Jadestone Energy Regulatory News (JSE)

Jadestone Energy Inc. 

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

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

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

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

Financial highlights

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

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

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

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

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

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

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

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

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

Operational highlights

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

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

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

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

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

Outlook highlights

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

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

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

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

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

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

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

Paul Blakeley, President and CEO commented:

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

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

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

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

Operations update

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

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

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

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

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

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

Financial overview

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Selected financial information

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

1 Production, sales and average realised prices are expressed on a barrels of oil equivalent basis as the underlying data includes gas production from Ogan Komering for the prevailing period based on Jadestone's 50% participating interest up until May 19, 20182 Revenue has been restated from gross to net after deducting royalties, but including the effective gain on hedging contracts3 Payment for oil and gas property, plant and equipment and intangible exploration assets. Excludes acquisition related capital expenditure4 Comparable reporting period for the current period is the nine months ended December 31, 2017

Conference call and webcast

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

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

Webcast link: https://event.on24.com/wcc/r/1964214/68A3F57926E8403B758AC386B99793F5Event conference title: Jadestone Energy Inc. - Fourth Quarter ResultsStart time: 9:00 p.m. (Singapore), 2:00 p.m. (London), 9:00 a.m. (Toronto)Date: Thursday, April 18, 2019Confirmation ID: 54105682

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

- Ends -

Enquiries

About Jadestone Energy Inc.

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

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

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

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

Cautionary statements

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

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

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

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

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

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

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

Glossary

2PD proved and probable developed reserves

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

bbls barrels of oilbbls/d barrels of oil per dayboe barrels of oil equivalentboe/d barrels of oil equivalent per dayEBITDAX earnings before interest, tax, depreciation, amortisation and exploration expensesFPSO floating production, storage and offloading vesselmbbl thousands of barrels of oil

mboe thousands of barrels of oil equivalent

mm bbls millions of barrels of oil

mm boe millions of barrels of oil equivalent

PVEP Petrovietnam Exploration Production Corporation

Jadestone Energy Inc.

CONSOLIDATED FINANCIAL STATEMENTS

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

MANAGEMENT'S REPORT

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

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

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

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

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

"A. Paul Blakeley" "Daniel Young"

________________________ _________________________

A. Paul Blakeley Daniel Young

Director Director

April 18, 2019 April 18, 2019

Jadestone Energy Inc.

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

Opinion

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

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

Basis for Opinion

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

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Key Audit Matters

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

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Other Information

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

Our opinion on the consolidated financial statements does not cover the other information and we do not and will not express any form of assurance conclusion thereon. In connection with our audit of the consolidated financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated.

We obtained the MD&A prior to the date of this auditor's report. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact in this auditor's report. We have nothing to report in this regard.

Responsibilities of Management and Those Charged with Governance for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Group or to cease operations, or has no realistic alternative but to do so.

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

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

Auditor's Responsibility for the Audit of the Financial Statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian GAAS will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements.

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

a) Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

b) Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group's internal control.

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

d) Conclude on the appropriateness of management's use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor's report to the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor's report. However, future events or conditions may cause the Group to cease to continue as a going concern.

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

f) Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion.

INDEPENDENT AUDITOR'S REPORT TO THE SHAREHOLDERS OF

JADESTONE ENERGY INC.

We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

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

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

"Deloitte & Touche LLP"

Deloitte & Touche LLP

Public Accountants and

Chartered Accountants

Singapore

April 18, 2019

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

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

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

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

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

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

as at December 31, 2018 and December 31, 2017

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

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

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

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

Jadestone Energy Inc.

CONSOLIDATED STATEMENT OF CASH FLOWS

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

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

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

1. CORPORATE INFORMATION

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

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

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

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

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

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

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

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

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PREPARATION

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

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

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

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

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

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

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

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

Adoption of new and revised standards

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

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

- IFRS 9 Financial Instruments; and

- IFRS 15 Revenue from Contracts with Customers.

IFRS 9 - Financial Instruments

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

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

IFRS 9 introduced new requirements for:

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

2) Impairment of financial assets; and

3) General hedge accounting.

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

(a) Classification and measurement of financial assets

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

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

(b) Impairment of financial assets

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

(c) Classification and measurement of financial liabilities

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

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

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

(d) General hedge accounting

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

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

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

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

IFRS 15 - Revenue from contracts with customers

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

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

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

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

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

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

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

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

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

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

New and revised IFRSs in issue but not yet effective

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

- IFRS 16 Leases; and

- Amendments to IFRS 3 Business Combinations

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

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

IFRS 16 Leases

General impact of application of IFRS 16 Leases

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

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

Impact of the new definition of a lease

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

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

- The right to direct the use of that asset.

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

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

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

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

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

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

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

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

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

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

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

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

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

Amendments to IFRS 3 Business Combinations

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

BASIS OF CONSOLIDATION

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

- Has power over the investee;

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

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

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

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

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

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

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

BUSINESS COMBINATIONS

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

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

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

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

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

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

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

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

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

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

FOREIGN CURRENCY TRANSACTIONS

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

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

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

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

JOINT OPERATIONS

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

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

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

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

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

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

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

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

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

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

- Approval is considered highly likely; and

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

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

PRE-LICENCE AWARD COSTS

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

EXPLORATION AND EVALUATION COSTS

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

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

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

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

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

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

FARM-OUTS IN THE EXPLORATION AND EVALUATION PHASE

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

OIL AND GAS PROPERTIES

Producing assets

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

Depletion and amortisation expense

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

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

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

Asset restoration obligations

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

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

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

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

BORROWING COSTS

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

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

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

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

PLANT AND EQUIPMENT

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

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

- Computer equipment: 3 years;

- Fixtures and equipment: 3 years; and

- Motor vehicles: 3 years.

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

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

IMPAIRMENT OF TANGIBLE ASSETS AND INTANGIBLE ASSETS

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

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

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

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

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

INVENTORY

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

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

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

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

FINANCIAL INSTRUMENTS

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

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

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

Financial assets

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

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

Classification of financial assets

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

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

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

Amortised cost and effective interest method

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

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

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

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

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

Foreign Exchange gains and losses

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

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

Impairment of financial assets

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

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

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

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

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

Measurement and recognition of expected credit losses

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

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

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

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

De-recognition of financial assets

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

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

Financial liabilities

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

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

Financial liabilities at FVTPL

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

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

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

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

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

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

Financial liabilities measured subsequently at amortised cost

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

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

Equity instruments

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

Convertible bonds

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

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

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

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

Transaction costs

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

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

De-recognition of financial liabilities

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

Derivative financial instruments

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

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

Hedge accounting

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

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

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

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

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

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

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

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

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

Cash flow hedges

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

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

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

EQUITY AND LISTING COSTS

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

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

FAIR VALUE ESTIMATION OF FINANCIAL ASSETS AND LIABILITIES

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

SHARE-BASED PAYMENTS

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

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

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

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

LEASES

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

The Group as lessee

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

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

PROVISIONS

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

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

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

RETIREMENT BENEFIT OBLIGATIONS

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

REVENUE

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

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

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

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

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

ROYALTIES

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

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

INCOME TAX

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

Current tax

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

Petroleum resource rent tax (PRRT)

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

Deferred tax

Deferred tax is recognised on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available, against which deductible temporary differences can be utilised.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

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

The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

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

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

Current and deferred tax for the year

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

CASH AND BANK BALANCES IN THE STATEMENT OF CASH FLOWS

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

3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

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

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

Critical judgements in applying the Group's accounting policies

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

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

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

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

Key sources of estimation uncertainty

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

a) Purchase price allocation & contingent payments

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

b) Valuation of derivative financial instruments

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

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

c) Depreciation of oil and gas properties

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

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

These factors could include:

- Changes in proved and probable reserves;

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

- Future estimates of capital expenditure requirements; and

- Unforeseen operational issues.

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

d) Taxes

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

e) Reserves estimates

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

f) Impairment of assets

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

g) Asset restoration obligations

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

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

4. REVENUE

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

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

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

5. PRODUCTION COSTS

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

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

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

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

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

7. ACQUISITION OF MONTARA ASSETS

7.1 Effective date and acquisition date

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

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

7.2 Business acquisition

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

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

7.3 Fair value of consideration transferred

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

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

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

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

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

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

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

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

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

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

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

7.4 Assets acquired and liabilities assumed at the date of acquisition

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

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

7.5 Impact of acquisitions on the results of the Group

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

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

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

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

7.6 Deferred contingent consideration

8. STAFF COSTS

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

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

9. OTHER EXPENSES

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

10. IMPAIRMENT OF ASSETS

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

11. OTHER INCOME

12. FINANCE COSTS

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

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

13. OTHER FINANCIAL GAINS

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

14. INCOME TAX (EXPENSE)/CREDIT