019: US$20.0 million; and

- Annual average Brent crude price exceeding US$80/bbl in 2020: US$10.0 million.

Management has assessed the fair value of the above deferred contingent consideration using a Monte Carlo option simulation model, which considered inputs such as spot Brent oil price at completion date, risk-free rate, volatility factor and length of time the contingent payment will apply. This represents the fair value of the contingent consideration to be US$10.8 million and US$5.0 million for the 2019 and 2020 deferred payments respectively, totalling US$15.8 million. This reflects a discount of 46% and 50% for the respective 2019 and 2020 deferred contingent consideration payments reflecting the time value of money and the likelihood of the trigger event occurring. Please refer to 7.6 for the full disclosure of all the other contingent payments and management's assessment therein. As at December 31, 2018, the fair value of the contingent payments have been reduced to US$3.7 million (Note 28) as a result of the declining Brent crude oil price at year end.

The unplanned shutdown that occurred at Montara between November 1, 2018 to January 11, 2019 resulted in a loss of production and revenue during this period, as well as the increase in costs due to overheads still being incurred and additional maintenance work required to rectify the safety issues. As a result, on January 7, 2019, PTTEP Australia and the Group agreed that PTTEP Australia would fund cash calls capped at US$22.0 million. Management believes that the shutdown was a result of facts and circumstances that existed as at the acquisition date. As such, the US$22.0 million has been adjusted against the consideration transferred for the Montara Assets.

Fair value of purchase consideration	USD'000

Asset purchase price	195,000
Crude inventory value	6,657
Capital charge	6,982
Net income adjustment	(75,547)
Cash payment on acquisition date	133,092
Deferred contingent consideration	15,805
Prepaid Asset for future cash calls	(22,000)
Working capital adjustment	997
Total	127,894

Management has considered that the purchase consideration and the transaction terms is reflective of fair value for the following reasons:

- Open and unrestricted market: there were no restrictions in place preventing other potential buyers from negotiating with PTTEP Australia during the sales process period;

- Knowledgeable, willing but not anxious parties. The process was conducted over a number of months which gave the interested parties sufficient time to conduct due diligence and prepare analysis to support the transaction; and

- The Group is not a related party to PTTEP Australia. Both parties had engaged their own professional, financial and legal advisors so there is no reason to conclude that the transaction was not transacted at arm's length.

7.4 Assets acquired and liabilities assumed at the date of acquisition

The fair value assessment of the Montara identifiable assets and liabilities, acquired as at the date of acquisition, have been reviewed in accordance with IFRS 3 Business Combinations. The provisional fair value of the identifiable assets and liabilities of Montara as at the acquisition date were:

	USD'000

Asset
Non-current assets
Oil & gas properties	353,806
Current assets
Inventory - oil	17,195
Inventory - materials	18,178
Prepayments	4,917
Total assets	394,096

Liabilities
Current liabilities
Trade and other payables	(4,314)
Non-current liabilities
Provision for asset restoration obligations	(183,020)
Deferred tax liabilities	(78,437)
Other provisions	(431)
Total liabilities	(266,202)

Net identifiable assets acquired	127,894

The fair values disclosed are provisional as at December 31, 2018 due to the complexity of the acquisition and the proximity to the end of the year. As a result, the final fair values and associated calculations, which include tax effects, may differ, from this provisional determination. Pursuant to IFRS 3, the review of the fair value of the assets and liabilities acquired will be completed within 12 months of the acquisition, at the latest.

7.5 Impact of acquisitions on the results of the Group

Included in the loss for the year is a loss after tax of US$4.2 million and revenue of US$31.2 million that is attributable from Montara Assets.

Acquisition-related costs amounting to US$1.8 million have been excluded from the consideration transferred and have been recognised as an expense in the period, within "Other Expenses" line item in the consolidated statement of profit or loss and other comprehensive income.

Had the business combination been effected at January 1, 2018, and based on the performance of the business during 2018 under PPTEP Australia's operatorship, the Group would have generated revenues of US$257.2 million and an estimated net loss after tax of US$4.8 million.

Management of the Group considers these "pro-forma" numbers to represent an approximate measure of the performance of the combined Group on an annualised basis and to provide a reference point for comparison in future periods.

7.6 Deferred contingent consideration

No.	Trigger event	Consideration	Management's rationale
1.	The average dated Brent price in the calendar year 2019 is US$80/bbl or higher	US$20 million	Please refer to 7.3 above
2.	The average dated Brent price in the calendar year 2020 is US$80/bbl or higher	US$10 million	Please refer to 7.3 above
3.	Montara infill well production is equal to or greater than 1.5 mm bbls in the first 12 months after start of commercial production	US$20 million	It is unlikely that the infill well production will be equal or greater than 1.5 mm bbls in the first 12 months based on current projections. As such, fair value is assessed to be nil.
4.	First commercial gas	US$20 million	Group has no plans to produce gas from Montara as at the date of these financial statements.
5.	FID of development of new wells within Montara titles with 2P reserves greater than 15.0 mm bbls	US$60 million	Group has no substantive plans to drill new wells, aside from infill well drilling as at the date of these financial statements.

8. STAFF COSTS

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Wages, salaries and fees	10,555	7,201
Staff benefits in kind	2,463	1,071
Termination payments	-	311
Share based compensation	520	436
	13,538	9,019

The above staff cost includes director's and non-executive directors' salaries and fees.

Staff costs have increased during the year due to additional headcount predominately in Australia and Vietnam. The overall Group head count increased from 66 people to 78 people at the end of the year. PTTEP Australia currently operates the Montara Assets on behalf of Jadestone while the Group applies for the acceptance of its safety case, among other relevant regulatory approvals.

9. OTHER EXPENSES

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Professional fees/consultancies	5,474	3,776
Office costs	3,868	2,281
Travel and entertainment	811	366
Other expenses	221	(93)
	10,374	6,330

Professional fees in 2018 include one-off project fees associated with the acquisition of Montara Assets of US$1.8 million (December 31, 2017: Nil) and the AIM equity listing of US$1.9 million (December 31, 2017: US$0.4 million).

10. IMPAIRMENT OF ASSETS

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Impairment of intangible exploration assets (Note 16)	11,901	-

The Group performed a review of exploration assets during the year and as a result of that review, management decided to relinquish Block 127 in Vietnam at the end of the exploration phase in May 2018. All minimum work commitments had been completed and the Group returned the license and officially relinquished the block in October 2018. The total capitalised exploration expenditure in respect of Block 127 of US$11.9 million was charged to profit or loss as an impairment expense. There were no outstanding liabilities or capitalised costs for Block 127 as at December 31, 2018.

11. OTHER INCOME

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Gain on disposal of intangible exploration	-	400
Gain on disposal of motor vehicle	-	12
Interest income	422	57
Net foreign exchange gain/(loss)	640	(60)
Miscellaneous income	656	344
	1,718	753

12. FINANCE COSTS

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Interest	2,968	563
Accretion expense for asset retirement obligations (Note 27)	3,632	1,589
Convertible bond facility fees (Note 31)	560	200
Bond accretion (Note 31)	706	985
Fair value loss on derivative liability (Note 31)	1,195	677
Other finance costs	-	290
	9,061	4,304

Interest expense includes interest incurred on the Tyrus bond, which was repaid in August 2018, of US$0.6 million (December 31, 2017: US$0.6 million) and the new reserve based lending facility, which was drawn down on September 28, 2018, of US$2.4 million (December 31, 2017: Nil).

The accretion expense reflects the asset retirement obligations for the Stag field, and for the Montara field since September 28, 2018 (Note 27).

13. OTHER FINANCIAL GAINS

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Change in provisions - contingent payments	12,057	-
Gain on early repayment of convertible bonds	288	-
Net gain on ineffective oil derivatives	637	-
	12,982	-

The change in provisions represents the reduction in the fair value of the Montara contingent payments. The consideration to PTTEP Australia included two potential contingent payments which at the date of acquisition had a fair value of US$15.8 million. The contingent payments are only payable if the average Brent crude oil price is above US$80/bbl in either or both of 2019 and 2020. The fair value of these payments has declined since acquisition to US$3.7 million, reflecting the changes in the economic outlook for Brent crude oil prices.

14. INCOME TAX (EXPENSE)/CREDIT

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Current tax
Corporate tax	(2,188)	(1,610)
Petroleum resource rent tax (PRRT)	(6,221)	-
	(8,409)	(1,610)
Deferred tax
Accelerated tax depreciation	(3,196)	2,103
Tax losses	2,812	2,445
Petroleum resource rent tax (PRRT)	(774)	2,524
	(1,158)	7,072
	(9,567)	5,462

The Australian corporate income tax rate is applied at 30%. PRRT is calculated at 40% of sales revenue less certain permitted deductions and is tax deductible for Australian corporate income tax purposes. The Indonesian corporate income tax rate is applied at 35%. Branch profit tax is applied at 20%.

The above movement in deferred tax balances relates to temporary differences between the tax base of an asset or liability, and its carrying amount in the statement of financial position.

During the year, Stag utilised PRRT carried forward credits of US$5.8 million and incurred a liability of US$6.2 million. The Montara field has sufficient PRRT carried forward credits of US$2.9 billion available for offset against future PRRT taxable profit and so it is not anticipated to incur any liability for the foreseeable future.

The Company is a resident in the Province of British Columbia and pays no Canadian tax; the Group has no operating business in Canada. Subsidiary companies are resident for tax purposes in the territories in which they operate. No Canadian tax arises in the current period or in the previous year from any of the subsidiaries' operations in view of the losses incurred.

The tax (expense)/credit on Group losses differ from the amount that would arise using the standard rate of income tax applicable in the countries of operation as explained overleaf:

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Loss before tax on continuing operations	(21,446)	(20,392)

Tax credit calculated at the domestic tax rates applicable to the loss in the respective countries (Australia 30%, Indonesia 48%*, Canada 27% and Singapore 17%)	2,364	4,697
Effects of non-deductible expenses	(7,013)	(2,699)

Effects of tax previously unrecognised and unused tax losses now recognised in deferred tax asset	-	2,604
PRRT tax (expense)/benefit	(6,995)	-
Effect of PRRT tax benefit/(expense)	2,077	-
Effect of unused tax losses recognised as deferred tax assets	-	860
Tax (expense)/credit for the year	(9,567)	5,462

* The Indonesian tax rate is based on the effective rate after taking into account the corporate tax rate of 35% and the branch profit at 20%.

In addition to the amount charged to the profit and loss, the following amounts relating to tax have been recognised in other comprehensive income.

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Other comprehensive income - deferred tax
Income tax related to carrying amount of hedged item	15,207	-
	15,207	-

15. LOSS PER ORDINARY SHARE

The calculation of the basic and diluted loss per share is based on the following data:

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Loss for the purposes of basic and diluted per share, being the net loss for the year/period attributable to equity holders of the Company	31,033	14,930

	Year ended December 31, 2018	Nine months ended December 31, 2017
	Number	Number

Weighted average number of ordinary shares for the purposes of basic and diluted loss per share	316,787,465	221,298,004

The denominator, for the purposes of calculating both basic and diluted earnings per share, for the year ended 31, December 2018, has taken into account the shares issues pursuant to the listing on AIM on August 8, 2018.

The calculation of diluted EPS for the 12 months to December 31, 2018 excludes 74,668,968 (December 31, 2017: 75,486,320) of potential ordinary shares eligible for conversion under the secured convertible bond as they are non-dilutive given the interest and other costs on the bond per share exceed basic loss per share. Of such potential ordinary shares, 34,542,222 shares relate to the undrawn portion of convertible bond facility as of January 1, 2018.

Additionally, 2,631,982 (December 31, 2017: 868,949) of weighted potential ordinary shares available for exercise under vested options are not included given the Group's loss from continuing operations. For the nine-month period to December 31, 2017 an additional 234,641 of potential ordinary shares available for exercise under warrants then on issue are also not included for the same reason. These warrants expired unexercised on April 20, 2017.

Earnings per share (US$)	Year ended December 31, 2018	Nine months ended December 31, 2017

- Basic	(0.10)	(0.07)

- Diluted	(0.10)	(0.07)

16. INTANGIBLE EXPLORATION ASSETS

					Total
					USD'000

Cost
At April 1, 2017					198,500
Additions					744
Disposals					(5,950)
At December 31, 2017					193,294

Additions					1,835
Disposals					(99,522)
At December 31, 2018					95,607

Impairments
At April 1, 2017					93,571
Disposal of exploration assets					(5,950)
At December 31, 2017					87,621

Charged to profit or loss (Note 10)					11,901
Disposal of exploration assets					(99,522)
At December 31, 2018					-

Net book value
At December 31, 2017					105,673

At December 31, 2018					95,607

Exploration additions for the year were US$1.8 million (December 31, 2017: US$0.7 million).

The impairment of US$11.9 million relates to the relinquishment of Block 127 in Vietnam (Note 10).

For the purpose of the consolidated statement of cash flows, intangible exploration assets of US$0.7 million remained unpaid as at December 31, 2018 (December 31, 2017: US$0.5 million).

17. OIL AND GAS PROPERTIES

					Total
					USD'000

Cost:
At April 1, 2017					68,172
Changes in asset restoration obligations (Note 27)					5,919
Additions					1,772
At December 31, 2017					75,863

Arising from the acquisition of businesses (Note 7)					353,806
Changes in asset restoration obligations (Note 27)					6,353
Additions					6,968
At December 31, 2018					442,990

Accumulated depletion and amortisation:
At April 1, 2017					(3,838)
Depletion and amortisation for the period (Note 6)					(9,787)
At December 31, 2017					(13,625)

Depletion and amortisation for the year (Note 6)					(14,000)
At December 31, 2018					(27,625)

Net book value
At December 31, 2017					62,238
At December 31, 2018					415,365

18. PLANT AND EQUIPMENT

	At April 1, 2017	Additions	Impairment & disposals	At December 31, 2017
	USD'000	USD'000	USD'000	USD'000

Cost
Computer equipment	1,106	74	-	1,180
Fixtures and fittings	931	93	-	1,024
Motor vehicles	56	-	(56)	-
Total	2,093	167	(56)	2,204

Accumulated depreciation
Computer equipment	492	173	-	665
Fixtures and fittings	865	26	-	891
Motor vehicles	56	-	(56)	-
Total	1,413	199	(56)	1,556

Carrying amount	680			648

	At January 1, 2018 USD'000	Additions USD'000	Impairment & disposals USD'000	At December 31, 2018 USD'000

Cost
Computer equipment	1,180	1,192	-	2,372
Fixtures and fittings	1,024	245	-	1,269
Total	2,204	1,437	-	3,641

	At January 1, 2018	Depreciation	Impairment & disposals	At December 31, 2018
	USD'000	USD'000	USD'000	USD'000

Accumulated depreciation
Computer equipment	665	326	-	991
Fixtures and fittings	891	50	-	941
Total	1,556	376	-	1,932

Carrying amount	648			1,709

19. INVESTMENTS IN SUBSIDIARIES AND INTERESTS IN JOINT OPERATIONS

The succeeding sections of this Note present the details of the subsidiaries and joint operations of the Group.

Details of the investments in which the Group holds 20% or more of the nominal value of any class of share capital are as follows:

Name of the company	Place of incorporation	% voting rights and shares held 2018	% voting rights and shares held 2017	Nature of business

Jadestone Energy (Eagle) Pty Ltd*	Australia	100	-	Production oil & gas
Jadestone Energy (Australia Holdings) Pty Ltd*	Australia	100	-	Investment holdings
Jadestone Energy (Australia) Pty Ltd	Australia	100	100	Production oil & gas
Jadestone Energy (Holdings) Ltd	BVI	100	100	Dormant
Jadestone Energy (Ogan Komering) Ltd**	Canada	100	100	Production oil & gas
Jadestone Energy (Singapore) Pte Ltd	Singapore	100	100	Investment holdings
Jadestone Energy International Holdings Inc.	Canada	100	100	Investment holdings
Jadestone Energy Ltd	Bermuda	100	100	Investment holdings
Jadestone Energy Sdn Bhd	Malaysia	100	100	Administration
Mitra Energy (Indonesia Bone) Ltd	BVI	100	100	Exploration
Mitra Energy (Indonesia North Madura) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Indonesia NV) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Indonesia Rombebai) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Indonesia Sibaru) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Indonesia Spermonde) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Indonesia Titan) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Philippines SC- 56) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Philippines SC- 57) Ltd	BVI	100	100	Exploration
Mitra Energy (Services) Ltd	BVI	100	100	Dormant
Mitra Energy (Vietnam 05-1) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Con Son) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Vietnam Minh Hai) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Nam Du) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Phu Khanh) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Phu Quy) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Rang Dong) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Song Hong) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Thanh Long) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Tho Chu) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy Billiton Pte. Ltd	Singapore	100	100	Exploration
Titan Resources (Natuna) Indonesia Ltd	Barbados	100	100	Exploration
Titan Resources (Natuna) Indonesia Ltd	Bermuda	100	100	Exploration

* Jadestone Energy (Australia Holdings) Pty Limited and Jadestone Energy (Eagle) Pty Ltd were incorporated on June 22, 2018 as part of the Montara acquisition.

** The Ogan Komering PSC expired on February 28, 2018, and a temporary cooperation contract was entered into, continuing the PSC terms, pending the issue of the new PSC. The new PSC was issued to Pertamina on May 20, 2018, at which point Jadestone no longer held an interest in the PSC.

Details of the operations, of which all are in exploration stage except for Stag, Montara and Ogan Komering (ceased on May 20, 2018) which are in the production stage, are as follows:

				Group effective working interest % as at December 31,
Contract Area	Date of expiry	Held by	Place of operations	2018	2017

Montara Oilfield	Indefinite	Jadestone Energy (Eagle) Pty Ltd	Australia	100	N/A
Stag Oilfield	Aug 25, 2039	Jadestone Energy (Australia) Pty Ltd	Australia	100	100
Ogan Komering	May 19, 2018	Jadestone Energy (Ogan Komering) Ltd	Indonesia	-	50
SC56	Aug 4, 2055	Mitra Energy (Philippines SC-56) Ltd	Philippines	25	25
SC57	Sept 14, 2055	Mitra Energy (Philippines SC-57) Ltd	Philippines	21	21
51*	Jun 10, 2040	Mitra Energy (Vietnam Tho Chu) Pte Ltd	Vietnam	100	100
46/07*	Jun 29, 2035	Mitra Energy (Vietnam Nam Du) Pte Ltd	Vietnam	100	100
127**	May 24, 2042	Mitra Energy (Vietnam Phu Khanh) Pte Ltd	Vietnam	-	100

* Effective May 1, 2017, Petrovietnam Exploration Production Corporation relinquished its 30% working interest in Block 46/07 and Block 51 leaving Jadestone as operator with a 100% working interest in the Blocks, pending issuance of the new investment license from the regulator.

** The Group performed a review of exploration assets during the year and as a result of that review, management decided to relinquish Block 127 in Vietnam at the end of the exploration phase in May 2018. All minimum work commitments had been completed and the Group returned the license and officially relinquished the block in October 2018. There were no outstanding liabilities or capitalised costs as at December 31, 2018 (Note 10 and 16).

20. DEFERRED TAX

The following are the deferred tax liabilities and assets recognised by the Group and movements thereon during the current and prior reporting period.

	Australian PRRT	Accelerated tax depreciation	Tax losses	Total
	USD'000	USD'000	USD'000	USD'000

As at April 1, 2017	17,541	(1,200)	-	16,341
Credit to profit or loss	2,524	2,103	2,445	7,072
Exchange rate differences	208	-	-	208
As at December 31, 2017	20,273	903	2,445	23,621

(Charge)/credit to profit or loss	(774)	(3,196)	2,812	(1,158)
Charged to OCI	-	(15,207)	-	(15,207)
Acquisition of Montara assets	-	(78,437)	-	(78,437)
As at December 31, 2018	19,499	(95,937)	5,257	(71,181)

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Deferred tax liabilities	(92,468)	(200)
Deferred tax assets	21,287	23,821
	(71,181)	23,621

At the reporting date, the Group has unused tax losses of US$17.5 million (December 31, 2017: US$8.2 million) available for offset against future profits. A deferred tax asset has been recognised in respect of these losses to the extent that it is probable that the unutilised tax losses will reverse in the foreseeable future. Management has assessed the recoverability of the deferred tax assets based on forecast cash flows from operations. In addition, the Group has unused PRRT credits of approximately US$2.9 billion available for offset against future PRRT taxable profits in respect of the Montara field. No deferred tax asset has been recognised in respect of these PRRT credits, due to management's projections that there will continue to be current augmentation of PRRT credits, that are more than sufficient to offset against any PRRT tax to be paid. Accordingly, as PPRT credits are utilised based on a last-in-first-out basis, the past credits of approximately US$2.9 billion will not be utilised and are therefore not recognised as a deferred tax asset.

21. INVENTORIES

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Materials and spares	22,964	4,194
Crude oil inventory	6,867	5,416
	29,831	9,610

22. TRADE AND OTHER RECEIVABLES

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Trade receivables	57	1,987
Prepayments	26,831	1,766
Other receivables and deposits	4,857	285
PRRT receivables	700	-
GST/VAT receivables	355	681
	32,800	4,719

Trade receivables in 2018 represent revenues generated in Australia (December 31, 2017: Australia and Indonesia). The average credit period is 30 days (December 31, 2017: 30 days). All outstanding receivables as of December 31, 2017 have been fully recovered in 2018.

Prepayments includes US$22.0 million from PTTEP Australia (Note 7) relating to the Montara acquisition.

The Group has derivative receivable of US$4.0 million (December 31, 2017: Nil) within other receivables. The derivative receivable has been received in full in January 2019. There is no significant increase in credit risk since initial recognition.

Australian PRRT paid for the year to December 31, 2018 amounted to US$6.9 million, while the PRRT expense reported for the period was US$6.2 million. The difference of US$0.7 million paid, is recognised as a PRRT receivable, as it is expected to be refunded during the current PRRT year in view of abnormally higher near term expenditures at Stag and in particular, costs incurred for the Stag 49H infill well.

No interest is charged on outstanding receivables. There are no trade receivables older than 30 days.

23. CASH AND BANK BALANCES

	December 31, 2018	December 31, 2017
	USD'000	USD'000
Current assets
Cash and bank balances	58,064	10,450
Less: restricted cash	(5,083)	-
Cash and cash equivalents	52,981	10,450


Non-current assets
Cash and bank balances	23,561	10,729
Less: restricted cash	(23,561)	(10,729)
Cash and cash equivalents	-	-

Cash and cash equivalents in the consolidated statement of cash flows	52,981	10,450

As part of the reserve based lending agreement (Note 30), the Group must retain an aggregate amount of principal, interest, fees and costs payable that is equivalent to the amount payable at each quarter-end of the calendar year in the debt service reserve account ("DSRA"). An amount of US$18.6 million (December 31, 2017: Nil) is deposited in the DSRA as at December 31, 2018. In addition, the Group is required to maintain a minimum cash balance in the Montara cash operating account of US$15.0 million (December 31, 2017: Nil). The DSRA has been classified as restricted cash given certain restrictions under the loan agreement to withdraw amounts from the DSRA. The scheduled amounts of quarterly principal repayment under the loan, are sculpted, and decline over time, and hence the quantum required under the DSRA will fall, in line with reductions in the principal repayment, all other things being equal. US$5.1 million of the DSRA total balance, has been recognised as current/able to be released within 12 months, with the remaining $13.5 million treated as non-current/able to be released in 2020/2021.

The Group retains US$10.0 million (December 31, 2017: US$10.0 million) in support of a bank guarantee to a key supplier in respect of Stag's FSO vessel and is kept in a specific bank account that has in place restrictions that does not allow for the cash to be used for normal operations.

In 2017, restricted cash for Ogan Komering PSC's asset and site restoration fund amounted to US$0.7 million. The asset restoration obligation has been passed on to Pertamina, and accordingly, the restricted cash has been released, upon expiration of the PSC in the current year.

24. SHARE CAPITAL

Authorised ordinary shares

Unlimited number of ordinary voting shares with no par value.

	No. of shares	US$'000

Issued and fully paid At April 1, 2017 and December 31, 2017	221,298,004	364,466
Issued during the year	239,711,474	102,096
At December 31, 2018	461,009,478	466,562

On August 8, 2018, the Company was listed on AIM, a market by the London Stock Exchange. Pursuant to the listing on AIM, the Company issued 239,711,474 new ordinary shares, raising gross proceeds of approximately £83.9 million at a price of 35 pence per share. The majority of funds raised have been used to partly fund the Montara acquisition.

The costs arising from the issuance of the new shares and charged to profit or loss and equity amounted to US$2.0 million (December 31, 2017: Nil) and US$5.8 million (December 31, 2017: Nil) respectively.

The Company has one class of ordinary share. Fully paid ordinary shares carry one vote per share without restriction, and carry a right to dividends as and when declared by the Company.

25. HEDGING RESERVES

	Total USD'000

Balance at January 1, 2018	-
Gain arising on changes in fair value of hedging instruments during the year	(51,775)
Income tax related to gain recognised in other comprehensive income	15,534
Gain reclassified to profit or loss	1,088
Income tax related to amounts reclassified to profit or loss	(327)
At December 31, 2018	(35,480)

There were no hedge contracts in the comparative period.

The cash flow hedge reserve represents the cumulative amount of gains and losses on hedging instruments deemed effective in cash flow hedges. The cumulative deferred gain or loss on the hedging instrument is recognised in profit and loss only when the hedged transaction impacts the profit and loss, or is included directly in the initial cost or other carrying amount of the hedged non-financial items (basis adjustment).

26. SHARE BASED PAYMENTS RESERVE

The total expense arising from share based payments recognised for the period ended December 31, 2018 was US$0.5 million (December 31, 2017: US$0.4 million) (Note 8).

On August 19, 2015, the Company adopted, as approved by shareholders, a stock incentive plan (the "Plan") which establishes a rolling number of shares issuable under the Plan in the amount of 10% of the Company's issued shares at the date of grant. Under the terms of the Plan, the exercise price of each option granted cannot be less than the market price at the date of grant, or such other price as may be required by TSX-V. Options under the Plan can have a term of up to 10 years, with vesting provisions determined by the directors in accordance with TSX-V policies for Tier 2 Issuers.

The Black-Scholes option-pricing model, with the following assumptions, was used to estimate the fair value of the options at the date of grant:

	Options granted on
	July 29, 2018	March 29, 2018 December 10, 2017		March 28, 2017

Risk-free rate	2.23% to 2.26%	1.99% to 2.04%	1.68% to 1.72%	1.11% to 1.21%
Expected life	5.5 to 6.5 years	5.5 to 6.5 years	5.5 to 6.5 years	5.5 to 6.5 years
Expected volatility	44.7% to 43.2%	43.1% to 44.1%	43.2% to 43.9%	41.6% to 42.8%
Share price	C$0.61	C$0.43	C$0.42	C$0.45
Exercise price	C$0.61	C$0.50	C$0.45	C$0.47
Expected dividends	Nil	Nil	Nil	Nil

The following table summarises the share options outstanding and exercisable as at December 31, 2018:

	Share Options
	Number of options	Weighted average exercise price C$	Weighted average remaining contract life	Number of options exercisable

As at April 1, 2017	10,427,821	0.88	7.62	3,177,821
New share options issued	175,000	0.45	9.95	-
Cancelled during the year	(2,500,000)	1.82	-	(2,249,999)
As at December 31, 2017	8,102,821	0.58	9.03	927,822
Previously issued share options			8.04	2,475,008
New share options issued	4,500,000	0.54	9.36	-
Cancelled during the year	(470,000)	1.03	-	(170,000)
As at December 31, 2018	12,432,821	0.56	8.52	3,232,830

27. PROVISION FOR ASSET RESTORATION OBLIGATIONS

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Non-current assets
Opening balance	84,728	77,186
Acquisition of Montara (Note 7)	183,020	-
Accretion expense (Note 12)	3,632	1,589
Changes in discount rate and FX assumptions (Note 17)	6,353	5,919
Other	(36)	34
Closing balance	277,697	84,728

The Group's asset restoration obligations ("ARO") result from the future estimated costs to decommission each of the Stag and Montara assets.

The carrying value of the provision comprises the discounted present value of the estimated future costs. Current estimated costs of the ARO for each of the Stag and Montara assets have been escalated to the estimated date at which the expenditure would be incurred, at an assumed blended inflation rate of 2.13% and 2.27% respectively (December 31, 2017: Stag - 2.27%). The estimates are a blend of assumed US and Australian inflation rates to reflect the underlying mix of US dollar and Australian dollar denominated expenditures. The present value of the future estimated ARO for each of the Stag and Montara assets has then been calculated based on blended risk free rates of 2.49% and 2.60% respectively (December 31, 2017: Stag - 2.52%).

Management expects decommissioning expenditures to be incurred from 2032 onwards.

28. OTHER PAYABLES

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Stag FSO redundancy payments	6,603	7,259
Montara contingent payments (Note 7)	3,748	-
	10,351	7,259

The Stag FSO redundancy payments represents the fair value of amounts payable to the crew of the FSO on termination of the lease.

The Montara contingent payments of US$3.7 million (December 31, 2017: Nil) relate to the fair value of the two potential contingent payments as detailed in Note 7. At acquisition, the contingent payments were fair valued at US$15.8 million. The reduction to US$3.7 million reflects the change in outlook for Brent crude oil in 2019 and 2020 (Note 13) and the payments (if any) will need to be made in 2020 and 2021 respectively and accordingly have been classified as non-current on the consolidated statement of financial position.

29. DERIVATIVE FINANCIAL LIABILITIES

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Derivative financial instruments - convertible bond	-	3,067
	-	3,067

The US$3.1 million balance as at December 31, 2017 relates to the convertible bond which was repaid in August 2018 (Note 31).

30. BORROWINGS

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Non-current secured borrowings
Reserve based lending facility	49,420	-
	49,420	-

Current secured borrowings
Reserve based lending facility	51,114	-
Current unsecured borrowings
Other	1,279	829
	52,393	829

On August 2, 2018, the Company entered into a reserve based lending agreement to borrow US$120.0 million to partly fund the Montara acquisition (Note 7). The loan is secured against the Montara assets and repayable in quarterly tranches from December 31, 2018 until March 31, 2021. The loan was fully drawn down on September 28, 2018. The loan incurred costs of US$3.2 million and the fair value of the loan at draw down had an amortised carrying value of US$116.8 million. On December 31, 2018, the Company made principal and interest repayment of US$16.9 million and US$1.7 million respectively, leaving a balance of US$100.5 million.

The loan incurs interest at 3% above LIBOR.

31. SECURED CONVERTIBLE BOND

On November 8, 2016 the Group entered into a convertible bond with Tyrus Capital Event S.à r.l and incurred a structuring fee of 2% of the facility, and a 1% per annum standby fee on the undrawn portion of the facility until maturity on October 31, 2019.

On August 1, 2018, the Group and Tyrus Capital Event S.à r.l. conditionally agreed, upon admission and listing on AIM, that the Group would redeem the convertible bond facility by paying US$17.4 million to Tyrus and all associated security released. At June 30, 2018, the balance on the bond was drawn to US$15.0 million. Repayment subsequently occurred on August 15, 2018 and all associated security was released.

	Year Ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Interest expense (Note 12)	558	563
Standby fee (Note 12)	64	136
Bond accretion (Note 12)	706	985
Fair value of associated financial derivative (Note 12)	1,195	677
Amortisation of prepaid structuring fee (Note 12)	496	64
Gain on early repayment of convertible bonds (Note 13)	(288)	-
	2,731	2,425

Balances related to the secured convertible bond are:

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Nominal value of the convertible bonds issued	15,000	15,000
Derivative financial instruments at the date of issuance	(2,390)	(2,390)
Liability component at the date of issuance	12,610	12,610
Less: convertible bond issue costs	(378)	(378)
Liability recognised at inception, net of costs	12,232	12,232
Cumulative accretion expense	1,244	538
	13,476	12,770
Less: bond settlement adjustments	(13,476)	-
	-	12,770

32. RECONCILIATION OF LIABILITIES ARISING FROM FINANCING ACTIVITIES

The table below details changes in the Group's liabilities arising from financing activities, including both cash and non-cash changes. Liabilities arising from financing activities are those for which cash flows were, or future cash flows will be, classified in the Group's consolidated statement of cash flows, as cash flows from financing activities.

The cash flows represent the repayment of the convertible bond, drawdown on borrowings and repayment of borrowings in the statement of cash flows.

	At January 1, 2018	Financing Cash flows	Others	At December 31, 2018
	USD'000	USD'000	USD'000	USD'000

RBL facility	-	99,829	705	100,534
Secured convertible bond	12,770	(17,450)	4,680	-
Other borrowings	829	450	-	1,279

	At April 1, 2017	Financing Cash flows	Other	At December 31, 2017
	USD'000	USD'000	USD'000	USD'000

Secured convertible bond	-	14,550	(1,780)	12,770

33. COMMITMENTS UNDER OPERATING LEASES

The Group rents equipment under operating leases. The leases are for an average period of 3 years, with fixed rentals over the same period.

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Operating lease payments recognised as an expense during the year	7,630	5,738

At year-end, the Group has outstanding commitments under non-cancellable operating leases that fall due as follows:

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Within one year	9,671	7,367
Later than one year but within five years	32,408	27,596
Later than five years	2,368	9,121
	44,447	44,084

34. TRADE AND OTHER PAYABLES

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Trade payables	7,178	1,098
Other payables	13,657	8,591
Provision for long service leave	722	668
Other provisions	9,117	480
	30,674	10,837

These amounts are non-interest bearing and repayable on demand. The Group believes that the carrying amount of trade payables approximates their fair value.

Trade payables and accruals principally comprise amounts outstanding for trade purchases and ongoing costs. The average credit period taken for trade purchases is less than 30 days. For most suppliers no interest is charged on the trade payables in the first 30 days from the date of invoice. Thereafter, interest is charged on the outstanding balances at various interest rates. The Group has financial risk management policies in place to ensure that all payables are settled within the pre-agreed credit terms.

35. DERIVATIVE FINANCIAL INSTRUMENTS

The Group uses derivatives to manage its exposure to oil and gas fluctuations. Oil hedges are undertaken using swaps and collar options using fixed price sales contracts, all contracts are hedged using Dated Brent oil price options. In the current year, the Group has designated the capped swaps as a cash flow hedge of highly probable sales.

	December 31, 2018	December 31, 2017
Derivative financial assets	USD'000	USD'000

Designated as cash flow hedges
Commodity capped swap	51,324	-

Analysed as:
Current	15,339	-
Non-current	35,985	-
	51,324	-

The following is a summary of the Group's derivative contracts outstanding at December 31, 2018 (refer overleaf):

Contracts designated as hedges

Contract quantity	Type of contract	Term	Contract price	Hedge classification	Fair value of asset at December 31, 2018 USD'000

50% of anticipated Montara's planned 2PD production	Commodity capped swap	Oct 2018 - Sep 2020	Swap component: US$78.26/bbl for Q4 2018, US$71.72/bbl for 2019 and US$68.45/bbl for the nine months to September 30, 2020 Call component: US$80.00/bbl for the nine months to September 30, 2019, then US$85/bbl to September 2020	Cash flow	51,324

For the hedges of Montara's production, as critical terms (i.e., the notional amount, life and underlying oil price benchmark) of the capped swaps and their corresponding hedged items are highly similar, the Group performed a qualitative assessment of effectiveness and has concluded that the value of the capped swaps and the value of the corresponding hedged items will systematically change in opposite direction in response to movements in the underlying commodity prices.

There is however, a source of ineffectiveness in the capped swaps arrangement arising from the slight difference in the timing of Montara's production and the settlement of the capped swaps arrangement versus the crude sales. The overall change in value used for calculating hedge ineffectiveness on the capped swap hedge transaction amounted to US$637,000 (December 31, 2017: Nil) and has been included in the statement of profit or loss within "Other financial gains" (Note 13).

The following tables detail the commodity swap contracts outstanding at the end of the reporting period, as well as information regarding their related hedged items. Commodity swap contract assets are included in the "derivative financial instruments" line item in the consolidated statement of financial position. There is no hedge contract in the prior reporting period.

Hedging instruments - outstanding contracts

	Oil volumes	Notional value	Change in fair value used for calculating hedge ineffectiveness	Fair value assets
	bbls	USD'000	USD'000	USD'000

December 31, 2018
Cash flow hedges
Commodity swap component	3,157,050	222,718	637	50,477
Commodity call component	2,107,962	172,613	-	847
			637	51,324

Hedged items

	Change in value used for calculating hedge ineffectiveness	Balance in cash flow hedge reserve for continuing hedges	Balance in cash flow hedge reserve arising from hedging relationships for which hedge accounting is no longer applied
	USD'000	USD'000	USD'000

December 31, 2018
Cash flow hedges
Forecast sales	637	35,480	-

The following table details the effectiveness of the hedging relationships and the amounts reclassified from hedging reserve to profit or loss:

	Current period hedging gains recognised in OCI USD'000	Amount of hedge ineffectiveness recognised in profit or loss USD'000	Line item in profit or loss in which hedge ineffectiveness is included USD'000	Amount reclassified to profit or loss due to hedged item affecting profit or loss	Line item in profit or loss in which reclassification adjustment is included

December 31, 2018
Cash flow hedges
Forecast sales	36,241	637	Other financial gains	451	Revenue

36. FINANCIAL INSTRUMENTS, FINANCIAL RISKS AND CAPITAL MANAGEMENTS

Financial assets and liabilities

Current assets and liabilities

Management considers that due to the short term nature of the Group current assets and liabilities, the carrying values equate to their fair value.

Non-current assets and liabilities

All non-current assets and liabilities are reflected at fair value.

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Financial assets
At amortised cost	86,539	23,451
Derivative instruments designated in hedge accounting relationships	51,324	-
	137,863	23,451

Financial liabilities
At amortised cost	416,787	116,423
Contingent consideration for a business combination	3,748	-
Derivative instruments at FVTPL	-	3,067
	420,535	119,490

Fair values are based on management's best estimates after consideration of current market conditions. The estimates are subjective and involve judgment and as such are not necessarily indicative of the amount that the Group may incur in actual market transactions.

Commodity price risk

The Group's earnings are affected by changes in oil and gas prices. The Group manages this risk by monitoring oil and gas prices and entering into commodity hedges against fluctuations in oil prices if considered appropriate.

During the year, the Group entered into hedge contracts for sales at Stag and planned production at Montara.

Stag

The Group entered into a commodity hedge to hedge 350,000 bbls of Stag crude oil production, over the period January 2, 2018 to June 30, 2018 at Brent ICE crude fixed at US$64.60/bbl and another 350,000 bbls oil hedge, over the period July 1, 2018 to December 31, 2018, at Brent ICE crude fixed at US$65.00/bbl.

Montara

As part of the Montara acquisition, the Company hedged 50% of its planned production volumes for the 24 months to September 30, 2020. The hedge is a capped swap, providing downside price protection while allowing for participation in higher commodity prices via purchased call options. The call strike is set at US$80/bbl for the nine months to September 31, 2019 and US$85/bbl for the twelve months to September 2020. The swap price is set at US$78.26/bbl for Q4 2018, US$71.72/bbl for 2019 and US$68.45/bbl for the nine months to September 2020. Approximately two thirds of the swapped barrels in 2019 and 2020 have upside price participation via purchased calls. The effective date of the hedge contracts is October 1, 2018.

Commodity price sensitivity

The results of operations and cash flows from oil and gas production can vary significantly with fluctuations in the market prices of oil and/or natural gas. These are affected by factors outside the Group's control, including the market forces of supply and demand, regulatory and political actions of governments, and attempts of international cartels to control or influence prices, among a range of other factors.

The table below summarises the impact on profit/(loss) before tax, and on equity, from changes in commodity prices on the fair value of derivative financial instruments. The analysis is based on the assumption that the crude oil price moves 10%, with all other variables held constant. Reasonably possible movements in commodity prices were determined based on a review of recent historical prices and current economic forecasters' estimates.

	Effect on the result before tax for the year ended December 31,	Effect on other comprehensive income for the year ended December 31,	Effect on the result before tax for the nine-month period ended December 31,	Effect on other comprehensive income for the nine-month period ended December 31,
	2018	2018	2017	2017
Gain or loss	USD'000	USD'000	USD'000	USD'000

Increase by 10%	(1)	(16,729)	-	-
Decrease by 10%	1	16,729	-	-

Foreign currency risk

Foreign currency risk is the risk that a variation in exchange rates between US Dollars ("US Dollar") and foreign currencies will affect the fair value or future cash flows of the Company's financial assets or liabilities.

Cash and bank balances are generally held in the currency of likely future expenditures to minimise the impact of currency fluctuations. It is the Group's normal practice to hold the majority of funds in US Dollars in order to match the Group's revenue and expenditures. The Company's US$120.0 million reserve based loan facility is a US Dollar denominated instrument.

In addition to United States Dollars, the Group transacts in various currencies, including Canadian Dollars, Singapore Dollars, Australian Dollars, Indonesian Rupiah, Vietnamese Dong, and Malaysian Ringgit.

Material foreign denominated balances were as follows:

	December 31, 2018	December 31, 2017
Cash and bank balances	USD'000	USD'000

Australian Dollars	4,923	2,070

	December 31, 2018	December 31, 2017
Trade and other receivables	USD'000	USD'000

Australian Dollars	5,237	1,434


	December 31, 2018	December 31, 2017
Trade and other payables	USD'000	USD'000

Australian Dollars	1,974	5,769

If the Australian dollar weakens/strengthens by 10% against the functional currency of the Group, profit or loss will increase/decrease by US$0.4 million (December 31, 2017: US$0.2 million).

Interest rate risk

The Group's interest rate exposure arises from some of its cash and bank balances and borrowings. The Group's other financial instruments are non-interest bearing or fixed rate, and are therefore not subject to interest rate risk.

Jadestone holds some of its cash in interest bearing accounts and short-term deposits. Interest rates currently received are at historically relatively low levels. Accordingly, a downward interest rate movement would not cause significant exposure to the Group.

On August 2, 2018, the Group entered into a reserve based lending agreement with the Commonwealth Bank of Australia and Société Générale to borrow US$120.0 million, repayable quarterly to March 31, 2021. The loan was fully drawn down on September 28, 2018 and incurs interest at LIBOR plus 3%. The loan incurred costs of US$3.2 million, which were offset against the proceeds received.

The balance of short term borrowings as at December 31, 2018 amounts to US$ Nil (December 31, 2017: US$0.8 million). The 7.5% coupon on the Group's US$15.0 million convertible bond facility, drawn down as at December 31, 2017 (Note 31), was a fixed rate coupon and this facility was fully redeemed in August 15, 2018.

Based on the carrying value of the reserve based loan of US$100.5 million at December 31, 2018, if interest rates had increased or decreased by 1% and all other variables remained constant, the Group's quarterly net income/(loss) before tax would have increased or decreased by US$0.3 million (December 31, 2017: Nil).

Credit risk

Credit risk represents the financial loss that the Group would suffer if a counterparty in a transaction fails to meet its obligations in accordance with the agreed terms.

The Group actively manages its exposure to credit risk, granting credit limits consistent with the financial strength of the Group's counterparties and customers, requiring financial assurances as deemed necessary, reducing the amount and duration of credit exposures, and close monitoring of relevant accounts.

The Group trades only with recognised, creditworthy third parties. Where Jadestone operates joint ventures on behalf of partners it seeks to recover the appropriate share of costs from these partners. The majority of the partners in these ventures are well established oil and gas companies.

In the event of non-payment, Jadestone has recourse to increase its venture share under the operating agreements.

The Group's current credit risk grading framework comprises the following categories:

Category	Description	Basis for recognising expected credit losses (ECL)
Performing	The counterparty has a low risk of default and does not have any past-due amounts.	12-month ECL
Doubtful	Amount is > 30 days past due or there has been a significant increase in credit risk since initial recognition.	Lifetime ECL - not credit-impaired
In default	Amount is > 90 days past due or there is evidence indicating the asset is credit-impaired.	Lifetime ECL -credit-impaired
Write-off	There is evidence indicating that the debtor is in severe financial difficulty and the Group has no realistic prospect of recovery.	Amount is written off

The tables below detail the credit quality of the Group's financial assets and other items, as well as maximum exposure to credit risk by credit risk rating grades (refer overleaf):

	Note	External credit rating	Internal credit rating	12-month ("12m") or lifetime ECL	Gross carrying amount⁽ⁱ⁾ USD'000	Loss allowance USD'000	Net carrying amount USD'000

December 31, 2018
Cash and bank balances	23	n.a	Performing	12m ECL	81,625	-	81,625
Trade receivables	22	n.a	(i)	Lifetime ECL	57	-	57
Other receivables	22	n.a	Performing	12m ECL	4,857	-	4,857

December 31, 2017
Cash and bank balances	23	n.a	Performing	12m ECL	21,179	-	21,179
Trade receivables	22	n.a	(i)	Lifetime ECL	1,987	-	1,987
Other receivables	22	n.a	Performing	12m ECL	285	-	285

⁽ⁱ⁾ For trade receivables, the Group has applied the simplified approach in IFRS 9 to measure the loss allowance at lifetime ECL. The Group determines the expected credit losses on these items by using specific identification, estimated based on historical credit loss experience based on the past due status of the debtors, adjusted as appropriate to reflect current conditions and estimates of future economic conditions. Accordingly, the credit risk profile of these assets is presented based on their past due status in terms of specific identification.

As at December 31, 2018, total trade receivables amounted to US$57,000 (December 31, 2017: US$1,987,000). The balance in 2017 had been fully recovered in 2018. The Group has derivative receivable of US$4.0 million (December 31, 2017: Nil) within other receivables. The derivative receivable was received in full in January 2019.

The concentration of credit risk relates to the main counterparty to oil and gas sales in Australia, where the sole customer has an A1 credit rating (Moody's). All trade receivables are initially settled 30 days after issuance date followed by a final reconciliation payment after a further 30 days, mitigating largely any credit risk.

The Group recognises lifetime expected credit loss (ECL) for trade receivables. The ECL on these financial assets are estimated based on days past due and applies a percentage of expected non-recoveries for each group of receivables. As at financial period end, ECL from trade and other receivables are expected to be insignificant.

Cash and bank balances are placed with reputable banks and financial institutions which are regulated with no history of default.

The maximum credit risk exposure relating to financial assets is represented by their carrying value as at the balance sheet date.

Liquidity risk

Liquidity risk is the risk that the Group will not be able to meet all of its financial obligations as they become due. This includes the risk that the Company cannot generate sufficient cash flow from producing assets or is unable to raise further capital in order to meet its obligations.

The Group manages it liquidity risk by optimising the positive free cash flow from its producing assets (with full legal ownership of Montara effective from September 28, 2018), on-going cost reduction initiatives, merger and acquisition strategies, and bank balance on hand.

The Group net loss after tax for the year was US$31.0 million (December 31, 2017: US$14.9 million). Net cash generated from operations for the year ended December 2018 was US$17.8 million (December 31, 2017: net cash used of US$6.7 million). The Group's net current assets remained positive at US$72.3 million as at December 31, 2018 (December 31, 2017: US$13.1 million).

The Company's reserve based loan is sized on a borrowing base drawn from projected cash flows from the Montara Assets, and based on proved and probable producing reserves (2PD). This borrowing base is subject to scheduled semi-annual redeterminations and as such, and in the event of a significant reduction in the borrowing base, there is a risk that scheduled repayments may increase to offset any such borrowing base deficiency. The existing borrowing base, as assessed by the lenders as at December 2018, is significantly above aggregate commitments.

The Group believes it has sufficient liquidity to meet all reasonable scenarios of operating and financial performance for the next 12 months.

Non-derivative financial liabilities

The following table details the expected maturity for non-derivative liabilities. The table below has been drawn up based on the undiscounted contractual maturities of the financial liabilities including interest that will be earned on those liabilities except where the Group anticipates that the cash flow will occur in a different period. The adjustment column represents the estimated future cash flows attributable to the instrument included in the maturity analysis, which are not included in the carrying amount of the financial liability on the consolidated statement of financial position, namely interest expense.

	Weighted average effective interest rate %	On demand or within 1 year USD'000	Within 2 to 5 years USD'000	More than 5 years USD'000	Adjustments USD'000	Total USD'000

December 31, 2018
Non-interest bearing	-	30,674	6,603	277,697	-	314,974
Variable interest rate instruments	8.071	58,907	52,182	-	(9,276)	101,813
		89,581	58,785	277,697	(9,276)	416,787

December 31, 2017
Non-interest bearing	-	10,837	7,259	84,728	-	102,824
Fixed interest rate instruments	7.500	958	13,628	-	(1,816)	12,770
Variable interest rate instruments	7.080	888	-	-	(59)	829
		12,683	20,887	84,728	(1,875)	116,423

Non-derivative financial assets

The following table overleaf details the expected maturity for non-derivative financial assets. The inclusion of information on non-derivative financial assets is necessary in order to understand the Group's liquidity risk management, as the Group's liquidity risk is managed on a net asset and liability basis. The table below has been drawn up based on the undiscounted contractual maturities of the financial assets including interest that will be earned on those assets except where the Group anticipates that the cash flow will occur in a different period. The adjustment column represents the estimated future cash flows attributable to the instrument included in the maturity analysis which are not included in the carrying amount of the financial asset on the consolidated statement of financial position, namely interest income.

	Weighted average effective interest rate %	On demand or within 1 year USD'000	Within 2 to 5 years USD'000	Adjustments USD'000	Total USD'000

December 31, 2018
Non-interest bearing	-	4,914	-	-	4,914
Variable interest rate instruments	*	58,064	23,561	*	81,625
		62,978	23,561	*	86,539

December 31, 2017
Non-interest bearing	-	2,272	-	-	2,272
Variable interest rate instruments	*	10,450	10,729	*	21,179
		12,772	10,729	*	23,451

* The effect of interest is not material.

Capital management

The Group manages its capital structure and makes adjustments to it, based on the funds available to the Group, in order to support the acquisition, exploration and development of resource properties and the ongoing operations of its producing assets. Given the nature of the Group's activities, the Board of Directors does not establish quantitative return on capital criteria for management, but rather works with management to ensure that capital is managed effectively and the business has a sustainable future.

To carry-out planned asset acquisitions, exploration and development, and to pay for administrative costs, the Group may utilise excess cash generated from its ongoing operations and may utilise its existing working capital, and will work to raise additional funds if needed.

Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of the Group, is reasonable. There were no changes in the Group's approach to capital management during the financial period ended December 31, 2018. The Group is not subject to externally imposed capital requirements.

	December 31, 2018	December 31, 2017
Gearing ratio	USD'000	USD'000

Debt	101,813	13,599
Cash and cash equivalents	(52,981)	(10,450)
Restricted cash	(18,644)	-
Net debt	30,188	3,149
Equity	215,261	108,198
Net debt to equity ratio	14%	3%

Debt is defined as long and short-term borrowings (excluding derivatives) as detailed in Notes 30 and 31. Cash and cash equivalents includes the Montara Assets' minimum working capital cash balance of US$15.0 million required under the RBL, while restricted cash comprises the US$18.7 million in the RBL debt service reserve account as at December 31, 2018. Restricted cash, as shown here, excludes the US$10.0 million deposited in support of a bank guarantee to a key supplier in respect of the Stag FSO (see Note 23). Equity includes all capital and reserves of the Group that are managed as capital.

The Group's overall strategy remains unchanged from 2017.

Fair value measurements

The Group discloses fair value measurements by level of the following fair value measurement hierarchy:

1) Quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1);

2) Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (Level 2); and

3) Inputs for the asset or liability that are not based on observable market data (unobservable inputs) (Level 3).

								Relationship
								of
Financial	Fair value (USD'000) as at				Fair		Significant	unobservable
assets/financial	December 31, 2018		December 31, 2017		value	Valuation technique(s)	unobservable	inputs to
liabilities	Assets	Liabilities	Assets	Liabilities	hierarchy	and key input(s)	input(s)	to fair value

Derivative financial instruments
1) Derivative component of convertible bonds (Note 29)	-	-	-	3,067	Level 2	Based on third party valuations for similar products.	n.a.	n.a.
2) Commodity capped swap contracts (Note 35)	51,324	-	-	-	Level 2	Third party valuations based on market comparable information.	n.a.	n.a.

Others - contingent consideration in a business combination
3) Contingent consideration (Note 7 and 28)	-	3,748	-	-	Level 3	Based on the nature and the likelihood of occurrence of the trigger event. Fair value is estimated using future Dated Brent price forecasts at the end of the reporting period, taking into account time value of money and volatility factor.	Expected future volatility of 25% is based on analysis of the Brent oil price index's movement prior to acquisition date.	A slight increase in Brent oil price index would result in a significant increase in the fair value and vice versa.

37. SEGMENT INFORMATION

Information reported to the Group's Chief Executive Officer (the Chief Operating Decision Maker) for the purposes of resource allocation is focused on two reportable/business segments driven by different types of activities within the upstream oil and gas value chain, namely exploration and producing assets. The geographic focus of the business is on Southeast Asia ("SEA") and Australia.

Revenue and non-current assets information based on the geographical location of assets respectively are as follows (refer overleaf):

	Year ended December 31, 2018
	Producing assets		Exploration
	Australia	SEA	SEA	Corporate	Total
	USD'000	USD'000	USD'000	USD'000	USD'000

Revenue	105,970	7,453	-	-	113,423

Production cost	(87,559)	(2,780)	-	-	(90,339)
Depletion, depreciation & amortisation	(13,666)	(618)	-	(92)	(14,376)
Staff costs	(3,489)	(1,834)	(816)	(7,399)	(13,538)
Other expenses	(5,022)	(146)	(434)	(4,772)	(10,374)
Impairment of assets	-	-	(11,901)	-	(11,901)
Other income	1,529	-	-	189	1,718
Finance costs	(6,040)	-	(80)	(2,941)	(9,061)
Other financial gain	12,693	-	-	289	12,982
Profit/(Loss) before tax	4,416	2,075	(13,231)	(14,726)	(21,466)

Additions to non-current assets	360,774	-	1,835	1	362,610

Total assets & liabilities
Current assets	147,358	345	417	8,560	156,680
Non-current assets	476,981	-	95,607	280	572,868
Current liabilities	(79,867)	(93)	(737)	(3,654)	(84,351)
Non-current liabilities	(429,936)	-	-	-	(429,936)
Net assets	114,536	252	95,287	5,186	215,261

	Year ended December 31, 2017 (Restated)
	Producing assets		Exploration
	Australia	SEA	SEA	Corporate	Total
	USD'000	USD'000	USD'000	USD'000	USD'000

Revenue	42,203	9,811	-	-	52,014

Production cost	(37,953)	(5,567)	-	-	(43,520)
Depletion, depreciation & amortisation	(6,949)	(3,037)	-	-	(9,986)
Staff costs	(1,276)	-	(736)	(7,007)	(9,019)
Other expenses	(1,425)	-	(750)	(4,155)	(6,330)
Other income	-	-	741	12	753
Finance costs	(3,888)	-	-	(416)	(4,304)
Profit/(Loss) before tax	(9,288)	1,207	(745)	(11,566)	(20,392)

Additions to non-current assets	-	1,772	3,688	-	5,460

Total assets & liabilities
Current assets	19,478	1,502	449	3,350	24,779
Non-current assets	95,898	1,346	105,673	192	203,109
Current liabilities	(6,581)	(2,408)	(419)	(2,258)	(11,666)
Non-current liabilities	(91,987)	-	-	(16,037)	(108,024)
Net assets	16,808	440	105,703	(14,753)	108,198

Non-current assets include oil and gas properties, intangible exploration assets and property plant and equipment used in corporate offices.

Included in revenues arising from producing assets are revenues of approximately US$106.0 million (December 31, 2017: US$42.2 million) which arose from sales to the Group's largest customer.

38. FINANCIAL CAPITAL COMMITMENTS

Certain PSC's and service concessions' have firm capital commitments. The Group has the following outstanding minimum exploration commitments (refer overleaf):

SEA portfolio PSC operational commitments

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Not later than one year	10,000	10,000
	10,000	10,000

The SEA portfolio PSC operational commitments as at December 31, 2018 amounting to US$10 million (December 31, 2017: US$ 10 million), relates to the minimum work commitment outstanding in exploration phase two of the Block 46/07 PSC for the drilling of a further well.

Under the terms of the Block 46/07 PSC, Jadestone is committed to drill one more appraisal well on the block. The Company plans to drill an appraisal well on the Nam Du field to facilitate transition of 3C resource to 2C status. This well would be retained for future use as a Nam Du gas producer. On November 13, 2018, the Vietnam Government approved a request by the Company to extend the exploration phase two period for Block 46/07 by a further two years to June 29, 2020. This enables the appraisal well drilling to be deferred to 2020, which aligns with ongoing project facilities engineering definition and development well planning, thus ensuring that the final appraisal well design is suitable for use as a Nam Du platform production well.

Operational commitments and capital commitments

The Group has the following commitments for expenditure that were contracted for at the end of the reporting period but not recognised as liabilities. These include commitments for operations and personnel in relation to the Stag FSO as well as contracted expenditure for significant projects.:

	December 31, 2018	December 31, 2017
	USD'000	USD'000

Not later than one year	43,925	10,962
After one year but not more than five years	47,068	47,534
After five years	4,321	17,145
	95,314	75,641

39. CONTINGENT LIABILITIES

Stag

The Group may be responsible for certain contingent payments after 2018 of up to US$10 million linked to future expansion of the Stag Oilfield. At this time, Jadestone's management does not consider it probable that the conditions necessary to trigger the contingent payments will occur. Accordingly, as at December 31, 2018, no provision has been recognised in the financial statements.

Montara

The Group may be responsible for certain contingent payments after 2018 of up to US$130 million linked to oil price appreciation, and/or volumes of production from the first infill well in its first year, and/or future expansion of the Montara Assets (see also Note 7). At this time, Jadestone's management only considers the contingent payments of up to US$3.7 million linked to oil price appreciation above US$80/bbl in 2019 and/or 2020 as probable, while also noting the uncertain nature of future changes in oil prices; in this case future prices of Dated Brent. Accordingly, the fair value of the two oil price linked contingent payments of up to US$30 million is recognised as a payable (see Note 28) and the remaining US$100 million of contingent payments has not been recognised in the financial statements.

40. EVENTS AFTER THE END OF THE REPORTING PERIOD

US$22.0mm Montara adjustment

On January 7, 2019, an agreement was reached between PTTEP Australia and a subsidiary of Jadestone pursuant to which the Group would receive US$22.0 million from PTTEP Australia in relation to the recent shutdown to address the maintenance and inspection backlog at the Montara Assets. This was accounted for as a purchase price adjustment (see Note 7). Production at the Montara Assets restarted on January 11, 2019.

Stock options

On March 29, 2019, following a board approval earlier in the month, the Company issued 8.0 million incentive stock options to a number of employees, officers, directors and consultants. The stock options are exercisable for a period of ten years at an exercise price of Canadian dollars 0.85 per share. The stock options vest over a three year period and were granted in accordance with the terms of the Company's stock option plan, which has been approved by the Company's shareholders and the TSX Venture Exchange.

41. RELATED PARTY TRANSACTIONS

During the year, the Group entities did not enter into transactions with related parties, other than the following:

Compensation key management personnel

	Year ended December 31, 2018	Nine months ended December 31, 2017
	USD'000	USD'000

Short-term benefits	2,656	1,718
Other benefits	326	279
Share based payments	234	119
	3,216	2,116

The total remuneration of members of key management in 2018 (including salaries and benefits) was US$3.2 million (December 31, 2017: US$2.1 million).

Compensation of directors

	Year ended December 31, 2018
	Short term benefits^(a)	Other benefits^(a)	Share based payments	Total compensation
	USD'000	USD'000	USD'000	USD'000
A. Paul Blakeley	1,035	422	164	1,621
Daniel Young	546	149	74	769
Dennis McShane	130	-	19	149
Iain McLaren	70	-	9	79
Robert Lambert	50	-	9	59
David Neuhauser	45	-	9	54
Eric Schwitzer	58	-	9	67
	1,934	571	293	2,798

		Nine months to December 31, 2017
	Short term benefits^(a)		Other benefits^(a)	Share based payments	Total compensation
	USD'000		USD'000	USD'000	USD'000
A. Paul Blakeley	455		281	134	869
Daniel Young	330		97	40	467
Dennis McShane	7		-	1	8
Iain McLaren	70		-	6	76
Robert Lambert	50		-	6	56
David Neuhauser	45		-	6	51
Eric Schwitzer	57		-	6	63
	1,014		378	199	1,591

^(a)Short term benefits comprise salary, director fee as applicable, performance pay, pension and other allowances. Other benefits comprise benefits-in-kind.

Director participation in AIM equity raise

Certain directors and members of the management team of the Company ("Insiders") subscribed for new shares pursuant to the AIM equity raise and listing completed in August 2018. The issuance of new shares to these Insiders pursuant to the AIM equity raise and listing is considered to be a related party transaction within the meaning of TSX Venture exchange policy 5.9 and multilateral instrument 61-101 ("MI 61-101"), and disclosable in the December 31, 2018 year-end financial statements under AIM rule 19. The Company has relied on the exemptions from the valuation and minority shareholder approval requirements of MI 61-101, contained in sections 5.5(b) and 5.7(1)(b) of MI 61-101, in respect of the Insider participation. Certain directors subscribed for a total of 1,961,271 new shares at 35 pence per share (or £688,545) as follows.

	Number of new shares

Dennis McShane	217,919
A. Paul Blakeley	544,798
Robert Lambert	217,919
Iain McLaren	108,959
David Neuhauser*	544,798
Eric Schwitzer	108,959
Daniel Young	217,919
	1,961,271

* These relate to ordinary shares that Mr. Neuhauser is deemed to have an interest in through Livermore Strategic Opportunities LP, which Mr. Neuhauser is the Managing Director and hence has the power and authority to direct Livermore's activities

Repayment of secured convertible bonds

Tyrus Capital Event S.à r.l., an entity controlled by Tyrus Capital S.A.M., entered into a secured convertible bond facility agreement with the Company in November 2016. Tyrus Capital S.A.M. controls entities that hold approximately 23.8% of the Company's ordinary share capital as at September 30, 2018.

On August 1, 2018, the Company and Tyrus Capital Event S.à r.l. conditionally agreed, upon the Company's admission and listing on AIM, that the Company would redeem the secured convertible bond facility by paying US$17.4 million to Tyrus, and all associated security released. At June 30, 2018, the balance on the bond was drawn to US$15.0 million. Repayment subsequently occurred on August 15, 2018.

42. RESTATEMENTS AND COMPARATIVE FIGURES

In accordance with IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors, certain restatements have been made to the prior year's financial statements, following the Group's adoption of IFRS 15, that became effective during the year.

As a result, comparative figures in certain line items have been amended in the statement of profit or loss and other comprehensive income, statement of cash flows, and the related notes to the financial statements. Refer to further information set out in Note 2.

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

END

FR DMGMDKRLGLZG

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