Final Results

RNS Number : 6186K

Jadestone Energy Inc.

23 April 2020

Jadestone Energy Inc.

Jadestone Energy Reports Results for the Year Ended December 31, 2019
Record US$325 million Revenue and US$177 million Operating Cash Generated

April 23, 2020-Singapore: Jadestone Energy Inc. (AIM: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 year ended December 31, 2019.

Financial highlights

Jadestone reports record annual production, revenue, EBITDAX, operating cashflow, profit before tax, and profit after tax, with the benefit of a full year contribution from Montara;
2019 full year net revenue of US$325.4 million, a nearly three-fold increase over 2018 of US$113.4 million;
Liftings for the full year were 4,496.2 mbbls, compared to 1,683.1 mbbls in 2018, reflecting a full year of Montara production of 3,826.1 mbbls;
Average price realisations for 2019 were US$69.07/bbl, compared to US$69.39/boe in 2018, with the increase in pricing premia for each of Stag and Montara offsetting the year-on-year reduction in Brent;
Full year 2019 adjusted EBITDAX of US$187.5¹ million, which compares to US$10.2¹ million in 2018;
A more than 20% reduction in unit operating costs, generating an average cash cost per barrel for 2019 of US$22.85/bbl, before workovers, and compared to US$28.72/boe in 2018;
2019 full year positive net cash generated from operations of US$176.7 million, before changes in working capital, tax and interest, compared to a US$0.3 million net use of cash in 2018;
Annual pre-tax profit of US$73.3 million, compared to a pre-tax loss in 2018 of US$21.5 million;
Full year 2019 profit after tax of US$40.5 million, compared to a net loss of US$31.0 million in 2018;
Gross debt outstanding reduced to US$49.1² million by year-end, compared to US$101.8 million at December 2018. Following the March 2020 scheduled repayment of US$12.9 million, the principal balance outstanding is now US$37.3² million;
Gross cash and bank balances of US$89.4³ million at year-end, resulting in a net cash position of US$40.3² million. As at March 31, 2020, gross cash and bank balances had grown to US$109.4 ² million, or a net cash position of US$72.1² million; and
On November 18, 2019, the Company announced the acquisition of an operated 69% interest in the Maari Project, shallow water offshore New Zealand, for a total headline cash consideration of US$50.0 million.

¹ EBITDAX is a non-GAAP financial measure which does not have a standardised meaning prescribed by IFRS. This non-GAAP financial measure is included because management uses this information to analyse financial performance, efficiency and liquidity and it may be useful to investors on the same basis. EBITDAX is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, "net earnings (loss)" as determined in accordance with IFRS, as an indicator of financial performance. EBITDAX equals net earnings (loss) plus financial expenses (income), provisions for (recovery of) income taxes, and depletion, depreciation and amortisation and exploration expense. Because non-GAAP financial measures do not have a standardised meaning prescribed by IFRS, they are unlikely to be comparable to similar measures presented by other companies and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS.
² Gross debt and net debt/cash are non-GAAP measures which do not have a standardised meaning prescribed by IFRS. These measures are included because management uses this information to analyse the liquidity and financial position of the group and it may be useful to investors on the same basis. Gross debt and net debt/cash are non-GAAP measures and should not be considered an alternative to, or more meaningful than 'Net increase in cash and cash equivalents' as determined in accordance with IFRS, as an indicator of liquidity and financial performance. Gross debt is defined as long and short term interest bearing debt, and excludes derivatives. Net debt/cash is defined as cash and cash equivalents including the Montara assets' minimum working capital cash balance of US$15 million required to be maintained under the conditions of the reserve based lending facility and restricted cash of US$13.5 million under the debt service reserve account. The restricted cash excludes the US$10 million deposited in support of a bank guarantee to a key supplier of the Stag FSO. Because non-GAAP financial measures do not have a standardised meaning prescribed by IFRS, they are unlikely to be comparable to similar measures presented by other companies and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS.

³ Excludes a US$10.0 million deposit in support of a bank guarantee

Operational highlights

Continued safe operations at all assets, with no significant recordable personnel or environmental incidents;
Full year average production of 13,531 bbls/d, reflecting a full year of operations from the Montara asset, in addition to the Stag field, a more than three-fold increase on average production in 2018 of 4,057 boe/d;
All outstanding regulatory deficiencies at Montara, which were inherited when the asset was acquired, have been corrected, and we have operated for the remainder of the year without any regulatory enforcement notices;
Successfully conducted the first phase of major investments on Montara, including a subsea umbilical replacement, and innovative riserless light well intervention ("RLWI") programme, to restore gas lift and access additional reservoir sands;
Drilled the first infill well on Stag in six years, which successfully came on production at 1,400 bbls/d in line with pre-drill expectations, producing throughout the year as planned; and
2P reserves at December 31, 2019 of 41.8 mm bbls comprising both Stag and Montara, a decrease of 1.0 mm bbls from December 31, 2018. Inclusive of Maari's 2P reserves (as evaluated at the time of acquisition, net of planned 2019 production) Jadestone's 2P reserves have effectively increased 26% year-on-year to 54.0 mm bbls.

Outlook

The Company's maiden dividend payment to shareholders is on track for later in 2020, with a targeted range of US$7.5-12.5 million;
To further insulate the balance sheet in the wake of the COVID-19 pandemic, 2020 capital spending has been reduced by around 80% from US$160-190 million to US$30-35 million;
Ongoing downside oil price protection through the Company's capped swap, which provides a floor price of US$68.45/bbl (Dated Brent) through to September 30, 2020, on 50% of Montara planned production, excluding incremental oil price premia;
Project Clover, Jadestone's current Company-wide cost efficiency and capital saving programme, has to date identified incremental savings in 2020 of US$3-4/bbl that can be realised going forwards;
The Company's operating cashflow break even oil price for the remainder of 2020 is estimated to have been reduced to US$20/bbl. Unlevered free cashflow break even oil price for the same period is estimated to be below US$27/bbl;
Montara and Stag infill drilling has been deferred to coincide with a strengthening oil price environment, together with the potential to lock-in lower service costs next year;
2020 production guidance of 12,000 - 14,000 bbls/d for the year, adjusted to reflect a re-scheduling of Australia's infill wells into 2021 to maximise returns;
The Company has elected to defer entering into the mandated amended and enlarged reserves-based loan, given the reduced capital programme, with all existing debt repaid within 12 months based on current schedule;
AU$60.0 million locked in via forward exchange contracts at an AU$/US$ exchange rate of 0.6344, saving ~US$4.0 million versus the assumed costs in the 2020 work plan & budget;
Growth through the addition of an operated 69% interest in the Maari project, offshore New Zealand, with closing still expected in the second half of 2020; and
Ongoing pursuit of inorganic growth opportunities.

Paul Blakeley, President and CEO commented:

"I'm very pleased to report a transformational year for Jadestone in 2019, though it may well be overshadowed by the extraordinary circumstances that the world finds itself in today. The global economy has been dealt a huge blow by the COVID-19 pandemic, with significant oil demand destruction, exacerbated by OPEC+ disarray, and a lack of storage, such that we envisage a prolonged impact on oil pricing for which we need to be prepared. So, while I would like to reinforce how the Jadestone business has moved forward with a threefold increase in revenue to US$325 million, as well as US$177 million of operating cashflow, it's also important to emphasize that we have elected to defer 80% of our capital spend this year, in order to protect the balance sheet. We recently announced the deferral of the Nam Du/U Minh gas project in Vietnam by 12 months, and yesterday we confirmed that the two infill wells which were to be drilled this year in Australia will now be pushed back to 2021.

"In 2019, our Stag and Montara producing fields delivered an average increase in uptime performance of 12% to 80% overall, and operating costs came down by 20% in the same period to US$22.85/bbl. This was a result of a number of cost reduction and efficiency initiatives, with more to come in response to the current environment. In November last year we also announced the acquisition of the Maari project in New Zealand. So, while we balance prudence at this challenging time, with deferred drilling and a resulting downward guidance of 10% to production volumes this year, this is balanced by closing the Maari acquisition which will provide a 25% production increase next year.

"2019 also benefited from a threefold increase in crude oil sales, due largely to a full year of Montara production, enhanced by half of the produced volume being sold at US$72/bbl, and with strong premiums on top. This hedging programme will continue through to September this year and will be a major positive feature in our ability to generate positive free cash even at today's depressed prices down to US$20/bbl.

"Jadestone has acted quickly in response to the challenges imposed by the COVID-19 pandemic and put in place comprehensive procedures to ensure our operations remain unaffected, and can continue safely and efficiently. We have adjusted how we work both onshore and offshore to minimise the risk of infection and to protect the wellbeing of our people. Contingency plans for safe crew transfer, local housing for self-quarantine, and isolation and evacuation procedures are all in place.

"On a positive note, I would add that we will shortly publish a full annual report, and our first sustainability report which is part of our commitment to provide more information and transparency in our business. We will set comprehensive targets towards a sustainable future, which will be measured in parallel with operational and financial objectives, and will become a part of our core business ethos. This is important because we intend to be here for the long term, with a strategy that fits the times, and we are well positioned to benefit from the current challenging environment with both organic and inorganic opportunities. We have a strong balance sheet, which has grown significantly with gross cash at US$120 million at the end of March 2020, including a US$10 million bank guarantee, with remaining debt of US$37 million.

"Finally, due to its financial strength, the Company will pay its first dividend later this year as promised, will continue to work towards closing the Maari acquisition later in the second half of the year, and will also remain opportunistic for inorganic growth should the right opportunities emerge."

Operations update

Jadestone reported its first full year of results for the Montara Assets in 2019, following completion of the acquisition in late September 2018. Montara production averaged 10,483 bbls/d for the full year 2019, compared to 7,625 bbls/d for the post acquisition period September 28, 2018 to October 31, 2018, prior to the voluntary shut-in during November and December 2018, to address an inspection and maintenance backlog.

There were a total of six Montara liftings in 2019, resulting in total sales of 3,577,204 bbls, compared to the year ended December 31, 2018 which saw just one Montara lifting for total sales of 451,291 bbls.

During 2019, Jadestone conducted its first major investments on the Montara assets, including successfully installing replacement subsea umbilical cables. The umbilical cables are an essential part of the control system providing electrical power and control signals to the subsea well-heads, thereby enhancing long-term reliability of production from the subsea wells.

In addition, the Company conducted the innovative RLWI campaign at the Montara complex, undertaking a highly engineered scope of work to restore gas-lift to subsea wells, and to access additional reservoir sands. The RLWI programme achieved its objectives, completing the work at a substantially lower cost than would have been incurred using a more conventional jack-up drilling unit.

Production from the Stag oilfield averaged 3,049 bbls/d for the full year ended December 31, 2019, compared to 2,799 bbls/d for the year ended December 31, 2018. The increase was due to the Stag 49H infill well, which was drilled in May 2019 and initially produced at approximately 1,400 bbls/d upon completion, and thereafter at a rate averaging 838 bbls/d between May 22, to December 31, 2019. The additional production was partly offset by downtime associated with cyclones in 2019, and delays to workovers during the period that the 49H infill well was being drilled.

There were four Stag liftings in 2019, resulting in total sales of 918,961 bbls, compared to the year ended December 31, 2018 which saw five liftings and total sales of 1,031,763 bbls.

In Vietnam, the Company made substantial progress toward commercialising its Nam Du and U Minh gas fields, including completion of front end engineering and design work, selecting major suppliers, signing a heads of agreement in respect of key gas sales commercial terms, and submitting a field development plan ("FDP") in respect of the development. While the Company remains committed to developing the fields, in the absence of receipt of Vietnamese Government approvals of the FDP, and in light of prevailing market conditions due to COVID-19, the Company opted to delay any further work, and anticipates no further major spending on the project in 2020.

COVID-19 operational response

Jadestone has undertaken a thorough assessment of all aspects of its operations, and the specific risks and challenges posed by the COVID-19 pandemic. As an overarching principle, the Company will comply with local and international recommendations protecting the wellbeing of its people, and in turn to minimise the impact on its operations.

The Company has adjusted its offshore work rotation to reduce travel time and is providing local accommodation for personnel to self-isolate following cross-border travel in Australia. Health and wellness screening has been enhanced for all operational personnel, including pre-duty temperature checks and staff questionnaires. Offshore work plans have been modified to defer non-essential activity wherever possible, such that manning can be kept to a minimum in order to provide crew flexibility and additional cover in the event of any infection. Isolation and evacuation procedures are in place.

To this point, the Company has not experienced any disruptions to its offshore operations due to the COVID-19 pandemic. Jadestone is in frequent discussions with the relevant Australian Government and regulatory authorities and continues to execute key projects to enhance efficiency while operating within the requirements of its safety cases. As the public health response to COVID-19 remains fluid, Jadestone has designated a pandemic manager at each location, to ensure a coordinated and principled response to evolving business requirements.

Jadestone recognises that ongoing safe operations rely on a working supply chain to ensure provision of critical equipment, consumables, and services. The Company is maintaining a rolling six-month work plan for all offshore work and believes it is carrying a sufficient local inventory of critical spares to safeguard operations. However, in light of the potential for unforeseen disruptions to the supply chain, the Company has implemented additional new measures to enhance logistics support and transportation, including closer cooperation with nearby operators.

Jadestone has also implemented a travel ban, and work-from-home routines are in place, as an extension to the Company's standard operating model which relies on a distributed workforce. In addition, the Company has enhanced its support for personnel working from home to ensure efficient online collaboration, communications, and that decision-making can continue, as seamlessly as possible.

Reserves

An independent third-party reserves evaluator, ERCE, has audited Jadestone's Montara reserves and reviewed the Stag reserves, as of December 31, 2019 in a report dated April 23, 2020. As of December 31, 2019, the Company had proved oil reserves of 25.1 mm bbls, a decrease of 0.2 mm bbls from December 31, 2018. On a 2P basis, the Company had 41.8 mm bbls of oil reserves at December 31, 2019, decreased by 1.0 mm bbls from December 31, 2018. The difference in reserves reflects the impact of oil production during the year largely offset by reserves upgrades due to strong reservoir performance, as well as including technical revisions relating to an additional future infill well being included in the Company's future production profile.

The Company's reserves value, based on after income tax values of future net revenues discounted at 10% were evaluated to be US$253 million for proved reserves, and US$549 million on a 2P basis, as of December 31, 2019.

The Company's Statement of Reserves Data and Other Oil and Gas Information for the fiscal year ended December 31, 2019 is available at www.sedar.com .

Financial update

Revenue for the year was US$325.4 million, compared to US$113.4 million in 2018. The variance of US$212.0 million was predominately due to an increase in sales volumes, to 4,496.2 mbbls in calendar 2019, compared to 1,683.1 mboes in calendar 2018.

Revenue for Q4 2019 was US$91.2 million, compared to US$45.0 million for Q4 2018, or an increase of US$46.2 million, predominately due to higher liftings in the quarter of 1,266.3 mbbls, compared to 657.2 mbbls in Q4 2018.

Full year production costs for 2019 were US$119.9 million, compared to US$90.9 million in the year ended December 31, 2018. The variance of US$29.0 million was predominately due to an increase in Montara's production costs by US$41.7 million, due to a full calendar year of ownership in 2019, compared to the period September 28, 2018 to December 31, 2018, and partly offset by a decrease in Stag's production costs of US$10.1 million, in part due to the adoption of IFRS16 relating to treatment of leases, in addition to movements in closing inventory.

On a per barrel basis, and excluding workovers, but including lease costs related to operations, this results in full year 2019 costs of US$22.85/bbl, compared to US$28.72/boe for the full year 2018.

Production costs for Q4 2019 were US$25.9 million, compared to US$50.6 million in Q4 2018, with the comparable period abnormally high partly due to repairs and maintenance incurred during the Montara shut-down between November to December 2018, leases recognised in production costs prior to the adoption of IFRS16 on January 1, 2019, and crude inventory movements.

On a per barrel basis, and excluding workovers, this results in Q4 2019 unit opex of US$20.26/bbl, compared to US$28.94/bbl in Q4 2018.

For the full year, the Company reports adjusted positive EBITDAX of US$187.5 million, compared to US$10.2 million for 2018, demonstrating how transformative 2019 was in terms of cash generation. Jadestone generated adjusted positive EBITDAX of US$59.9 million for Q4 2019, compared to an EBITDAX loss of US$1.7 million for the same quarter a year ago.

For the full year, the Company generated positive operating cash flows before movements in working capital, interest and taxes of US$176.7 million, compared to a use of US$0.3 million in the year ended December 31, 2018. In Q4 2019, the Company generated positive operating cash flow of US$58.0 million, compared to a use of cash of US$6.2 million in Q4 2018.

Full year 2019 unadjusted profit before tax was US$73.3 million, compared to a net loss before tax of US$21.5 million in 2018. Q4 2019 profit before tax was US$27.1 million, compared to a loss of US$4.9 million in the quarter ending December 31, 2018.

2019 profit after tax was US$40.5 million, compared to a loss in the prior year of US$31.0 million. Net profit after tax for Q4 2019 was US$10.4 million, compared to a loss of US$6.6 million for Q4 2018, predominately due to the shut in of Montara during November and December 2018, compared to a full quarter's results in 2019.

At year end, the Company had US$89.4 million of cash, and a further US$10.0 million of cash in support of a bank guarantee. With gross debt outstanding of US$49.1 million, this translates to a total net cash balance of US$40.3¹ million, and compares to total net debt of US$30.2 million at December 31, 2018.

By the end of March 2020, total outstanding interest bearing debt had fallen to US$37.3 million versus total cash of US$109.4 million, again excluding the US$10.0 million cash in support of a bank guarantee, resulting in a net cash balance of US$72.1 million.

The Company's existing capped swap provides robust support for ongoing cash generation establishing, as it does, a floor benchmark crude oil price of US$68.45/bbl for approximately one third of the Company's production through to September 30, 2020, and excluding incremental oil price premia.

¹ Gross debt and net debt/cash are non-GAAP measures which do not have a standardised meaning prescribed by IFRS. These measures are included because management uses this information to analyse the liquidity and financial position of the group and it may be useful to investors on the same basis. Gross debt and net debt/cash are non-GAAP measures and should not be considered an alternative to, or more meaningful than 'Net increase in cash and cash equivalents' as determined in accordance with IFRS, as an indicator of liquidity and financial performance. Gross debt is defined as long and short term interest bearing debt, and excludes derivatives. Net debt/cash is defined as cash and cash equivalents including the Montara assets' minimum working capital cash balance of US$15 million required to be maintained under the conditions of the reserve based lending facility and restricted cash of US$13.5 million under the debt service reserve account. The restricted cash excludes the US$10 million deposited in support of a bank guarantee to a key supplier of the Stag FSO. Because non-GAAP financial measures do not have a standardised meaning prescribed by IFRS, they are unlikely to be comparable to similar measures presented by other companies and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS.

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, 2019.

Quarterly comparison	Dec 2019 quarter	Dec 2018 quarter	Change (%)
Production, mbbls	1,352.6	479.7	181.9%
Sales, mbbls	1,266.3	657.2	92.7%
Avg realised liquids price¹, US$/bbl	69.24	67.51	2.6%
Sales revenue¹, US$ million	91.2	45.0	102.7%
Capital expenditure², US$ million	5.1	7.6	(32.9)%
Quarterly comparison	Dec 2019 quarter	Sep 2019 quarter	Change (%)
Production, mbbls	1,352.6	1,199.3	12.8%
Sales, mbbls	1,266.3	891.6	42.0%
Avg realised liquids price¹, US$/bbl	69.24	65.36	5.9%
Sales revenue¹, US$ million	91.2	62.5	45.9%
Capital expenditure², US$ million	5.1	20.9	(75.5)%
Yearly comparison	Year to Dec 2019	Year to Dec 2018	Change (%)
Production, mboe³	4,938.9	1,480.8	233.5%
Sales, mboe³	4,496.2	1,683.1	167.1%
Avg realised liquids price¹, US$/boe³	69.07	69.39	(0.5%)
Sales revenue¹, US$ million	325.4	113.4	186.9%
Capital expenditure², US$ million	57.2	10.0	470.2%

¹ Revenue has been restated from gross to net after deducting royalties, but including the effective gain on hedging contracts

² Payment for oil and gas property, plant and equipment and intangible exploration assets. In 2019 excludes the RLWI/major spend elements that are reported under opex. Also excludes acquisition related capital expenditure

³ 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

Conference call and webcast

The management team will host an investor and analyst conference call at 4:00 p.m. (Singapore), 9:00 a.m. (London), and 4:00 a.m. (Toronto) today, Thursday, April 23, 2020, 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, 2019 will be available on the Company's website at: www.jadestone-energy.com/investor-relations/ .

Webcast link: https://produceredition.webcasts.com/starthere.jsp?ei=1304879&tp_key=4e7f200c5f
Event conference title: Jadestone Energy Inc. - Fourth Quarter Results
Start time: 4:00 p.m. (Singapore), 9:00 a.m. (London), 4:00 a.m. (Toronto)
Date: Thursday, April 23, 2020
Conference ID: 55792013

Country	Dial-In Numbers
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
New Zealand	0800453421
Singapore	8001013217
Switzerland	0800312635
Switzerland (Mobile)	0800312635
United Kingdom	08006522435
United States (Toll free)	888 390 0605

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	+44 7392 940 495
Robin Martin, Investor Relations Manager	ir@jadestone-energy.com

Stifel Nicolaus Europe Limited (Nomad, Joint Broker)	+44 (0) 20 7710 7600 (UK)
Callum Stewart
Simon Mensley
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 the Stag oilfield and the Montara project, both offshore Australia. Both the Stag and Montara assets include oil producing fields, with further development and exploration potential. The Company has a 100% operated working interest 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. In addition, the Company has executed a sale and purchase agreement to acquire an operated 69% interest in the Maari Project, shallow water offshore New Zealand, and anticipates completing the transaction in H2 2020, upon receipt of customary approvals.

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 in the Asia Pacific region.

Jadestone Energy Inc. is listed on the AIM market of the London Stock Exchange. 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 the Company's intent to defer its Australia infill drilling campaign into 2021, expected reductions to capital spending, 2020 average production, 2021 production growth and the timing and payment of a dividend.

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.

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 19 years, has read and approved the technical 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. Upon the publication of this announcement, this inside information is now considered to be in the public domain.

Glossary

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
mbbl thousands of barrels of oil
mboe thousands of barrels of oil equivalent
mm bbls millions of barrels of oil

Jadestone Energy Inc.

CONSOLIDATED FINANCIAL STATEMENTS

for the years ended December 31, 2019 and December 31, 2018

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") as issued by the International Accounting Standards Board, 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 and authorised for issue on April 23, 2020.

"A. Paul Blakeley"							"Daniel Young"
A. Paul Blakeley							Daniel Young
Director							Director
April 23, 2020							April 23, 2020

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, 2019 and 2018, 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 years ended December 31, 2019 and 2018, 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 position of Jadestone Energy Inc. as at December 31, 2019 and 2018, and its financial performance and its cash flows for the years ended December 31, 2019 and 2018, 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.

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, 2019, the Group recorded US$383.0 million of oil and gas properties and US$59.0 million of right-of-use assets associated with these properties, which approximate 51% and 8% respectively relative to 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 as at 31 December 2019.

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, 2019 and its future plans for these assets. Management, who is ultimately responsible to the third party estimates, 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.

Since December 31, 2019, the oil price has fallen sharply in large part due to the impact of the international spread of COVID-19 and geopolitical factors. Management has assessed that this is a non-adjusting post balance sheet event in accordance with IAS 10 Events after the reporting period and has made disclosures in Note 41.

Our audit procedures focused on evaluating impairment indicators in accordance with IAS 36 Impairment of assets, 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;

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

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

• Challenging management's oil 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.

As part of our post balance sheet date audit procedures, we considered whether the COVID-19 pandemic and geopolitical factors provide evidence of conditions that existed at the balance sheet date. Based on our procedures covering the facts and circumstances, we concurred with management that it is a non-adjusting event and disclosures surrounding the impact of the events had been appropriately disclosed in Note 41.

Key Audit Matters

How the matter was addressed in the audit

Impairment assessment of intangible exploration assets

As at December 31, 2019, the Group recorded US$116.1 million of intangible exploration assets, which approximate 15% of the Group's total assets.

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

Based on management's assessment, there were no impairment indicators identified as at December, 31 2019.

Notwithstanding the above, as the intangible exploration assets represent 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.

Management, who is ultimately responsible for third party estimates, have 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.

Since December 31, 2019, the oil and gas price has fallen sharply in large part due to the impact of the international spread of COVID-19 and geopolitical factors. Management has assessed that this is a non-adjusting post balance sheet event in accordance with IAS 10 Events after the reporting period and has made disclosures in Note 41.

Our audit procedures focused on evaluating and challenging the judgements and key assumptions used by management in performing the impairment review under IFRS 6 Exploration for and evaluation of mineral resources. 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;

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

• Checking the reserve reports prepared by the 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.

As part of our post balance sheet audit procedures, we have considered whether the COVID-19 pandemic and geopolitical factors provide evidence of conditions that existed at the balance sheet date. Based on our procedures, we concurred with management that it is a non-adjusting event and disclosures surrounding the impact of the events had been appropriately disclosed in Note 41.

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

Other Information

Management is responsible for the other information. The other information comprises:

• Management's Discussion and Analysis; and

• The information, other than the financial statements and our auditor's report thereon, in the Annual Report.

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 identified above and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated.

We obtained Management's Discussion and Analysis prior to the date of this auditor's report. If, based on the work we have performed on this other information, 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.

The information, other than the financial statements and the auditors' report thereon, in the Annual Report is expected to be made available to us after the date of this auditor's report. If, based on the work we will perform on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact to those charged with governance.

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.

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.

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 23, 2020

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

for the years ended December 31, 2019 and December 31, 2018

	Notes	2019 USD'000	2018 Restated USD'000

Consolidated statement of profit or loss

Revenue	4	325,406	113,423
Production costs	5	(119,898)	(90,939)
Depletion, depreciation and amortisation	6	(90, 746 )	(13,776)
Staff costs	8	(19, 714 )	(13,538)
Other expenses	9	(11,692)	(10,374)
Impairment of assets	10	-	(11,901)
Other income	11	2,979	2,534
Finance costs	12	(16,443)	(9,240)
Other financial gains	13	3,389	12,345

Profit/(Loss) before tax		73,281	(21,466)
Income tax expense	14	( 32 , 776 )	(9,567)

Profit/(Loss) for the year		40,505	(31,033)

Earnings/(Loss) per ordinary share
Basic and diluted (US$)	15	0.09	(0.10)

Consolidated statement of comprehensive income

Profit/(Loss) for the year		40,505	(31,033)

Other comprehensive (loss)/income
Items that may be reclassified subsequently to profit or loss:
(Loss)/Gain on unrealised cash flow hedges	26	(30,542)	51,775
Hedging gain reclassified to profit or loss		(14,874)	(1,088)

		(45,416)	50,687
Tax income/(expense) relating to components of other comprehensive (loss)/income	14	13,624	(15,207)

Other comprehensive (loss)/income		(31,792)	35,480

Total comprehensive income for the year		8,713	4,447

Certain 2018 comparative information has been restated, as a result of reclassifications between line items. Please refer to Note 43.

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

for the years ended December 31, 2019 and December 31, 2018

	Notes	2019 USD'000	2018 Restated USD'000

Assets

Non-current assets
Intangible exploration assets	16	116,096	95,607
Oil and gas properties*	17	383,018	430,193
Plant and equipment	18	1,780	1,709
Right-of-use assets	19	59,787	-
Derivative financial instruments	36	-	15,339
Restricted cash	24	17,477	23,561
Deferred tax assets	21	16,012	21,287

Total non-current assets		594,170	587,696

Current assets
Inventories*	22	31,411	15,822
Trade and other receivables	23	42,283	32,800
Derivative financial instruments	36	5,275	35,985
Restricted cash	24	6,008	5,083
Cash and cash equivalents	24	75,934	52,981

Total current assets		160,911	142,671

Total assets		755,081	730,367

Equity and liabilities

Equity

Capital and reserves
Share capital	25	466,573	466,562
Share-based payments reserve	27	23,857	22,375
Hedging reserves	26	3,688	35,480
Accumulated losses		(268,651)	(309,156)

Total equity		225,467	215,261

Non-current liabilities
Provisions	28	280,418	284,300
Borrowings	31	7,328	49,420
Secured convertible bonds	32	-	-
Lease liabilities	29	42,533	-
Other payable	30	359	3,748
Deferred tax liabilities	21	64,825	92,468

Total non-current liabilities		395,463	429,936

* The comparative information has been restated for 2018 as a result of IFRS 3 adjustment to the purchase price allocation of the Montara assets acquisition, see further in Notes 7 and 43.

Certain 2018 comparative information has been restated, as a result of reclassifications between line items. Please refer to Note 43.



	Notes	2019 USD'000	2018 Restated USD'000

Current liabilities
Borrowings	31	41,795	52,393
Lease liabilities	29	19,739	-
Trade and other payables*	35	27,962	31,493
Tax liabilities		44,655	1,284

Total current liabilities		134,151	85,170

Total liabilities TOTAL EQUITY AND LIABILITIES		529,614	515,106

Total equity and liabilities		755,081	730,367

* The comparative information has been restated for 2018 as a result of IFRS 3 adjustment to the purchase price allocation of the Montara assets acquisition, see further in Notes 7 and 43.

Certain 2018 comparative information has been restated, as a result of reclassifications between line items. Please refer to Note 43.

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

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

for the years ended December 31, 2019 and December 31, 2018

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

As at January 1, 2018	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 25)	102,096	-	-	-	102,096

Total transactions with owners, recognised directly in equity	102,096	520	-	-	102,616

As at December 31, 2018/ January 1, 2019	466,562	22,375	35,480	(309,156)	215,261

Profit for the year	-	-	-	40,505	40,505
Other comprehensive loss for the year	-	-	(31,792)	-	(31,792)

Total comprehensive income for the year	-	-	(31,792)	40,505	8,713

Share-based compensation, representing transaction with owners, recognised directly in equity	-	1,482	-	-	1,482
Shares issued, net of transaction costs (Note 25)	11	-	-	-	11

Total transactions with owners, recognised directly in equity	11	1,482	-	-	1,493

As at December 31, 2019	466,573	23,857	3,688	(268,651)	225,467

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF CASH FLOWS

for the years ended December 31, 2019 and December 31, 2018

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

	Notes	2019 USD’000	2018 USD’000

Operating activities
Profit/(Loss) before tax		73,281	(21,466)
Adjustments for:
Depletion, depreciation and amortisation	6	75,870	13,776
Depreciation of right-of-use assets	6 / 19	14,876	-
Other finance costs	12	10,376	6,272
Interest expense	12	6,067	2,968
Share-based payments	8	1,482	520
Loss/(Gain) on ineffective hedge recycled to profit or loss	9 / 11	633	(637)
Oil and gas properties written off	17	533	-
Change in fair value of contingent payments	13	(3,389)	(12,057)
Change in Stag FSO provision	11	(1,717)	(835)
Interest income	11	(1,260)	(422)
Unrealised foreign exchange gain	11	(8)	-
Gain on early repayment of convertible bonds	13	-	(288)
Impairment of intangible exploration assets	10	-	11,901

Operating cash flows before movements in working capital		176,744	(268)

Increase in trade and other receivables		(9,483)	(3,918)
(Increase)/Decrease in inventories		(7,346)	15,752
(Decrease)/Increase in trade and other payables		(12,431)	14,856

Cash generated from operations		147,484	26,422

Release of restricted cash for Ogan Komering		-	729
Interest paid		(4,698)	(2,263)
Tax refunded/(paid)		1,851	(7,125)

Net cash generated from operating activities		144,637	17,763

Investing activities
Acquisition of Montara	7	-	(133,092)
Payment for oil and gas properties	17	(45,161)	(6,968)
Payment for plant and equipment	18	(502)	(1,437)
Proceeds from disposal of plant and equipment		4	-
Payment for intangible exploration assets	16	(11,589)	(1,635)
Transfer from/(to) debt service reserve account	24	5,159	(18,644)
Interest received	11	1,260	422

Net cash used in investing activities		(50,829)	(161,354)











	Notes	2019 USD’000	2018 USD’000

Financing activities
Net proceeds from issuance of shares	25	11	102,096
Net drawdown from borrowings	31	-	118,040
Repayment of borrowings	33	(54,203)	(17,761)
Repayment of lease liabilities	33	(16,671)	-
Payment of bond facility and stand-by fees	32 / 33	-	(17,514)

Net cash (used in)/generated from financing activities		(70,863)	184,861

Net increase in cash and cash equivalents		22,945	41,270

Effect of translation on foreign currency cash and cash balances		8	1,261

Cash and cash equivalents at beginning of the year		52,981	10,450

Cash and cash equivalents at end of the year	24	75,934	52,981

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

Jadestone Energy Inc.

SIGNIFICANT ACCOUNTING POLICIES AND

EXPLANATION NOTES TO THE FINANCIAL STATEMENTS

for the years ended December 31, 2019 and December 31, 2018

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 AIM, a market by the London Stock Exchange. The Company was listed on the TSX-V throughout 2019 but delisted on March 25, 2020. The Company trades 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 (Stag) and Vulcan basins (Montara), offshore Western Australia.

On November 18, 2019, the Group executed a sale and purchase agreement ("SPA") with Österreichische Mineralölverwaltungs Aktiengesellschaft New Zealand ("OMV New Zealand") to acquire an operated 69% controlling interest in the Maari project for a total consideration of US$50.0 million (subject to customary working capital adjustments). The transaction is subject to regulatory approvals and joint venture partners' acceptance. Following these approvals, the transaction will close and control of the Maari project will transfer to the Group. The economic benefits from January 1, 2019 until the closing date will be adjusted in the final consideration price. The Group anticipates to complete the acquisition in second half of 2020.

The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower, Singapore 079909. The registered office of the Company is 10^th 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 from selling 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 IFRS 16 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.

Adoption of new and revised standards

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

In the current year, the Group has applied IFRS 16 Leases (as issued by the IASB in January 2016) that is effective for annual periods that begin on or after January 1, 2019.

IFRS 16 introduces new or amended requirements with respect to lease accounting. It introduces significant

changes to lessee accounting by removing the distinction between operating and finance lease and requiring the recognition of a right-of-use asset and a lease liability at commencement for all leases, except for short-term leases and leases of low value assets when such recognition exemptions are adopted. In contrast to lessee accounting, the requirements for lessor accounting have remained largely unchanged. Details of these new requirements are described in the "Leases" policy. The impact of the adoption of IFRS 16 on the Group's consolidated financial statements is described below.

The date of initial application of IFRS 16 for the Group is January 1, 2019.

The Group has applied IFRS 16 using the cumulative catch-up approach which measures asset at amount equal to liability (adjusted for accruals and prepayments). Please refer to (c) for the finance impact on the initial application of IFRS 16.

(a) Impact of the new definition of a lease

The Group has made use of the practical expedient available on transition to IFRS 16 not to reassess whether

a contract is or contains a lease. Accordingly, the definition of a lease in accordance with IAS 17 and IFRIC 4 will continue to be applied to those leases entered or changed before January 1, 2019.

The change in definition of a lease mainly relates to the concept of control. IFRS 16 determines whether a contract contains a lease on the basis of whether the customer has the right to control the use of an identified asset for a period of time in exchange for consideration. This is in contrast to the focus on 'risks and rewards' in IAS 17 and IFRIC 4.

The Group applies the definition of a lease and related guidance set out in IFRS 16 to all lease contracts entered into or changed on or after January 1, 2019 (whether it is a lessor or a lessee in the lease contract). The Group has reviewed the new definition in IFRS 16, and concluded that it will not significantly change the scope of contracts that meet the definition of a lease for the Group.

(b) Impact on lessee accounting

(i) Former operating leases

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

Applying IFRS 16, for all leases (except as noted below), the Group:

- Recognises 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;

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

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

Under IFRS 16, right-of-use assets are tested for impairment in accordance with IAS 36.

For short-term leases (lease term of 12 months or less) and leases of low-value assets (which includes personal computers, small items of office furniture and telephones), the Group has opted to recognise a lease expense on a straight-line basis as permitted by IFRS 16. This expense is presented within 'other expenses' in profit or loss.

The Group has used the following practical expedients when applying the cumulative catch-up approach to leases previously classified as operating leases applying IAS 17.

- The Group has applied a single discount rate to a portfolio of leases with reasonably similar characteristics.

- The Group has elected not to recognise right-of-use assets and lease liabilities to leases for which the lease term ends within 12 months of the date of initial application.

- The Group has excluded initial direct costs from the measurement of the right-of-use asset at the date of initial application.

- The Group has used hindsight when determining the lease term when the contract contains options to extend or terminate the lease.

The weighted average lessees incremental borrowing rate applied to lease liabilities recognised in the statement of financial position on January 1, 2019 is 8.6%.

The following table shows the operating lease commitments disclosed in Note 34 applying IAS 17 at December 31, 2018, discounted using the incremental borrowing rate at the date of initial application and the lease liabilities recognised in the statement of financial position at the date of initial application.

		USD’000
Operating lease commitments as at December 31, 2018		43,595
Short-term leases and leases of low-value assets		(50)
Effect of discounting the above amounts		(8,157)
Present value of the lease payments due in periods covered by extension options that are included in the lease term and not previously included in operating lease commitments		462
Lease liabilities recognised as at January 1, 2019		35,850

The Group has recognised US$35.9 million of right-of-use assets and US$35.9 million of lease liabilities upon transition to IFRS 16. In the current year, the Group has applied a number of amendments to IFRS Standards and Interpretations issued by the IASB that are effective for an annual period that begins on or after January 1, 2019. Their adoption has not had any material impact on the disclosures or on the amounts reported in these financial statements.

New and revised IFRSs in issue but not yet effective

In the current year, the Group has not applied the following amendments to IFRS Standards and Interpretations issued by the IASB that are effective for an annual period that begins on or after January 1, 2020:

- Amendments to IFRS 3 Business Combinations;

- Amendments to IAS 1 and IAS 8 Definition of Material; and

- Amendments to References to the Conceptual Framework in IFRS Standards.

All amendments are effective for annual periods beginning on or after January 1, 2020 and generally require prospective application.

The Group is currently performing an assessment of the impact of these amendments and anticipates potential material impact on the financial statements of the Group in future periods as described below:

Amendments to IFRS 3 Business Combinations

The amendments clarify that while businesses usually have outputs, outputs are not required for an integrated set of activities and assets to qualify as a business. To be considered a business an acquired set of activities and assets must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs.

Additional guidance is provided that helps to determine whether a substantive process has been acquired.

The amendments introduce an optional concentration test that permits a simplified assessment of whether an acquired set of activities and assets is not a business. Under the optional concentration test, the acquired set of activities and assets is not a business if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar assets.

The amendments are applied prospectively to all business combinations and asset acquisitions for which the

acquisition date is on or after the first annual reporting period beginning on or after January 1, 2020, with early application permitted.

Amendments to IAS 1 and IAS 8 Definition of Material

The amendments are intended to make the definition of material in IAS 1 easier to understand and are not

intended to alter the underlying concept of materiality in IFRS Standards. The concept of 'obscuring' material

information with immaterial information has been included as part of the new definition.

The threshold for materiality influencing users has been changed from 'could influence' to 'could reasonably be expected to influence'.

The definition of material in IAS 8 has been replaced by a reference to the definition of material in IAS 1. In addition, the IASB amended other Standards and the Conceptual Framework that contain a definition of material or refer to the term 'material' to ensure consistency.

The amendments are applied prospectively for annual periods beginning on or after January 1, 2020, with earlier application permitted.

Amendments to References to the Conceptual Framework in IFRS Standards

Together with the revised Conceptual Framework, which became effective upon publication on March 29, 2018, the IASB has also issued Amendments to References to the Conceptual Framework in IFRS Standards. The document contains amendments to IFRS 2, IFRS 3, IFRS 6, IFRS 14, IAS 1, IAS 8, IAS 34, IAS 37, IAS 38, IFRIC 12, IFRIC 19, IFRIC 20, IFRIC 22, and SIC-32.

Not all amendments, however, update those pronouncements with regard to references to and quotes from the framework so that they refer to the revised Conceptual Framework. Some pronouncements are only updated to indicate which version of the Framework they are referencing to (the IASC Framework adopted by the IASB in 2001, the IASB Framework of 2010, or the new revised Framework of 2018) or to indicate that definitions in the Standard have not been updated with the new definitions developed in the revised Conceptual Framework.

The amendments, where they actually are updates, are effective for annual periods beginning on or after January 1, 2020, with early application permitted.

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; and

- 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. Measurement period adjustments are adjustments that arise from additional information obtained during the 'measurement period' (which cannot exceed one year from the acquisition date) about facts and circumstances that existed at the acquisition date. 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 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 at 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 at 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 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 licence, concessions and other exploration rights are expensed in profit or 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 depleting the remaining carrying value of the asset over the remaining expected future production. If reserves estimates are revised downwards, earnings could be affected by higher depletion 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 its 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 within oil and gas properties.

The change in net present value of future obligations, due to the 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 or 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; and

- Fixtures and equipment: 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.

Right-of-use assets are depreciated over the shorter period of the lease term and the useful life of the underlying asset. If a lease transfers ownership of the underlying asset or the cost of the right-of-use asset reflects that the Group expects to exercise a purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset.

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 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.

INVENTORIES

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 or 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 or 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 entirety 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.

Debt instruments that meet the following conditions are subsequently measured at fair value through other comprehensive income ("FVTOCI"):

- the financial asset is held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets; 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.

By default, all other financial assets are subsequently measured at fair value through profit or loss ("FVTPL").

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, 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.

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 or loss and is included in "other income" (Note 11) line item.

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 expenses" (Note 9) line item.

Impairment of financial assets

The Group's financial assets that are subject to the expected credit loss model comprise 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.

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 generally settled 30 days after sale date. In the event that an invoice is issued on a provisional basis then the final reconciliation is paid within 3 days of the issuance of the final invoice, largely mitigating 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, applying 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.

Significant increase in credit risk

In assessing whether the credit risk on a financial instrument has increased significantly since initial recognition, the Group compares the risk of a default occurring on the financial instrument as at the reporting date with the risk of a default occurring on the financial instrument as at the date of initial recognition. In making this assessment, the Group considers both quantitative and qualitative information that is reasonable and supportable, including historical experience and forward-looking information that is available without undue cost or effort. Forward-looking information considered includes the future prospects of the industries in which the Group's debtors operate, based on consideration of various external sources of actual and forecast economic information that relate to the Group's core operations.

In particular, the following information is taken into account when assessing whether credit risk has increased significantly since initial recognition:

- an actual or expected significant deterioration in the financial instrument's external (if available) or internal credit rating;

- significant deterioration in external market indicators of credit risk for a particular financial instrument, e.g. a significant increase in the credit spread, the credit default swap prices for the debtor, or the length of time or the extent to which the fair value of a financial asset has been less than its amortised cost;

- existing or forecast adverse changes in business, financial or economic conditions that are expected to cause a significant decrease in the debtor's ability to meet its debt obligations;

- an actual or expected significant deterioration in the operating results of the debtor;

- significant increases in credit risk on other financial instruments of the same debtor; and

- an actual or expected significant adverse change in the regulatory, economic, or technological environment of the debtor that results in a significant decrease in the debtor's ability to meet its debt obligations.

Despite the foregoing, the Group assumes that the credit risk on a financial instrument has not increased significantly since initial recognition if the financial instrument is determined to have low credit risk at the reporting date. A financial instrument is determined to have low credit risk if i) the financial instrument has a low risk of default, ii) the borrower has a strong capacity to meet its contractual cash flow obligations in the near term and iii) adverse changes in economic and business conditions in the longer term may, but will not necessarily, reduce the ability of the borrower to fulfil its contractual cash flow obligations.

The Group regularly monitors the effectiveness of the criteria used to identify whether there has been a significant increase in credit risk and revises them as appropriate to ensure that the criteria are capable of identifying significant increase in credit risk before the amount becomes past due.

Definition of default

The Group considers the following as constituting an event of default for internal credit risk management purposes as historical experience indicates that receivables that meet either of the following criteria are generally not recoverable:

- when there is a breach of financial covenants by the counterparty; or

- information developed internally or obtained from external sources indicates that the debtor is unlikely to pay its creditors, including the Group, in full (without taking into account any collaterals held by the Group).

Credit-impaired financial assets

A financial asset is credit-impaired when one or more events that have a detrimental impact on the estimated future cash flows of that financial asset have occurred. Evidence that a financial asset is credit-impaired includes observable data about the following events:

- significant financial difficulty of the issuer or the borrower;

- a breach of contract, such as a default or past due event;

- the lender(s) of the borrower, for economic or contractual reasons relating to the borrower's financial difficulty, having granted to the borrower a concession(s) that the lender(s) would not otherwise consider;

- it is becoming probable that the borrower will enter bankruptcy or other financial reorganisation; or

- the disappearance of an active market for that financial asset because of financial difficulties.

Write-off policy

The Group writes off a financial asset when there is information indicating that the counterparty is in severe financial difficulty and there is no realistic prospect of recovery, e.g. when the counterparty has been placed under liquidation or has entered into bankruptcy proceedings, or in the case of trade receivables, when the amounts are over one year past due, whichever occurs sooner. Financial assets written off may still be subject to enforcement activities under the Group's recovery procedures, taking into account legal advice where appropriate. Any recoveries made are recognised in profit or loss.

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 the simplified approach was used.

Derecognition 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 recognises a collaterialised borrowing for the proceeds received.

On derecognition 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 either "other financial gains" (Note 13) or "finance costs" (Note 12) line item 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.

Foreign exchange gain or loss

For financial liabilities that are denominated in a foreign currency and are measured at amortised cost at the end of each reporting period, the foreign exchange gains and losses are determined based on the amortised cost of the instruments. These foreign exchange gains and losses are recognised in the "other income"
(Note 11) or "other expenses" (Note 9) line item in profit or loss for financial liabilities that are not part of a designated hedging relationship. For those which are designated as a hedging instrument for a hedge of foreign currency risk, foreign exchange gains and losses are recognised in other comprehensive income and accumulated in a separate component of equity.

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. The 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 component are charged directly to equity. Transaction costs relating to the liability component are included in the carrying amount of the liability, and amortised over the period of the convertible loan using the effective interest method.

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

Derecognition 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 decognised, 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.

Derivatives are 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 36 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 26.

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 in either "other financial gains" (Note 13) or "finance costs"
(Note 12) line item.

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 revision 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

The Group has applied IFRS 16 using the cumulative catch-up approach and therefore comparative information has not been restated and is presented under IAS 17. The details of accounting policies under both IAS 17 and IFRS 16 are presented separately below.

Policies applicable from January 1, 2019

The Group as lessee

The Group assesses whether a contract is or contains a lease, at inception of the contract. The Group recognises a right-of-use asset and a corresponding lease liability with respect to all lease arrangements in which it is the lessee, except for short-term leases (defined as leases with a lease term of 12 months or less) and leases of low value assets (such as personal computers, small items of office furniture and telephones). For these leases, the Group recognises the lease payments as an operating expense on a straight-line basis over the term of the lease unless another systematic basis is more representative of the time pattern in which economic benefits from the leased assets are consumed.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted by using the rate implicit in the lease. If this rate cannot be readily determined, the lessee uses its incremental borrowing rate.

Lease payments included in the measurement of the lease liability comprise fixed lease payments (including in-substance fixed payments).

The lease liability is presented as a separate line in the consolidated statement of financial position.

The lease liability is subsequently measured by increasing the carrying amount to reflect interest on the lease

liability (using the effective interest method) and by reducing the carrying amount to reflect the lease payments made.

The Group remeasures the lease liability (and makes a corresponding adjustment to the related right-of-use asset) whenever:

- The lease term has changed or there is a significant event or change in circumstances resulting in a change in the assessment of exercise of a purchase option, in which case the lease liability is remeasured by discounting the revised lease payments using a revised discount rate.

- The lease payments change due to changes in an index or rate or a change in expected payment under a guaranteed residual value, in which cases the lease liability is remeasured by discounting the revised lease payments using an unchanged discount rate (unless the lease payments change is due to a change in a floating interest rate, in which case a revised discount rate is used).

- A lease contract is modified and the lease modification is not accounted for as a separate lease, in which case the lease liability is remeasured based on the lease term of the modified lease by discounting the revised lease payments using a revised discount rate at the effective date of the modification.

The Group did not make any such adjustments during the periods presented.

The right-of-use assets comprise the initial measurement of the corresponding lease liability, lease payments

made at or before the commencement day, less any lease incentives received and any initial direct costs. They are subsequently measured at cost less accumulated depreciation and impairment losses.

Whenever the Group incurs an obligation for costs to dismantle and remove a leased asset, restore the site on which it is located or restore the underlying asset to the condition required by the terms and conditions of the lease, a provision is recognised and measured under IAS 37. To the extent that the costs relate to a right-of-use asset, the costs are included in the related right-of-use asset, unless those costs are incurred to produce inventories.

Right-of-use assets are depreciated over the shorter period of lease term and useful life of the underlying asset. If a lease transfers ownership of the underlying asset or the cost of the right-of-use asset reflects that the Group expects to exercise a purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset. The depreciation starts at the commencement date of the lease.

The right-of-use assets are presented as a separate line in the consolidated statement of financial position.

The Group applies IAS 36 to determine whether a right-of-use asset is impaired and accounts for any identified impairment loss as described in the "Impairment of Assets" policy.

As a practical expedient, IFRS 16 permits a lessee not to separate non-lease components, and instead account

for any lease and associated non-lease components as a single arrangement. The Group has not used this practical expedient. For contracts that contain a lease component and one or more additional lease or non-lease components, the Group allocates the consideration in the contract to each lease component on the basis of the relative stand-alone price of the lease component and the aggregate stand-alone price of the non-lease components.

Policies applicable prior to January 1, 2019

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 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. In line with the aforementioned, revenue is recognised at a point in time when deliveries of the liquids are transferred to the customers.

Gas revenue is meter measured based on the hydrocarbon volumes delivered. The volumes delivered over a calendar month 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 and net of revenue.

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. Such deferred tax assets and liabilities are not utilised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

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. The measurement of deferred tax liabilities and assets reflects the tax consequences that would follow from the manner in which the Group expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities.

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 three 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.

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 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) Contingent consideration

The determination of 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 management 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 7.4.

b) Depletion of oil and gas properties

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

Estimates of the Group's oil and gas reserves are inherently uncertain. Proved plus probable reserves are the estimated volumes of crude oil and natural gas which geological and engineering data demonstrate that are most likely to be economically producible, from known reservoir under existing economic conditions and operating method. Changes in proved plus probable oil and gas reserves, and the associated expected development capital, will affect units of production depletion in the Group's consolidated financial statements for oil and gas properties. Proved plus oil and gas reserves are subject to revision, based on new information, such as from development drilling and production activities, or from changes in economic factors, including product prices, contract terms, evolution of technology or development plans, etc.

The carrying amount and depletion amount of oil and gas properties are disclosed in Note 17 and
Note 6, respectively.

c) 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 unutilised tax credits and unutilised 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 21 to the financial statements.

d) 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.

e) 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. For right-of-use assets, the Group applies IAS 36 to determine whether a right-of-use asset is impaired and accounts for any identified impairment loss as described in the 'Impairment of Assets' policy. The carrying amounts of intangible exploration assets, oil and gas properties and right-of-use assets are disclosed in Notes 16, 17 and 19, respectively.

f) 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 and reviewed subsequently at the end of each reporting period. 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 28 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 is recognised at a point in time.

	2019 USD'000	2018 USD'000

Liquids revenue, after hedging
Stag	65,181	74,772
Montara	260,225	31,198
Ogan Komering	-	8,520

Gas revenue
Ogan Komering	-	2,482

	325,406	116,972

Royalties	-	(3,549)

Total revenue derived from contracts with customers, after hedging and net of royalties	325,406	113,423

Royalties in 2018 related to production entitlement in Indonesia. The Ogan Komering PSC expired on
May 20, 2018 and hence no revenue and no production royalty entitlement is recognised in the current year.

5. PRODUCTION COSTS

	2019 USD'000	2018 USD'000

Operating costs	52,527	48,887
Workovers	30,331	10,577
Logistics	20,635	9,034
Repairs and maintenance	23,742	5,117
Movement in inventories	(7,337)	17,324

	119,898	90,939

The cost of inventories recognised in production costs is US$92.4 million (2018: US$61.0 million). In 2018, the Group had written down crude oil amounting to US$3.4 million to its net realisable value. The write down amount was recognised in production costs. There were no inventories write-down in FY2019.

The Group has adopted IFRS 16, effective January 1, 2019. The Group has recognised depreciation of right-of-use assets in 2019, as disclosed in Note 6. The lease payments paid were offset against lease liabilities.

The Group has applied the cumulative catch-up approach and did not restate comparatives. The lease payments included in 2018 operating costs were US$6.8 million.

The Montara assets were acquired on September 28, 2018. The production costs for 2018 include Montara's production costs of US$42.7 million from the date of acquisition until the year end, compared to a full year for 2019 of US$84.4 million.

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$90.9 million in 2018 is US$2.8 million related to Ogan Komering (Note 38).

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

	2019 USD'000	2018 USD'000

Depletion and amortisation (Note 17):
Stag	10,237	8,614
Montara	73,449	4,768
Ogan Komering	-	618

	83,686	14,000
Depreciation:
Plant and equipment (Note 18)	427	376
Right-of-use assets (Note 19)	14,876	-
Movement in inventories	(8,243)	(600)

	90,746	13,776

The Montara assets were acquired on September 28, 2018 and were shut down to address a maintenance and inspection backlog from November 1, 2018 to January 11, 2019. The depletion charge for the oil and gas properties for the comparative period related to the production from September 28 to October 31, 2018, compared to a full year for 2019.

The Ogan Komering DD&A charge in 2018 related to the production from January 1 to May 19, 2018, after which the Group no longer held an interest in the PSC.

7. ACQUISITION OF MONTARA ASSETS

7.1 Effective date and acquisition date

In 2018, Jadestone Energy (Eagle) Ltd, a wholly owned subsidiary of the Company, closed the acquisition of the Montara Assets from PTTEP Australia, obtaining control and 100% of legal ownership.

The transaction had an economic effective date of January 1, 2018, at which point the economic benefits of owning the Montara Assets passed to the Group. The transaction closed on September 28, 2018
(the Acquisition Date) at which point the Group obtained ownership and control of the Montara assets.
On May 30, 2019 the regulator approved the transfer of 99% of the legal title in the license. On August 6, 2019, the transfer of operatorship was completed and on October 1, 2019, the final 1% of legal title of the license was approved and the transaction was completed.

As the Group took control of the operating decisions of the Montara assets on September 28, 2018, this is the date used for the purpose of calculating the purchase price allocation and the fair value of the assets and liabilities recorded in the statement of financial position.

7.2 Fair value of consideration transferred and purchase price allocation adjustments

On September 28, 2018, the consideration for the 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 cash 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$195.0 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 cash adjustment reflects the net of the interim period receipts and expenses incurred, invoiced or paid by PTTEP Australia in the period from the effective date to the date of completion.

In addition, there were 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 are linked to 2018 production volumes, future Dated Brent oil prices in 2019 and 2020, production from the infill well drilling scheduled for 2020 and final investment decision for developments with significant 2P reserves. The Group reviewed all the contingent payments, and at the date of acquisition recorded an amount of US$15.8 million at fair value for the following two contingent events:

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

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

Management has assessed the fair value of the above contingent consideration using a Monte Carlo option simulation model, which considered inputs such as the spot Dated Brent oil price at completion date,
the risk-free rate, volatility of Dated Brent oil price, and the length of time the contingent payment will apply. This implies 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 in 2018. This reflected a discount of 46% and 50% for the respective 2019 and 2020 contingent consideration payments arising from the time value of money and the likelihood of the trigger event occurring. During the year, the Group has derecognised the 2019 deferred contingent payment as the annual average Dated Brent crude price in 2019 fell below US$80/bbl. Please refer to Note 7.4 for the full disclosure of all the other contingent payments and management's assessment therein. As at December 31, 2019, the fair value of the 2020 contingent payment has been reduced to US$0.4 million (2018: US$3.7 million) (Note 30) as a result of the declining forward curve Dated Brent crude oil price.

The voluntary shutdown that occurred at Montara from November 1, 2018 to January 11, 2019 resulted in a loss of production and revenue during the period, as well as an increase in costs due to overheads still being incurred and additional maintenance work required to rectify historic maintenance and inspection 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.

During the year, the Group has completed the purchase price allocation ("PPA") exercise to determine the fair values of the net assets acquired within the stipulated time period of 12 months from the acquisition date of September 28, 2018, in accordance with IFRS 3 Business Combinations. Following the transfer of operatorship on August 6, 2019, the Group was able to confirm an inventory adjustment of US$14.0 million in order to align with the Group's accounting policies. The adjusted fair values of identifiable assets and liabilities have been reflected in the consolidated statement of financial position as at December 31, 2018.

Below are the effects of the final PPA adjustments in accordance with IFRS 3:

Fair value of purchase consideration	Provisional PPA USD’000	Adjustments USD’000	Final PPA USD’000

Asset purchase price	195,000	-	195,000
Crude inventory value	6,657	-	6,657
Capital charge	6,982	-	6,982
Net cash adjustment	(75,547)	-	(75,547)

Cash payment on acquisition date	133,092	-	133,092
Deferred contingent consideration	15,805	-	15,805
Prepaid asset for future cash calls	(22,000)	-	(22,000)
Working capital adjustment	997	819	1,816

Total	127,894	819	128,713

Assets acquired and liabilities assumed at the date of acquisition:

	Provisional PPA USD’000	Adjustments USD’000	Final PPA USD’000

Asset
Non-current assets
Oil & gas properties	353,806	14,828	368,634
Current assets
Inventories	35,373	(14,009)	21,364
Prepayments	4,917	-	4,917

Total assets	394,096	819	394,915

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

Total liabilities	(266,202)	-	(266,202)

Net identifiable assets acquired	127,894	819	128,713

Please refer to Note 43 for a summary of the adjustment of comparative figures.

7.3 Impact of acquisition on the results of the Group

Included in 2018 revenue for the year and 2018 loss after tax for the year, were US$31.2 million and US$4.2 million, respectively, that were both attributable from the 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 comparable period, within "other expenses" (Note 9) in the consolidated statement of profit or loss and other comprehensive income.

Had the business combination been effected as 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 in 2018.

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.

7.4 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	Reversed during the year as the event was not triggered.
2.	The average Dated Brent price in the calendar year 2020 is US$80/bbl or higher	US$10 million	The fair value has been reduced to US$0.4 million as a result of declining Dated Brent crude oil price and the likelihood of the trigger event occurring.
3.	Montara infill well production is equal to or greater than 1.5mm 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 1.5mm 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	The 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 15.0mm bbls	US$60 million	The 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

	2019 USD'000	2018 USD'000

Wages, salaries and fees	13,764	10,555
Staff benefits in kind	4,468	2,463
Share-based compensation	1,482	520

	19,714	13,538

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

Headcount has increased during the year from 80 person to 197 person at the end of the year predominantly due to additional headcount required in Australia and in Vietnam as the Group prepared for project sanction of Nam Du and U Minh.

9. OTHER EXPENSES

	2019 USD’000	2018 USD’000

Professional fees/consultancies	6,510	6,568
Office costs	2,194	2,774
Travel and entertainment	834	811
Net loss on ineffective oil derivatives	633	-
Oil and gas properties written off	533	-
Net foreign exchange loss	173	-
Other expenses	815	221

	11,692	10,374

The Group has adopted IFRS 16, effective January 1, 2019. The Group has recognised depreciation for right-of-use assets in 2019 as disclosed in Note 6. The lease payments paid were offset against lease liabilities. The Group has applied the cumulative catch-up approach and did not restate comparatives. Lease payments included in 2018 office costs were US$0.9 million.

10. IMPAIRMENT OF ASSETS

2019

USD'000

2018

USD'000

Impairment of intangible exploration assets (Note 16)

11,901

In 2018, a review of exploration assets resulted in management deciding to impair and relinquish Block 127 in Vietnam at the end of its 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.

11. OTHER INCOME

	2019 USD’000	2018 USD’000

Interest income	1,260	422
Change in Stag FSO provision	1,717	835
Net foreign exchange gain	2	640
Net gain on ineffective oil derivatives	-	637

	2,979	2,534

12. FINANCE COSTS

	2019 USD’000	2018 USD’000

Interest expense	6,067	2,968
Accretion expense for asset retirement obligations (Note 28)	5,842	3,632
Interest expense on lease liabilities	4,280	-
Accretion expense for Stag FSO provision	110	179
Convertible bond facility fees (Note 32)	-	560
Bond accretion (Note 32)	-	706
Fair value loss on derivative liability (Note 32)	-	1,195
Other finance costs	144	-

	16,443	9,240

The accretion expense for asset retirement obligations for the Stag field and the Montara field recognised in 2019 has increased to US$5.8 million from US$3.6 million in 2018, reflecting a full year charge at Montara for 2019, as compared to 2018 for the period from September 28, 2018 to year end.

The Group has adopted IFRS 16, effective from January 1, 2019. Consequently, the Group has recognised interest expense on lease liabilities in 2019. The Group has applied the cumulative catch-up approach and did not restate comparatives. Lease payments made in 2018 were included in Note 5 and Note 9.

Interest expense includes interest incurred on the reserve based lending facility of US$6.1 million (2018: US$2.4 million), reflecting a full year charge in 2019 as compared to 2018 for the period from September 28, 2018 to year end. Interest expense in 2018 also included interest incurred on the Tyrus bond, which was repaid in August 2018, of US$0.6 million.

13. OTHER FINANCIAL GAINS

	2019 USD'000	2018 USD'000

Change in provisions - Montara contingent payments	3,389	12,057
Gain on early repayment of convertible bonds	-	288

	3,389	12,345

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 (see Note 7.4). The Group has derecognised the 2019 contingent payment as the average Dated Brent crude oil price in 2019 fell below US$80/bbl. The fair value of the remaining contingent payment has been reduced to US$0.4 million (2018: US$3.7 million), reflecting the lower forward curve for Dated Brent crude oil prices, and hence the lower likelihood of exceeding US$80/bbl in 2020.

14. INCOME TAX EXPENSE

	2019 USD'000	2018 USD'000

Current tax
Corporate tax	(43,370)	(2,188)
Petroleum resource rent tax ("PRRT")	1,850	(6,221)

	(41,520)	(8,409)
Deferred tax
Tax depreciation	20,285	(3,196)
Tax losses	(5,257)	2,812
PRRT	(6,284)	(774)

	8,744	(1,158)

	(32,776)	(9,567)

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%. Indonesian 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$1.1 million (2018: US$5.8 million) and incurred a net expense of US$4.4 million (2018: US$7.0 million). The Montara field has utilised PRRT carried forward credits of US$21.5 million and currently has US$3.1 billion (2018: US$2.9 billion) based on the Montara field's latest forecasted augmentation by management which is 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. Subsidiaries are resident for tax purposes in the territories in which they operate.

The tax expense on Group's profit/(loss) differ from the amount that would arise using the standard rate of income tax applicable in the countries of operation as explained below:

	2019 USD'000	2018 USD'000

Profit/(Loss) before tax	73,281	(21,446)

Tax calculated at the domestic tax rates applicable to the profit/loss in the respective countries (Australia 30%, Indonesia 48%*, Canada 27% and Singapore 17%)	(23,190)	2,364
Effects of non-deductible expenses	(5,152)	(7,013)
PRRT tax benefit/(expense)	6,284	(6,995)
Effect of PRRT tax (expense)/benefit	(10,718)	2,077

Tax expense for the year	(32,776)	(9,567)

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

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

	2019 USD'000	2018 USD'000

Other comprehensive income - deferred tax
Income tax (credit)/expense related to carrying amount of hedged item	(13,624)	15,207

15. EARNINGS/(LOSS) PER ORDINARY SHARE

The calculation of the basic and diluted profit/(loss) per share is based on the following data

	2019 USD’000	2018 USD’000

Profit/(Loss) for the purposes of basic and diluted per share, being the net profit/(loss) for the year attributable to equity holders of the Company	40,505	(31,033)

	2019 Number	2018 Number

Weighted average number of ordinary shares for the purposes of basic EPS	461,040,802	316,525,850
Effect of diluted potential ordinary shares - share options	2,512,719	-

Weighted average number of ordinary shares for the purposes of dilutive EPS	463,553,521	316,525,850

The calculation of diluted EPS for 2019 includes 2,512,719 of weighted average dilutive ordinary shares available for exercise from in-the-money vested options (2018: 400,264 of weighted average potential ordinary shares available for exercise from in-the-money vested options are excluded, as they are non-dilutive given the Group's loss from operations). Additionally, 607,821 of weighted average potential ordinary shares available for exercise are excluded, as they are out-of-the-money (2018: 546,973).

In 2018, the calculation of diluted EPS excludes 74,668,968 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. The secured convertible bond was fully repaid on August 15, 2018. Additionally, 2,631,982 of weighted potential ordinary shares available for exercise under vested options are not included given the Group's loss from continuing operations in 2018.

Earnings per share (US$)	2019	2018

- - Basic	0.09	(0.10)

- - Diluted	0.09	(0.10)

16. INTANGIBLE EXPLORATION ASSETS

	Total USD'000

Cost
As at January 1, 2018	193,294
Additions	1,835
Disposals	(99,522)

As at December 31, 2018/January 1, 2019	95,607
Additions	20,489

As at December 31, 2019	116,096







	Total USD'000

Impairments
As at January 1, 2018	87,621
Additions	11,901
Disposals	(99,522)

As at December 31, 2018/January 1, 2019/December 31, 2019	-

Net book value
As at December 31, 2018	95,607

As at December 31, 2019	116,096

For the purpose of the consolidated statement of cash flows, intangible exploration assets of US$8.9 million remained unpaid as at December 31, 2019 (2018: US$0.7 million).

17. OIL AND GAS PROPERTIES

	Total USD'000

Cost
As at January 1, 2018	75,863
Arising from the acquisition of businesses (Note 7)	353,806
Fair value adjustment (Note 7)	14,828
Changes in asset restoration obligations (Note 28)	6,353
Additions	6,968

As at December 31, 2018/January 1, 2019	457,818
Changes in asset restoration obligations (Note 28)	(8,117)
Additions	45,161
Written off	(533)

As at December 31, 2019	494,329

	Total USD'000

Accumulated depletion and amortisation
As at January 1, 2018	13,625
Charge for the year	14,000

As at December 31, 2018/January 1, 2019	27,625
Charge for the year	83,686
Written off	-

As at December 31, 2019	111,311

Net book value
As at December 31, 2018	430,193

As at December 31, 2019	383,018

18. PLANT AND EQUIPMENT

	Computer equipment USD'000	Fixtures and fittings USD'000	Total USD'000

Cost
As at January 1, 2018	1,180	1,024	2,204
Additions	1,192	245	1,437

As at December 31, 2018/January 1, 2019	2,372	1,269	3,641
Additions	452	50	502
Disposal	-	(4)	(4)

As at December 31, 2019	2,824	1,315	4,139

Accumulated depreciation
As at January 1, 2018	665	891	1,556
Charge for the year	310	66	376

As at December 31, 2018/January 1, 2019	975	957	1,932
Charge for the year	359	68	427
Disposal	-	-*	-*

As at December 31, 2019	1,334	1,025	2,359

Net book value
As at December 31, 2018	1,397	312	1,709

As at December 31, 2019	1,490	290	1,780

*Due to figures rounded to nearest thousand.

19. RIGHT-OF-USE ASSETS

	Production assets USD'000	Transportation and logistics USD'000	Buildings USD'000	Total USD'000

Cost
As at January 1, 2019	29,339	3,507	3,004	35,850
Additions	-	38,813	-	38,813

As at December 31, 2019	29,339	42,320	3,004	74,663

Accumulated depreciation
As at January 1, 2019	-	-	-	-
Charge for the year	5,334	8,519	1,023	14,876

As at December 31, 2019	5,334	8,519	1,023	14,876

Net book value
As at December 31, 2019	24,005	33,801	1,981	59,787

The Group leases several assets including the Stag FSO, helicopters, a supply boat, logistic facilities for Montara field, and buildings. The average lease term is 4 years.

The maturity analysis of lease liabilities is presented in Note 29.

	2019 USD'000

Amount recognised in profit or loss

Depreciation expense on right-of-use assets	14,876
Interest expense on lease liabilities	4,280
Expenses relating to short-term leases	11,748
Expense relating to leases of low value assets	15

20. INVESTMENTS IN SUBSIDIARIES AND INTERESTS IN JOINT OPERATIONS

The succeeding sections of this Note present the details of the principal 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 2019	% voting rights and shares held 2018	Nature of business

Jadestone Energy (Eagle) Pty Ltd	Australia	100	100	Production oil & gas
Jadestone Energy (Australia Holdings) Pty Ltd	Australia	100	100	Investment holdings
Jadestone Energy (Australia) Pty Ltd	Australia	100	100	Production oil & gas
Jadestone Energy (New Zealand Holdings) Ltd*	New Zealand	100	-	Investment holdings
Jadestone Energy (New Zealand) Ltd*	New Zealand	100	-	Exploration
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 (Philippines SC- 56) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Philippines SC- 57) Ltd	BVI	100	100	Exploration
Mitra Energy (Vietnam 05-1) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Nam Du) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Tho Chu) Pte Ltd	Singapore	100	100	Exploration

* Jadestone Energy (New Zealand Holdings) Ltd and Jadestone Energy (New Zealand) Ltd were incorporated on October 25, 2019 as part of the Maari acquisition.

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	2019	2018

Montara Oilfield	Indefinite	Jadestone Energy (Eagle) Pty Ltd	Australia	100	100
Stag Oilfield	Aug 25, 2039	Jadestone Energy (Australia) Pty Ltd	Australia	100	100
46/07	Jun 29, 2035	Mitra Energy (Vietnam Nam Du) Pte Ltd	Vietnam	100	100
51	Jun 10, 2040	Mitra Energy (Vietnam Tho Chu) Pte Ltd	Vietnam	100	100
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

21. DEFERRED TAX

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

	Australian PRRT USD'000	Tax depreciation USD'000	Derivatives financial instruments USD'000	Tax losses USD'000	Total USD'000

As at January 1, 2018	20,273	903	-	2,445	23,621
(Charged)/Credited 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/January 1, 2019	19,499	(80,730)	(15,207)	5,257	(71,181)
(Charged)/Credited to profit or loss	(6,284)	20,285	-	(5,257)	8,744
Credited to OCI	-	-	13,624	-	13,624

As at December 31, 2019	13,215	(60,445)	(1,583)	-	(48,813)

	2019 USD'000	2018 USD'000

Deferred tax liabilities	(64,825)	(92,468)
Deferred tax assets	16,012	21,287

	(48,813)	(71,181)

At the reporting date, the Group has unutilised tax losses of US$ Nil (2018: US$17.5 million) available for offset against future profits. The Group has unutilised PRRT credits of approximately US$3.1 billion (2018: 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 PRRT credits are utilised based on a last-in-first-out basis, the unutilised PRRT credits of approximately US$3.1 billion (2018: US$2.9 billion) will not be utilised given the forecasted augmentation, and are therefore not recognised as a deferred tax asset.

22. INVENTORIES

	2019 USD'000	2018 Restated USD'000

Materials and spares	8,964	8,955
Crude oil inventories	22,447	6,867

	31,411	15,822

23. TRADE AND OTHER RECEIVABLES

	2019 USD'000	2018 USD'000

Trade receivables	34,007	57
Prepayments	4,754	26,831
Other receivables and deposits	2,311	4,857
PRRT receivables	-	700
GST/VAT receivables	1,211	355

	42,283	32,800

Trade receivables represent revenues generated in Australia. The average credit period is 30 days (2018: 30 days). All outstanding receivables as at December 31, 2019 and December 31, 2018 have been fully recovered in 2020 and 2019, respectively.

Prepayments in 2018 includes US$22.0 million from PTTEP Australia (Note 7) relating to the Montara acquisition. The amount was fully recovered via cash calls in 2019.

The Group has derivative receivables of US$0.5 million (2018: US$3.4 million) within other receivables, which have been received in full in January 2020 (2018: January 2019). There is no significant increase in credit risk since initial recognition.

In 2018, Australian PRRT paid amounted to US$6.9 million, while the PRRT expense was US$6.2 million. The difference of US$0.7 million was recognised as a PRRT receivable and was fully recovered during 2019.

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

24. CASH AND BANK BALANCES

	2019 USD'000	2018 USD'000

Current assets
Cash and bank balances	81,942	58,064
Less: restricted cash	(6,008)	(5,083)

Cash and cash equivalents	75,934	52,981

Non-current assets
Cash and bank balances	17,477	23,561
Less: restricted cash	(17,477)	(23,561)

Cash and cash equivalents	-	-

Cash and cash equivalents in the consolidated statement of cash flows	75,934	52,981

As part of the reserve based lending agreement (Note 31), the Group must retain an aggregate amount of principal, interest, fees and costs payable at each quarter-end in the debt service reserve account ("DSRA"). An amount of US$13.5 million (2018: US$18.6 million) is deposited in the DSRA as at December 31, 2019. In addition, the Group is required to maintain a minimum cash balance in the Montara cash operating account of US$15.0 million (2018: US$15.0 million). 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. During the year, US$6.0 million (2018: US$5.1 million) has been recognised as current/able to be released within 12 months, with the remaining US$7.5 million (2018: US$13.6 million) treated as non-current/able to be released in 2021 (2018: 2020/2021).

The Group retains US$10.0 million of cash (2018: US$10.0 million) in support of a bank guarantee to a key supplier in respect of Stag's FSO vessel. It 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.

25. SHARE CAPITAL

Authorised ordinary shares

Unlimited number of ordinary voting shares with no par value.

	No. of shares	USD'000

Issued and fully paid
As at January 1, 2018	221,298,004	364,466
Issued during the year	239,711,474	102,096

As at December 31, 2018/January 1, 2019	461,009,478	466,562
Issued during the year	33,333	11

As at December 31, 2019	461,042,811	466,573

In 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 costs arising from the issuance of the new shares and charged to profit or loss and equity amounted to US$2.0 million and US$5.8 million respectively.

During the year, employee share options of 33,333 were exercised and issued at a price of CAD0.47 per share.

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.

26. HEDGING RESERVES

	2019 USD'000	2018 USD'000

At beginning of the year	(35,480)	-
Loss/(Gain) arising on changes in fair value of hedging instruments during the year	30,542	(51,775)
Income tax related to (loss)/gain recognised in other comprehensive income	(9,162)	15,534
Net gain reclassified to profit or loss	14,874	1,088
Income tax related to amounts reclassified to profit or loss	(4,462)	(327)

At end of the year	(3,688)	(35,480)

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 or loss only when the hedged transaction impacts the profit or loss.

27. SHARE-BASED PAYMENTS RESERVE

The total expense arising from share-based payments recognised for the period ended December 31, 2019 was US$1.5 million (2018: US$0.5 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
	December 3, 2019	March 28, 2019	July 29, 2018	March 29, 2018

Risk-free rate	1.46% to 1.47%	1.46% to 1.47%	2.23% to 2.26%	1.99% to 2.04%
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	40.1% to 42.8%	39.9% to 42.3%	43.2% to 44.7%	43.1% to 44.1%
Share price	C$1.17	C$0.85	C$0.61	C$0.43
Exercise price	C$1.17	C$0.85	C$0.61	C$0.43
Expected dividends	Nil	Nil	Nil	Nil

The following table summarises the share options outstanding and exercisable as at December 31, 2019:

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

As at January 1, 2018	8,102,842	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/ January 1, 2019	12,132,842	0.56	8.50	3,232,830
New share options issued	8,075,000	0.85	9,25	75,000
Vested during the year	-	0.50	7.63	3,858,316
Exercised during the year	(33,333)	0.47	-	(33,333)
Cancelled during the year	(306,667)	0.48	-	(113,333)

As at December 31, 2019	19,867,842	0.68	8.21	7,019,480

28. PROVISIONS

	Provision for asset restoration obligations USD'000	Stag FSO provision USD'000	Total USD'000

As at January 1, 2018	84,728	7,259	91,987
Acquisition of Montara (Note 7)	183,020	-	183,020
Accretion expense (Note 12)	3,632	179	3,811
Changes in discount rate and FX assumptions and estimates (Note 17/Note 11)	6,353	(835)	5,518
Other	(36)	-	(36)

As at December 31, 2018/January 1, 2019	277,697	6,603	284,300
Accretion expense (Note 12)	5,842	110	5,952
Changes in discount rate assumptions and estimates (Note 17/Note 11)	(8,117)	(1,717)	(9,834)

As at December 31, 2019	275,422	4,996	280,418

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

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 2.06% and 2.10% respectively (2018: Stag - 2.27%; Montara - 2.13%). 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 2.24% and 2.31% respectively (2018: Stag - 2.49%; Montara - 2.60%). The Stag estimated ARO has been revised upward, as at year end, due to an increase in facilities abandonment, as a result of higher construction vessel costs amidst tightening market conditions. The Montara estimated ARO has been revised downward, due to a decrease in well abandonment costs arising from decreasing rig and other equipment rates.

Management expects decommissioning expenditures to be incurred from 2033 and 2036 onwards for Montara and Stag, respectively.

On May 30, 2019, Jadestone Energy (Eagle) Pty Ltd, a wholly owned subsidiary of the Company entered into a deed poll with the Australian Government with regard to the requirements of maintaining sufficient financial capacity to ensure Montara's asset restoration obligations can be met when due. The deed states that the Group is required to provide a financial security in favour of the Australian Government when the aggregate remaining net after tax cash flow of the Group is 1.25 times or below the Group's estimated future decommissioning costs.

29. LEASE LIABILITIES

		2019 USD'000

Analysed as:
Non-current		42,533
Current		19,739

		62,272

Maturity analysis of lease liabilities based on undiscounted gross cash flows:
Year 1		20,228
Year 2		19,881
Year 3		17,934
Year 4		9,547
Year 5		3,145
Unearned interest		(8,463)

		62,272

The Group does not face a significant liquidity risk with regards to its lease liabilities. Lease liabilities are monitored within the Group's treasury function.

30. OTHER PAYABLE

2019

USD'000

2018

USD'000

Montara contingent payments (Note 7.4)

359

3,748

The contingent payment of US$0.4 million relates to one remaining potential contingent payment to PTTEP for the Montara acquisition (see Note 7.4). The 2019 contingent payment has been derecognised during the year as the liability has failed to materialise as Dated Brent price averaged below US$80 bbl. The 2020 contingent payment will be payable if the average Dated Brent price is above US$80/bbl in 2020. Based on the forward curve and the likelihood of occurrence, the fair value of the contingent payment was valued at US$0.4 million. The 2020 contingent payment is payable in January 2021 and accordingly it has been classified as a non-current liability on the consolidated statement of financial position.

31. BORROWINGS

	2019 USD'000	2018 USD'000

Non-current secured borrowings
Reserve based lending facility	7,328	49,420

Current secured borrowings
Reserve based lending facility	41,795	51,114

Current unsecured borrowings
Other	-	1,279

	41,795	52,393

	49,123	101,813

On August 2, 2018, the Group 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 drawdown had an amortised carrying value of US$116.8 million. During the year, the Group made principal repayment and interest service costs of US$52.9 million and US$4.5 million (2018: US$16.9 million; US$ 1.7 million) respectively, leaving a balance of US$49.1 million (2018: US$100.5 million).

The loan incurs interest at 3% above LIBOR.

32. 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$17.5 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.

	2019 USD'000	2018 USD'000

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

	-	2,731

Balances related to the secured convertible bond are:

	2019 USD'000	2018 USD'000

Nominal value of the convertible bonds issued	-	15,000
Derivative financial instruments at the date of issuance	-	(2,390)

Liability component at the date of issuance	-	12,610
Less: convertible bond issue costs	-	(378)

Liability recognised at inception, net of costs	-	12,232
Cumulative accretion expense	-	1,244

	-	13,476
Less: bond settlement adjustments	-	(13,476)

	-	-

33. 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 consolidated statement of cash flows.

	Reserved Based Lending Facility USD'000	Lease Liabilities USD'000	Secured Convertible Bond USD'000	Other Borrowings USD'000

As at January 1, 2018	-	-	12,770	829
Financing cash flows	99,829	-	(17,514)	450
Others	705	-	4,744	-

As at December 31, 2018/ January 1, 2019	100,534	-	-	1,279
Adoption of IFRS 16	-	35,850	-	-
Financing cash flows	(52,924)	(16,671)	-	(1,279)
New lease liabilities	-	38,813	-	-
Interest expense	1,513	4,280	-	-

As at December 31, 2019	49,123	62,272	-	-

34. COMMITMENTS UNDER OPERATING LEASES

As at December 31, 2019, the Group is committed to US$4,000 for short-term leases (out of scope under IFRS 16).

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

2018

USD'000

Operating lease payments recognised as an expense

7,630

As at December 31, 2018, the Group has outstanding commitments under non-cancellable operating leases that fall due as follows:

		2018 USD'000

Within one year		9,125
Later than one year but within five years		31,325
Later than five years		3,145

		43,595

35. TRADE AND OTHER PAYABLES

	2019 USD'000	2018 Restated USD'000

Trade payables	9,192	7,178
Other payables	14,355	14,476
Provision for long service leave	851	722
Other provisions	3,460	9,117
GST/VAT payables	104	-

	27,962	31,493

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.

36. DERIVATIVE FINANCIAL INSTRUMENTS

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

	2019 USD'000	2018 USD'000

Derivative financial assets
Designated as cash flow hedges
Commodity capped swap	5,275	51,324

Analysed as:
Current	5,275	35,985
Non-current	-	15,339

	5,275	51,324

The following is a summary of the Group's outstanding derivative contracts:

Contracts designated as hedges

Contract quantity	Type of contracts	Terms	Contract price	Hedge classification	Fair value asset at December 31, 2019 USD'000	Fair value asset at December 31, 2018 USD'000

32% (2018: 50%) of Group's anticipated planned 2PD production	Commodity capped swap: swap component	Oct 2018 - Sep 2020	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	Cash flow	5,203	50,477
67% of swapped barrels in 2019 and in the nine months to September 30, 2020	Commodity capped swap: call component	Jan 2019 - Sep 2020	US$80.00/bbl for the nine months to September 30, 2019, then US$85.00/bbl to September 2020	Cash flow	72	847

As critical terms (i.e., the notional amount, life and underlying oil price benchmark) of the capped swap and the corresponding Montara hedged sales are highly similar, the Group performed a qualitative assessment of effectiveness and has concluded that the value of the capped swap 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 swap arrangement, arising from the slight difference in the timing of Montara's production and the settlement of the capped swap arrangement versus the crude sales. The overall change in value used for calculating hedge ineffectiveness on the capped swap hedge transaction amounted to net loss of US$0.6 million (2018: net gain of US$0.6 million) and have been included in the statement of profit or loss within "other expenses" (Note 9) and "other income" (Note 11), respectively.

The following tables detail the commodity swap contracts outstanding at the end of the reporting year, 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.

Hedging instruments - outstanding contracts

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

2019
Cash flow hedges
Commodity swap component	1,136,940	77,829	633	5,203
Commodity call component	568,470	48,320	-	72

			633	5,275

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

2019
Cash flow hedges
Forecast sales	633	3,688	-

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 (loss)/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 USD'000	Line item in profit or loss in which reclassification adjustment is included

2019
Cash flow hedges
Forecast sales	(21,380)	633	Other expenses	14,241	Revenue

2018
Cash flow hedges
Forecast sales	36,241	637	Other income	451	Revenue

37. 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's 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.

	2019 USD'000	2018 Restated USD'000

Financial assets
At amortised cost	135,737	86,539
Derivative instruments designated in hedge accounting relationships	5,275	51,324

	141,012	137,863

Financial liabilities
At amortised cost	419,671	417,606
Contingent consideration for a business combination	359	3,748

	420,030	421,354

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.

The Group entered into hedge contracts for sales based upon planned production at Montara (Note 36).

Montara

The Group 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 was 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.

Gain or loss	Effect on the result before tax for the year ended December 31, 2019 USD'000	Effect on other comprehensive income before tax for the year ended December 31, 2019 USD'000	Effect on the result before tax for the year ended December 31, 2018 USD'000	Effect on other comprehensive income before tax for the year ended December 31, 2018 USD'000

Increase by 10%	-	(7,266)	(1)	(16,729)
Decrease by 10%	-	7,266	1	16,729

Foreign currency risk

Foreign currency risk is the risk that a variation in exchange rates between United States Dollars ("US Dollar") and foreign currencies will affect the fair value or future cash flows of the Group'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 Dollar in order to match the Group's revenue and expenditures. The Group's US$120.0 million reserve based loan facility is a US Dollar denominated instrument.

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

Material foreign denominated balances were as follows:

	2019 USD'000	2018 Restated USD'000

Cash and bank balances
Australian Dollars	7,088	4,923

Trade and other receivables
Australian Dollars	5,853	5,237

Trade and other payables
Australian Dollars	21,231	1,974

If the Australian dollar weakens/strengthens by 10% against the functional currency of the Group, profit or loss will increase/decrease by US$0.8 million (2018: decrease/increase by US$0.8 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.

Based on the carrying value of the reserve based loan as at December 31, 2019, 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 decreased or increased by US$0.1 million (2018: US$0.3 million).

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.

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 table below details 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:

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

2019
Cash and bank balances	24	n.a	Performing	12m ECL	99,419	-	99,419
Trade receivables	23	n.a	(i)	Lifetime ECL	34,007	-	34,007
Other receivables	23	n.a	Performing	12m ECL	2,311	-	2,311

2018
Cash and bank balances	24	n.a	Performing	12m ECL	81,625	-	81,625
Trade receivables	23	n.a	(i)	Lifetime ECL	57	-	57
Other receivables	23	n.a	Performing	12m ECL	4,857	-	4,857

(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, 2019, total trade receivables amounted to US$34.0 million (2018: US$0.1 million). The balance in in 2019 and 2018 had been fully recovered in 2020 and 2019, respectively. The Group has derivative receivables of US$0.5 million and US$3.4 million within other receivables in 2019 and 2018 and was received in full in January 2020 and 2019, respectively.

The Group recognises lifetime ECL for trade receivables. The ECL on these financial assets are estimated based on days past due by applying 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, and with no history of default.

The maximum credit risk exposure relating to financial assets is represented by their carrying value as at the reporting 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 Group 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, on-going cost reduction initiatives, merger and acquisition strategies, and bank balance on hand.

The Group net profit after tax for the year was US$40.5 million (2018: loss after tax of US$31.0 million). Operating cash flows before movements in working capital and net cash generated from operating activities for the year ended December 31, 2019 was positive of US$176.7 million and US$144.6 million, respectively (2018: negative of US$0.3 million; net cash generated of US$17.8 million). The Group's net current assets remained positive at US$26.8 million as at December 31, 2019 (2018: US$57.5 million).

The Group'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 but including certain infill wells (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 2019, 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 18 months. Please refer to Note 41 for subsequent events disclosure surrounding the impact of COVID-19 pandemic on the Group and the Group's assessment on the use of the going concern assumption.

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

2019
Non-interest bearing	-	48,086	55,503	275,422	(8,463)	370,548
Variable interest rate instruments	7.735	44,425	7,477	-	(2,779)	49,123

		92,511	62,980	275,422	(11,242)	419,671

2018 (Restated)
Non-interest bearing	-	31,493	6,603	277,697	-	315,793
Variable interest rate instruments	8.071	58,907	52,182	-	(9,276)	101,813

		90,400	58,785	277,697	(9,276)	417,606

Non-derivative financial assets


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

2019
Non-interest bearing	-	36,318	-	-	36,318
Variable interest rate instruments	-*	89,419	10,000	-*	99,419

		125,737	10,000	*	135,737

2018
Non-interest bearing	-	4,914	-	-	4,914
Variable interest rate instruments	-*	58,064	23,561	-*	81,625

		62,978	23,561	-*	86,539

The following table 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 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.

*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 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 should that be necessary.

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 year ended December 31, 2019. The Group is not subject to externally imposed capital requirements.

	2019 USD'000	2018 USD'000

Gearing ratio
Debt	49,123	101,813
Cash and cash equivalents	(75,934)	(52,981)
Restricted cash	(13,485)	(18,644)

Net (cash)/debt	(40,296)	30,188
Equity	225,467	215,261

Net debt to equity ratio	N/M	14%

Debt is defined as long and short-term borrowings (excluding derivatives) as detailed in Note 31 and 32. 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$13.5 million in the RBL debt service reserve account (2018: US$18.6 million). 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. Equity includes all capital and reserves of the Group that are managed as capital.

The Group's overall strategy remains unchanged from 2018.

Fair value measurements

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

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

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

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

Relationship

Financial assets/financial liabilities

Fair value (USD'000) as at

Fair

Valuation

Significant

unobservable

2019

2018

value hierarchy

technique(s)

and key input(s)

unobservable input(s)

inputs to fair value

Assets

Liabilities

Assets

Liabilities

Derivative financial instruments

1) Commodity capped swap contracts (Note 36)

5,275

51,324

Level 2

Third party

valuations

based on

market

comparable

information.

n.a.

Others - contingent consideration in a business combination

2) Contingent consideration (Note 7 and 30)

359

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 oil

price forecasts

at the end of

the reporting

period, taking

into account

the time value

of money and

volatility of oil

prices.

Expected

future oil

price

volatility of

25% is

based on

an analysis

of Dated

Brent oil

price

movement prior to acquisition date.

A slight

increase in

Dated Brent

oil prices

would

result in a

significant increase in the fair value and vice versa.

38. 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 producing assets and secondly development and exploration assets. The geographic focus of the business is on SEA and Australia.

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

	2019
	Producing assets		Exploration
	Australia USD'000	SEA USD'000	SEA USD'000	Corporate USD'000	Total USD'000

Revenue
Liquids revenue	325,406	-	-	-	325,406
	325,406	-	-	-	325,406

Production cost	(119,898)	-	-	-	(119,898)
DD&A	(90,277)	-	(113)	(356)	(90,746)
Staff costs	(7,282)	-	(3,543)	(8,889)	(19,714)
Other expenses	(7,012)	-	(278)	(4,402)	(11,692)
Other income	2,971	-	2	6	2,979
Finance costs	(16,387)	-	(7)	(49)	(16,443)
Other financial gain	3,389	-	-	-	3,389

Profit/(Loss) before tax	90,910	-	(3,939)	(13,690)	73,281

Additions to non-current assets	84,444	-	20,456	65	104,965

Non-current assets	461,053	-	116,162	943	578,158

	2018 (Restated)
	Producing assets		Exploration
	Australia USD'000	SEA USD'000	SEA USD'000	Corporate USD'000	Total USD'000

Revenue
Liquids revenue	105,970	8,520	-	-	114,490
Gas revenue	-	2,482	-	-	2,482
Royalties	-	(3,549)	-	-	(3,549)
	105,970	7,453	-	-	113,423

Production cost	(88,159)	(2,780)	-	-	(90,939)
DD&A	(13,066)	(618)	-	(92)	(13,776)
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	2,345	-	-	189	2,534
Finance costs	(6,219)	-	(80)	(2,941)	(9,240)
Other financial gain	12,057	-	-	288	12,345

Profit/(Loss) before tax	4,417	2,075	(13,231)	(14,727)	(21,466)

Additions to non-current assets	376,856	-	1,835	183	378,874

Non-current assets	470,522	-	95,607	280	566,409

Non-current assets include oil and gas properties, intangible exploration assets, right-of-use assets, restricted cash and plant and equipment used in corporate offices.

Included in revenues arising from producing assets in 2019 are revenues of approximately US$325.4 million (2018: US$106.0 million) which arose from sales to the Group's largest customer.

39. FINANCIAL CAPITAL COMMITMENTS

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

SEA portfolio PSC operational commitments

2019

USD'000

2018

USD'000

Not later than one year

10,000

The SEA portfolio PSC operational commitments as at December 31, 2019 amounted to US$10.0 million (2018: US$ 10.0 million), and 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 July 9, 2019, the Company submitted a request to the Vietnam Government, for a further one-year extension to the Block 46/07 PSC exploration phase two period to June 29, 2021 and this was approved on February 26, 2020. Following the Group's announcement on March 19, 2020 to delay the project, the Group will seek Vietnam Government approval for a further extension in order to align drilling of the appraisal well with development of Nam Du/U Minh. The Group is committed to the project and expects to receive approval for the extension request.

Capital commitments

The Group has the following capital commitments for expenditure that were contracted for at the end of the reporting year but not recognised as liabilities for Montara:

2019

USD'000

2018

USD'000

Not later than one year

19,441

17,417

40. CONTINGENT LIABILITIES

Stag

The Group may be responsible for certain contingent payments after 2018 of up to US$10.0 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, 2019, no provision has been recognised in the financial statements.

Montara

The Group may be responsible for certain contingent payments after 2019 of up to US$110.0 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 7.4). At this time, Jadestone's management only considers the contingent payments of up to US$10.0 million (fair value of US$0.4 million) linked to oil price appreciation above US$80/bbl in 2020 as possible, 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 oil price linked contingent payments of US$10.0 million is recognised as a payable (see Note 30) and the remaining US$100.0 million of contingent payments has not been recognised in the financial statements.

41. EVENTS AFTER THE END OF THE REPORTING PERIOD

Award of damages in relation to Philippines arbitration

In December 2017, the Group commenced arbitration action against Total E&P Philippines BV ("Total"), with the Singapore International Arbitration Center, in response to a breach of the 2012 farm out agreement ("the FOA"), claiming that Total failed to drill an exploration well on the deepwater Halcon prospect, located within the block covered by Service Contract 56 ("SC56") in the Sulu Sea, offshore the Philippines. The FOA required Total to drill one exploration well and pay their 75% interest along with the Group's 25% interest.

On January 3, 2020, the tribunal found in favour of the Group, concluding that Total breached the FOA, awarding (i) monetary damages to the Group of US$11.1 million, less specific expenditures incurred prior to the breach to be agreed or determined if the parties cannot agree; and (ii) legal costs of approximately US$4.3 million. The tribunal's costs will be borne by the Group and Total 25:75.

The parties were unable to agree the specific expenditures and, on March 24, 2020, the tribunal issued a final award in which it determined such expenditures to be US$0.7 million. The net award to the Group was US$10.4 million.

After the payment of all legal fees, funding costs, and the Company's share of the tribunal costs, net proceeds to the Group are expected to be approximately US$2.2 million. This will be recognised in FY2020.

Following the award of monetary damages to the Group, Total would be released from bearing the Group's 25% interest for the drilling of one exploration well, its share estimated at US$18.8 million. Consequently, the Group is potentially liable to pay US$2.5 million, being the penalty payable to the Department of Energy in Philippines if both Total and the Group fail to drill an exploration well prior the licence expiration on September 1, 2020. However, no final decision has been reached between the Group and Total on the future plan for SC56, the discussion will take place during the next operator committee meeting, tentatively scheduled in second quarter of 2020.

At the end of the reporting period, no contingent assets nor contingent liabilities were recorded as the outcome of the arbitration was not finalised till after year end.

The total carrying value within intangible exploration assets in respect of SC56 as at December 31, 2019 was US$50.4 million (2018: US$50.4 million). The Group has reviewed, pursuant to IFRS 6 Exploration for and evaluation of mineral resources, whether there are any impairment indicators for SC56 as at year end, and no change has been made to the SC56 carrying value within intangible exploration assets.

Vietnam Block 51 and 46/07

The Group holds a 100% operated working interest in the Block 51 PSC and the Block 46/07 PSC, both in the shallow water Malay-Tho Chu Basin, offshore southwest Vietnam. The Group has made three gas/condensate discoveries: the U Minh and Tho Chu fields in Block 51, and the Nam Du gas field in Block 46/07.

On October 17, 2019, the Group made the formal declaration of commercial discovery for the Nam Du and U Minh fields and submitted to the Vietnam Government the combined formal field development plan for the Nam Du and U Minh development, thus initiating the formal government approval process.

Following delays in the Vietnamese Government approval processes and the drop in the oil price in Q1 2020, the Company announced on March 19, 2020 that it would delay the sanction and development of Nam Du/U Minh and the first gas would not occur before Q4 2022 at the earliest.

As at year end, the Group has recognised US$65.6 million of intangible exploration assets in relation to Nam Du and U Minh fields.

TSX Venture Exchange de-listing

On March 12, 2020, Jadestone has announced and submitted an application to de-list from the TSX-V. The final day of trading for Jadestone's common shares on the TSX-V was on March 24, 2020. The Company's shares will continue to trade on AIM.

Upon de-listing from the TSX-V, the Company will remain a Canadian domiciled corporation and will continue as a reporting issuer under Canadian rules in the near term, but the Company has requested an order from the applicable securities commissions, to grant an exemption from certain of its Canadian reporting requirements, in a matter to similar to a designated foreign issuer.

Impact of Coronavirus outbreak ("COVID-19")

On January 30, 2020, the World Health Organisation declared the COVID-19 outbreak a "Public Health Emergency of International Concern" and on March 10, 2020, declared it to be a pandemic. Actions taken around the world to help mitigate the spread of COVID-19 include restrictions on travel, and quarantines in certain areas, and forced closures for certain types of public places and businesses. The COVID-19 and actions taken to mitigate it have had and are expected to continue to have an adverse impact on the economies and financial markets of many countries, including the geographical area in which the Group operates.

On April 12, 2020, members of Organisation of the Petroleum Exporting Countries and certain other countries including the Russian Federation, have agreed to cut global daily oil production by almost 10%, representing 9.7mm bbls/d effectively from May 2020.

The decline in Dated Brent oil price due to factors set out above has been assessed to be a non-adjusting post balance sheet event in accordance with IAS 10.

The depressed Dated Brent oil price will reduce the Group's revenue in 2020, but the Group has no plan to reduce its crude oil production as the Group has significant downside protection in place, including via its capped swap and a relatively competitive cash operating cost base. The Group has hedged about a third of its planned production for the first nine months of 2020. Plus, the crude at both Stag and Montara has generated a premium above the benchmark crude oil prices.

In the absence of Vietnamese Government approvals for the Nam Du/U Minh field development plan in Q1 2020, and the decline in oil prices, the Group announced on March 19, 2020 to defer the Nam Du/U Minh gas field development. In respect of the Block 46/07 PSC appraisal well commitment, the Group will seek Vietnam Government approval for a further extension to the existing June 29, 2021 deadline, in order to align drilling of the appraisal well with development of Nam Du/U Minh. The Group is committed to the project and expects to receive approval for the extension request.

At the time the Group undertook the impairment review of its non-financial assets, as at December 31, 2019, the spot price for Dated Brent was US$66.8/bbl. Since that time, Dated Brent oil prices have fallen to around US$19.10/bbl as at April 20, 2020, due to the impact of Coronavirus ("COVID-19") on oil demand.

The Group will reflect updated oil price data during its next impairment review, including spot oil prices, but will also give due consideration to both the medium- and long-term outlook for crude oil prices.

The Group will closely monitor the development of the COVID-19 outbreak and related oil price outlook, and continue to evaluate its impact on the business, the Group's financial position and operating results. As part of the preparation of the current financial statements, a forward looking going concern analysis was undertaken at some of the lower current third party downside Brent crude oil price outlooks, including US$22/bbl in Q2 2020 and US$30/bbl in H2 2020. The Group was able to generate positive operating cashflow without resorting to significant cuts in operating costs, and comfortably continue as a going concern.

42. RELATED PARTY TRANSACTIONS

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

Compensation of key management personnel

	2019 USD'000	2018 USD'000

Short-term benefits	6,746	2,656
Other benefits	1,052	326
Share-based payments	1,038	234

	8,836	3,216

The total remuneration of members of key management in 2019 (including salaries and benefits) was US$8.8 million (2018: US$3.2 million).

Compensation of directors

	Short-term benefits^(a)	Other benefits^(a)	Share-based payments	Total compensation
	USD'000	USD'000	USD'000	USD'000

2019
A. Paul Blakeley	1,302	350	233	1,885
Daniel Young	707	174	139	1,020
Dennis McShane	130	-	21	151
Iain McLaren	81	-	13	94
Eric Schwitzer	68	-	25	93
Robert Lambert	69	-	13	82
Cedric Fontenit	66	-	9	75
David Neuhauser	56	-	12	68
Lisa Stewart	6	-	-	6

	2,485	524	465	3,474







	Short-term benefits^(a)	Other benefits^(a)	Share-based payments	Total compensation
	USD'000	USD'000	USD'000	USD'000

2018
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
Eric Schwitzer	58	-	9	67
Robert Lambert	50	-	9	59
David Neuhauser	45	-	9	54
Cedric Fontenit	18	-	-	18

	1,952	571	293	2,816

^(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

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

		1,961,271

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

Repayment of secured convertible bond

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 25.6% of the Company's ordinary share capital, as at December 31, 2019.

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 Capital Event S.à r.l., 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.

43. RECLASSIFICATION OF COMPARATIVE FIGURES

Certain comparative figures in the financial statements of the Group have been reclassified to conform to the presentation in the current financial year. These reclassifications were made to better reflect the nature of the expenses in the respective lines in the statement of profit or loss and other comprehensive income. These relate to the following:

	As previously reported USD'000	Reclassification USD'000	As reclassified USD'000

Statement of profit or loss and other comprehensive income for the year ended December 31, 2018

Production costs	(90,339)	(600)	(90,939)
Depletion, depreciation and amortisation	(14,376)	600	(13,776)
Other income	1,718	816	2,534
Finance costs	(9,061)	(179)	(9,240)
Other financial gains	12,982	(637)	12,345

Statement of financial position as at December 31, 2018
Provision for asset restoration obligations	277,697	(277,697)	-
Provisions	-	284,300	284,300
Other payable	10,351	(6,603)	3,748

The reclassification of comparative figures have been reflected in the statement of cash flows.

As a result of the finalisation of the PPA during the financial year ended December 31, 2019, certain line items have been amended in the statement of financial position and related notes to the financial statements.

The items were adjusted as follow:

	Provisional PPA USD'000	Adjustments USD'000	Final PPA USD'000

Oil and gas properties	415,365	14,828	430,193
Inventories	29,831	(14,009)	15,822
Trade and other payables	(30,674)	(819)	(31,493)

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 SEASIDESSELL

Companies

Jadestone Energy (JSE)

Tuesday, 3rd December 2024

COMPANIES COVERED:

MARS SSPG OTB

A positive start for a number of reporting stocks on Tuesday with double digit gains for SSP Group and On The Beach, whilst investors in pub operator Marston’s also found cause for cheer after market outperformance.

Full Archive

UK 100

Latest directors dealings

2 hours ago Molten Ventures
2 hours ago Touchstone Exploration Inc NPV (DI)
2 hours ago Team Internet Group plc
2 hours ago Ondo Insurtech
2 hours ago Wilmington

All directors dealings today