JKX.L Regulatory News (JKX)

 FOR IMMEDIATE RELEASE

29 MARCH 2019

JKX Oil & Gas plc

('JKX', the 'Company' or the 'Group')

UNAUDITED PRELIMINARY RESULTS

FOR THE YEAR ENDED 31 DECEMBER 2018

JKX Oil & Gas plc (LSE: JKX), announces its unaudited preliminary results for the year ended 31 December 2018.

2018 Highlights

§ Revenue up to $92.9m (2017:$74.6m), benefitting from high sales prices in Ukraine.

§ First full year profit after tax since 2013 of $15.3m (2017:$17.7m loss).

§ Cash generated from continuing operations up to $37.3m (2017:$14.2m).

§ Moved into to net cash position of $8.2m (2017:$9.7m net debt position).

§ Both Ukrainian and Russian production up year on year.

§ In Ukraine, commenced new five year development plan with positive results.

§ In Russia, rigged up for the new three well workover programme targeting a significant increase in production within two years.

For further information please contact:

JKX Oil & Gas plc: +44 (0) 20 7323 4464

Ben Fraser, CFO

EM Communications: +44 (0) 20 7002 7860

Stuart Leasor, Jeroen van de Crommenacker

Chairman's statement

Dear shareholder, I am pleased to present the results for the full 2018 year and to report that 2018 has been a year of significant and positive change for the Company, with progress made in many key areas.

Previously the Board identified the following areas of immediate focus for 2018:

It is particularly notable that I am able to report the first full year profit for the year ending 31 December 2018 since 2013 and that in 2018 we have moved from having a net debt of $9.7m at the start of the year to a closing net cash position of $8.2m.

This represents a significant improvement in the Company's financial position and a vindication of the hard work and commitment from the Company's officers and staff over the year. The Company's focus has been on cost and risk control, building liquidity reserves, stabilising the operations, improving the contractor base and achieving successful results from the workover programme, as well as achieving stronger oil and gas prices.

Along with improved financial results there has also been positive progress in the other key focus areas I identified in the 2017 Annual Report:

Relationship with shareholders

For the first time in many years the Company's Board and senior leaders have remained stable since the last annual report, the only changes in the Board arising from the sale of Proxima's 19.97% shareholding to our new strategic investor, Cascade Investment Fund. I would like to recognise Proxima's support of the Company and to welcome Cascade. I look forward to a constructive relationship with Cascade over the years to come, whilst ensuring the continued independent nature of the Board.

During the year all the independent Directors (myself included) stood down and offered ourselves up for re-election at an EGM held on 22 March 2018 in order to ensure that we had the confidence of all shareholders.

I am glad to be able to report that all the directors were reappointed - as were Mr Bakunenko and Mr Rusinov who stood down and offered themselves up for re-election at the AGM held on 25 June 2018.

The Board seeks to foster an active and open communication with all our shareholders. During the year I have met with a range of shareholders to ensure that I can explain our strategy and discuss their concerns in order to ensure that decisions are taken in the best interests of the Company as a whole.

Operational and financial alignment between all companies of the Group

The Board has undertaken a review of key processes and has introduced a number of new policies and procedures in order to ensure the robustness of the Group control framework and a harmonised approach on a Group-wide basis. These processes will enhance the Board and senior management's ability to identify and manage risk.

In 2018, the Group has also reviewed its existing contractor base. This work has included comprehensive rig tender exercises in both Ukraine and Russia, to find rigs of a suitable standard to carry out the 2019 work plan. New drilling contractors have been appointed and additional contracts will be concluded in the near future. In addition a five year field development plan has been approved for Ukraine as well as a three well work over programme for Russia.

Focus on operational risk management developing existing fields step by step with proven, low risk technology

In 2018 Poltava Petroleum Company ('PPC') undertook an active work programme including working over leased and owned wells, three successful side-tracks and a new well completed. As a consequence annual production from Ukrainian assets increased by 4.8% in 2018 compared to 2017 and we are now starting to see the benefits of the work done in Q4 2018 and Q1 2019. The Group production from the first 2 months of 2019 is 11% higher than for the same period in 2018 and 9% higher than the average monthly production during 2018.

During 2018 successful production from two leased wells in the northern part of Rudenkivske further confirmed the presence of commercial hydrocarbons and plans are in place to drill a side-track in this field in 2019. Access to WM215, a leased well in the West Mashivske licence, together with the implementation of the necessary flowline connections led to first production from this field in the second half of the year. After year end a new well has been drilled in the new West Mashivske field (WM3) and 3D seismic shooting completed. WM3 is currently being tested and the seismic now being processed.

In Russia production increased by 3% in 2018 compared to 2017. Despite a continuing decline in Well 20 through the year, Russian production is up year-on-year, with the help of periodic acid jobs, to the continued stable performance of Well 25 and 27.

Ensure financial stability by building liquidity reserves, reducing debt and keeping tight control over costs

As reported above, the Company has recorded its first full year profit after tax since 2013 (2018: $15.3 m, 2017: Net loss $17.7 m) and has moved from being in a net debt position to a net cash position (2018 net cash: $8.2 m, 2017: net debt: $9.7m).

The Board and the senior executive team have successfully used the Group's positive operating cash flow to pay off debt on schedule and to consolidate cash reserves by strengthening cost controls and ensuring improved procurement and payment procedures in order to reduce future spend.

All planned payments to bondholders were successfully made in February 2018 and 2019, thus repaying on schedule one third of the capital outstanding on the bonds in 2018 (capital repaid 2018: $5.3 m) and one half of the remainder in 2019 (2019: $5.3 m). The final capital repayment ($5.4 m) will be made in February 2020.

Resolving outstanding tax issues

The Company's principal operating Company, PPC, has three material unresolved tax issues relating to:

1. A claim for underpayment of rental fees for 2010. The claim, including interest and penalties, amounts to approximately $12.4m. A ruling from the Supreme Court of Ukraine is expected in H1 2019.

2. Claims for underpayment of rental fees for 2015. The claims, including interest and penalties, amount to approximately $ 30.1m. The tax notification was subsequently cancelled. The cases are still being contested in court. We do not expect any final ruling in these cases before 2020.

3. An award of approximately $12.1m made by the Hague international tribunal in 2017. In February 2019 we filed for recognition of this award in the Ukrainian courts, and although material uncertainties remain over practical enforcement, we expect the recovery in 2020 at the earliest.

As described above, the timing of the court processes dealing with the royalty claims has become much clearer during 2018, and a decision on the claim for underpayment of rental fees for 2015 is not expected before 2020. This provision for potential liability of $30.1m has consequently been reclassified from short term to long term liabilities. This reclassification, together with the improved cash position, means that the company reasonably expects to have sufficient liquidity to pay tax claims that may arise if we do not successfully defend our position in Ukrainian courts.

More effective governance

The Board is culturally diverse, widely experienced and consists of individuals with knowledge and skills in each of the key areas of risk for the Company and with significant experience of operating in JKX's key markets.

As described in last year's Annual Report and Accounts, an external investigation was commissioned in Q1 2018 into the procurement of legal services and subsequent payments made to legal advisers in Ukraine in 2017. This investigation concluded that there had been a breakdown in internal controls and a number of measures have been introduced to strengthen the Company's internal control systems.

The Board's approach to the senior executive leadership remains unchanged and fit for purpose. In practice this means that each operating subsidiary has a General Director reporting directly to the Chairman whilst a Group Chief Financial Officer provides Group level overview and leadership. At the same time the highly experienced Board continues to make its range of skills and experience available to the Company.

We believe that the current composition of the Board continues to provide the Company with access to expertise and skills that would not otherwise be available to it, whilst reinforcing the Directors' strong commitment to Board independence. In addition to the non-executive Chairman, the number of independent directors has remained steady at three, while the number of non- independent directors has been reduced from three to one.

Outlook

Ukraine and Russia will remain our main areas of operation and the Board and management will continue to devote their full attention to our assets in these countries.

In Ukraine, we are starting to see the benefits of the work done and plan developed in 2018. Provisional production figures in Q1 2019 have risen to 5,015 boepd (2018 average annual production: 3,677 boepd). We will continue to prioritise low cost, low risk activities in order to maximise the impact of our free cash using the newly appointed drilling contractors and we will enhance our technical capabilities to ensure on time and on budget delivery of work packages.

In Russia a rig has arrived for the first well of the three well workover programme planned for 2019 and we are exploring alternative sales strategies in order to secure stable, long term sales at increased prices.

We anticipate a gradually improved cash flow through 2019 as the Group strategy and focus on operational excellence starts to yield results. This includes an unrelenting focus on internal control and cost optimisation.

In summary the key areas of focus for 2019 are:

§ successful implementation of the five year field development programme;

§ continued focus on financial stability, risk management and cost control;

§ resolving outstanding tax issues; and

§ an initial, strategic review of areas of new opportunity.

People

In 2018 the company suffered the tragic loss of an operator in Ukraine. This sad loss has caused the company to review its HSE provision across all its operations, in particular in high risk activities.

2018 has been a period of organisational stability for JKX following a period of significant Board and management change. This stability has given us the chance to continue right-sizing the organisation and to ensure that we have the correct resources in the right places in order to implement our revised strategy.

I would like to thank JKX's staff for ensuring continuity and smooth operations and to both our staff and our shareholders for their continued faith in the Company.

I remain optimistic about the Company, whilst being realistic about the challenges that it continues to face.

On behalf of the Board

Hans Jochum HornChairman

Financial review

Results for the year

The profit after tax for the year of $15.3m is the first reported since 2013 and is a marked improvement upon the loss after tax of $17.7m reported for 2017. Results for both years include significant charges reflecting updated interest calculations for the provisions for disputed rental fees for 2010 and 2015 in Ukraine ($5.1m in 2018 and $4.4m in 2017). No other exceptional charges have been reported for 2018, which compares favourably with the significant charges for the unsuccessful Rudenkivske fracturing programme, impairment charges and severance payments reported for 2017.

Total revenue for 2018 is $92.9m, 24.5% higher than the $74.6m reported in 2017. The increase is primarily due to the higher commodity prices in Ukraine, as well as the 3.1% increase in total Group production from 8,657 boepd in 2017 to 8,937 boepd in 2018. Gas sales prices and netbacks are still significantly higher in Ukraine than in Russia.

Revenue

* note this excludes Hungary that is presented as a discontinued operation in the financial information.

Ukraine revenues

The $17.9m increase in total revenues was due to both higher sales prices, as shown in the table, and higher sales volumes.

The average gas sales price in dollar terms was 29.6% higher in 2018 than in 2017. This is in line with international market trends. Total gas sales volumes increased by 5.9% from 150,909 Mcm in 2017 to 159,887 Mcm in 2018, primarily due to the gas production volume having increased 4.9% from 172,939 Mcm in 2017 to 181,482 Mcm in 2018. The increase in production was a result of the ongoing drilling and workover activity in Ukraine. For more detail please refer to the Operations review. 

The average oil sales price increased from $64.3/bbl in 2017 to $74.0/bbl in 2018 and total oil sales volumes for the year increased 2.1% from 256,076 barrels in 2017 to 261,420 barrels in 2018. Oil production volume increased 4.5% from 262,334 barrels in 2017 to 274,087 barrels in 2018, with the surplus being taken to inventory.

LPG sales volumes were 10,266 tonnes in 2018 compared to 9,855 tonnes in 2017, with sales prices being higher in 2018 ($544/tonne in 2018 compared to $467/tonne). 

A portion of production comes from wells owned by third parties, operated under service agreements with UkrGasVidobuvannya and under rental agreements with NAK Nadra Ukrayini and Ukrnafta. This production is subject to sale in the normal way, with payments being made to the well owners in accordance with the service and rental agreements.

Russia revenues

Russian revenues benefitted from a 3.9% price increase in rouble terms on 1 July 2018 and a year on year increase in production volumes (2018: 316,996 Mcm, 2017: 307,841 Mcm) but were negatively impacted by the weakening of the rouble as shown in the table above, leading to an increase of just 1.1% in dollar terms.

Cost of sales

The provision for disputed rental fees, in respect of claims for additional rental fees for the years 2010 and 2015, was increased by $5.1m, to reflect updated interest calculations, in 2018.

Cost of sales before exceptional items for 2018 totalled $57.5m (2017:$51.9m). This includes:

§ $21.9m of production taxes, which were $5.2m higher than in 2017 due to the higher production taxes incurred in Ukraine. The production tax expense in Ukraine increased from $14.9m in 2017 to $20.1m in 2018, mainly due to an increase in the average border gas price which is the basis for calculating gas production taxes (UAH8,194 per Mcm in 2018 compared to UAH6,115 per Mcm in 2017). Only $1.8m of the total production taxes relate to Russia (2017: $1.8m) where the mineral extraction tax rate for wells deeper than 5,000m has remained at 328 Roubles/Mcm.

§ $20.7m of operating costs, of which $12.1m relates to Ukraine (2017:$9.6m) and $8.6m relates to Russia (2017:$9.9m). The increase in operating costs in Ukraine is mainly due to a $2.0m increase in well service and rental costs (2018:$3.0m, 2017:$1.0m). The decrease in Russia is partly due to the rouble exchange rate.

§ $14.9m of depreciation, depletion and amortisation charge (2017:$16.8m).

Administrative expenses

Administrative expenses before exceptional items of $13.9m in 2018 compare favourably to those of $16.4m in 2017. The decrease is mainly due to staff cost reductions resulting from a right sizing exercise carried out during 2018 to ensure that resources are appropriate to the needs of the Group, and a reduction in legal, lobbying and other professional fees incurred. 2018 administrative expenses include $0.5m of professional fees in relation to the forensic investigation into payment of legal expenses in Ukraine, as disclosed in our previous annual report, which are considered non-recurring.

Finance income and costs

Finance costs decreased from $3.2m in 2017 to $2.5m in 2018. This mainly consists of the convertible bond interest, which reduced from $2.8m to $2.1m due to the repayment of principal outstanding in February 2018. Finance costs also include unwinding of discount of provisions for site restoration of $0.4m (2017: $0.3m). 

Finance income of $0.9m (2017: $0.3m) comprises income from bank deposits, which has risen in accordance with the increase in funds held.

Taxation

The total tax charge for 2018 is $2.2m (2017: $0.8m credit) comprising a current tax charge of $5.5m (2017: $3.0m) which relates to Ukraine and a deferred tax credit of $3.2m (2017: credit $3.8m). The increase in current tax charge reflects a higher profitability in Ukraine. The deferred tax credit relates to movements in various deferred tax assets and liabilities in Ukraine and Russia.

Discontinued operation

The Hungarian business is presented as a discontinued operation to reflect our decision to dispose of it, as explained in our previous annual report. It covered its costs in 2018, providing a small operational profit. The total profit attributable to it, as presented in the consolidated income statement, largely relates to non-cash items as set out in Note 8. The remaining net assets of $0.5m include deposits held to address future abandonment costs.

Capital Expenditure

While we started the year with only $6.9m unrestricted cash and building liquidity was a clear priority, we also recognise the need to invest for the longer term.

Of the $11.8m capital expenditure incurred during the year (2017:$19.3m), $11.1m relates to Ukraine where we drilled a new well and two sidetracks. Only $0.7m relates to Russia, where investment was minimal while we were securing a suitable rig for the three well workover programme to be performed in 2019.

Cash flows 

During the year the Group significantly increased its available cash balances from $6.9m to $19.2m while at the same time it decreased its borrowings from $16.6m to $11.0m, therefore moving from a net debt to a net cash position. This was achieved as a result of strong operating cash flow of $37.3m (2017:$14.2m) from continuing operations, almost all of it generated in Ukraine. Successful completion of the three well workover programme in Russia, improving netbacks by increasing production volumes, will improve its cash contribution to the Group in 2019 and beyond.

Use of cash during the year is as shown in the cash bridge below. Capital expenditure cash outflow of $3.5m relating to Russia includes $2.8m to settle creditor balances from prior periods.

Net cash outflow from financing activities in the period mainly relates to the $5.8m payment to the bondholders in February 2018. No dividends were paid to shareholders in the period (2017: nil).

Cash flows ($m)

Liquidity outlook

We have considerably improved our liquidity over the last year underpinned by greater operating cash flows.

After a further payment of $6.0m to bond holders in February 2019 the Group remains in a net cash position, with sufficient funds to make the remaining bond payments ($0.4m in August 2019 and $5.8m in February 2020). In addition in December 2018 PPC, our subsidiary in Ukraine, has renewed and increased a 12 month UAH280m ($10.1m) revolving credit line and a UAH50m ($1.8m) overdraft facility with Tascombank, neither of which are currently being used. We are confident that this facility can be renewed again for 2020. As well as our continued focus on cost control, other options available to us to improve our liquidity include the execution of forward sales in Ukraine and deferring capital expenditure if required. We are not burdened by significant field development commitments in the short or long terms.

Furthermore, we have improved our understanding of the 2010 and 2015 rental fee claims for which we continue to maintain provisions (see Note 10 to the consolidated financial information) and are now satisfied that we have the resources to meet these potential liabilities if necessary based on the expected timing of potential payments. In particular, careful consideration has been given to the earliest dates that courts may conclude that PPC may be required to settle each of the various claims in the event that court hearings proceed without undue delay, including assessments with external legal counsel. The Group's expectation is that a final hearing with respect to the 2010 rental fee claim will take place in 2019 and that final hearings in respect of the 2015 rental fee claims will take place in 2020 and 2021. The $12.4m provision for the 2010 rental fee claim has therefore been reported under current liabilities and the $30.1m provision for the 2015 rental fee claims has been reported under non-current liabilities.

Both our Ukrainian and Russian operations remain cash flow positive, generating sufficient cash to cover the Group's costs and their own investment programmes and the Group's liquidity is forecast to improve through 2019 and beyond. The consolidated financial statements have therefore been prepared on a going concern basis (see Note 2 to the consolidated financial information).

Ben Fraser

Chief Financial Officer

Operations review

Group production

In 2018 group average production was 8,937 boepd (2017: 8,657 boepd), an overall increase in production of 3%. The increase in production year-on-year was a result of the ongoing drilling and workover program in Ukraine and higher uptime in Russia.

1 Includes abandonments

Gas and oil production increased year-on-year in all cash generating units, except Hungary.

Ukraine

Novomykolaivske complex production and operations

The increase in Novomykolaivske complex production year-on-year was mostly attributed to production from two sidetracks, and the workover of a leased well in Rudenkivske.

Outlook

Following the creation of a five year field development plan and the recent success of IG103 sidetrack a follow-up well, IG142, is planned in 2019 to target another structural high point in the potentially productive horizons in the area directly south of IG103 sidetrack.

In Novomykolaivske one firm well, and one contingent well, are planned to be drilled to appraise the V16 to the south of the main field in 2019. Success of these two wells would lead to further wells targeting the shallow Visean sands to the west of the Molchanviske licence. These wells benefit from a relatively low capex cost due to the target depth being less than 2000m.

In Rudenkivske, following the success of the leased well workovers in 2018, a sidetrack is planned to further evaluate the Visean sands in the north western part of the field in 2019. Commercial success of this sidetrack could lead to the drilling of at least 7 more wellbores targeting the Visean sands in the North of Rudenkivkse.

Elyzavetivske Licence production and operations

The increase in production from the Elyzavetivske licence was mainly the result of the successful workover of two leased wells, one of which was on the West Mashivske licence.

Outlook

Following the successful workover of a leased well in West Mashivske and the tie-in to the Elyzavetivske facilities a new well was spudded in the West Mashivske field in December 2018.

After year end the shooting of a 3D seismic survey has been completed and is now being processed which along with the results from the first new well will enable a field development plan to be created for this field, the only undeveloped field in JKX's portfolio.

Russia

Koshekhablskoye licence production and operations

1 Includes Well 15 production and Well 5 workover

In 2018 there were no workovers while resources were focussed on finding a suitable rig to complete a 3 well workover program to commence in 2019. This workover programme will include the work overs of Well 5 and Well 18 which upon completion are expected to deliver a significant increase in production within two years.

The Callovian licence commitment has now been extended from 2019 to 2025.

Reserves Update

In Ukraine, production from 2018 has been more than offset by reserves increases across the fields. The most significant increase is the result of continuing production from the West Mashivske field in the Elyzavetivske licence.

In Russia, there has been no change to the reserves this year other than depletion due to 2018 production. Currently more than 50% of the Group reserves are accounted for by Russia and with a current commercial cut-off of 2049, relying on long term price and other commercial assumptions, no change to reserves year-on-year is justified.

Total remaining 2P reserves at 31 December 2018

* 0.18 Bcf [5 MMcm] produced in Hungary

Field-by-Field 2P reserves at 31 December 2018

Note: there are minor differences in the tables above due to rounding effects

JKX Contingent Resources

There is no change to the contingent resources in 2018.

Principal risks and uncertainties

The Board has completed a robust assessment of the most significant risks and uncertainties which could impact the business model, long-term performance, solvency or liquidity, and the results are below.

The principal risks set out on the following page are not set out in any order of priority, are likely to change and do not comprise all the risks and uncertainties that the Group faces.

Consolidated income statement

For the year ended 31 December 2018

1 Prior year numbers were restated as a result of application of IFRS 5 "Non-current Assets Held for Sale and Discontinued Operations" to the Group's operations in Hungary. Please refer to Note 8 for details

The above consolidated income statement should be read in conjunction with the accompanying notes below.

Consolidated income statement

For the year ended 31 December 2018

* Comparative earnings per share have been amended to provide a consistent basis of measurement with 2018. Refer to note 11 for details.

The above consolidated income statement should be read in conjunction with the accompanying notes below.

Consolidated statement of comprehensive income

For the year ended 31 December 2018

1 Prior year numbers were restated as a result of application of IFRS 5 "Non-current Assets Held for Sale and Discontinued Operations" to Group's operations in Hungary. Please refer to Note 8 for details

The above consolidated statement of comprehensive income should be read in conjunction with the accompanying notes below

Consolidated statement of financial position

As at 31 December 2018

* Comparative amounts in respect of deferred tax assets, liabilities, non-current other receivables and other payables have been reclassified for comparability with 2018. Please refer to Note 2

 The above Consolidated statement of financial position should be read in conjunction with the accompanying notes below.

Consolidated statement of changes in equity

For the year ended 31 December 2018

Consolidated statement of cash flows

 For the year ended 31 December 2018

Notes to financial information

1. General information

JKX Oil & Gas plc (the ultimate parent of the Group hereafter, 'the Company') is a public limited company listed on the London Stock Exchange which is domiciled and incorporated in England and Wales under the UK Companies Act. The registered number of the Company is 3050645. The registered office is 6 Cavendish Square, London, W1G 0PD.

The principal activities of the Company and its subsidiaries, (the 'Group'), are the exploration for, appraisal and development of oil and gas reserves.

As described in the Chairman's statement, an investigation into the procurement of legal services in Ukraine, and subsequent payments made to legal advisers, was commissioned by the Audit Committee in Q1 2018 and is now complete. While this investigation concluded there was a breakdown in the group's internal control in relation to the engagement and contracting with these legal advisers, the Committee has not been able to conclude on the nature of the payments made in 2017, and the extent to which these were valid payments for legal services provided. The current Board has introduced a number of measures to strengthen the Company's internal control systems and has reviewed legal costs incurred in 2018 and is satisfied as to the nature of such costs.

2. Basis of preparation

The preliminary results, which are unaudited, do not include all the notes of the type normally included in an annual financial report. Accordingly, this unaudited preliminary announcement does not constitute financial statements as defined by the Companies Act 2006 and should therefore be read in conjunction with the Annual Report for the year ended 31 December 2018, and any public announcements made by the Group during the reporting period. The annual financial report for the year ended 31 December 2018 was prepared in accordance with International Financial Reporting Standards as adopted by the European Union ("IFRS's") and the accounting policies applied in this preliminary announcement are consistent with the polices applied in the annual financial report for the year ended 31 December 2017 unless otherwise noted. The annual financial report for the year ended 31 December 2017 has been filed with the Registrar of Companies at Companies House. The audit report on these financial statements was qualified, making reference to a limitation of scope in respect of legal fees paid in the Ukraine. It is anticipated that the audit report on the consolidated financial statements for the year ended 31 December 2018 will also include a limitation of scope in respect of this comparative Ukrainian legal fee issue.

Comparatives

Comparative amounts in respect of deferred tax assets, liabilities, non-current other receivables and other payables have been reclassfied for comparability with 2018 in accordance with IFRS. The reclassifications had no impact on net assets or the loss for the period.

§ In the 2017 Annual report deferred tax assets of $20.8m and liabilities of $14.9m were presented gross, whereas in the 2018 Annual report the 2017 deferred tax assets of $11.3m and liabilities of $5.4m are presented net. Deferred tax assets and liabilities are offset where 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.

§ In the 2017 Annual report defined pension benefit plan liabilities of $0.5m were included in current trade and other payables, whereas in the 2018 Annual report they are presented separately under non-current liabilities.

§ Non-current other receivables of $3.1m and payables of $3.1m consisting of VAT were presented gross in the 2017 Annual report, whereas in the 2018 Annual report they are presented net reflecting that the amounts arise in the same taxable entity and are settled on a net basis.

Going concern

Background to the Group's performance and funding, including significant developments over the past year, is provided in the Financial Review. The Directors have reviewed the Group's forecast cash flows for the period to June 2020. Capital and operating costs are based on approved budgets and latest forecasts in the case of 2019 and current development plans in the case of 2020. The forecast cash flows reviewed include scenarios where potential liabilities arise in relation to the rental fee claims in Ukraine (see Note 10) including assessments of the timing of such potential payments undertaken following detailed analysis of Ukrainian legislation and the status of each claim with internal and external legal and tax experts. In addition the Directors have considered further scenarios that reflect future expectations regarding country, commodity price and currency risks that the Group may encounter. None of the scenarios have recognised any possible future benefit that may result from the arbitration award (see Note 10). Based on the Group's cash flow forecasts, the Directors believe that the combination of its current cash balances, expected future production and resulting net cash flows from operations, as well as the availability of additional courses of action with respect to financing the settlement of any successful rental fee claims arising in the forecast period, mean that the Group currently has adequate cash and other available resources to meet its liabilities and commitments as they fall due across the forecast period. One key means of such financing is the Tascombank loan of UAH280m ($10.1m) and overdraft facility of UAH50m ($1.8m) that was renewed and increased in December 2018 and that the Directors are confident will continue to be available throughout the forecast period beyond its current maturity date of December 2019 given operating cash flows, the recent renewal and increase and the security package available. Having considered the forecasts and reasonable sensitivity scenarios the Board considers it is appropriate to adopt the going concern basis of accounting in preparing the financial information.

3. Significant accounting policies

Adoption of new and revised standards

New standards, interpretations and amendments effective from 1 January 2018

The disclosed policies have been applied consistently by the Group for both the current and previous financial year with the exception of the new standards adopted.

The European Union ("EU") IFRS financial information has been drawn up on the basis of accounting policies consistent with those applied in the financial statements for the year to 31 December 2017, except for the following:

(a) IFRS 2 Share Based Payments (Amendment - Classification and Measurement of Share-Based Payment Transactions)

(b) Annual Improvements to IFRSs 2014 - 2016 Cycle (IFRS 1 First-time Adoption of IFRS, IFRS 12 Disclosures of interest in Other Entities and IAS 28 Investments in Associates and Joint Ventures)

(c) IFRIC Interpretation 22 'Foreign Currency Transactions and Advance Consideration'

(d) IFRS 9 'Financial instruments'

(e) IFRS 15 'Revenue from contracts with customers'

The application of (a) to (c) has had no impact on the disclosures or the amounts recognized in the Group's consolidated financial statements.

There were no retrospective adjustments as a result of adopting the new standards (d) and (e) listed below. The Group amended accounting policies applied from 1 January 2018 are disclosed in Note 3 under 'Significant accounting policies'.

IFRS 15 'Revenue from contracts with customers'

The IASB has issued a new standard for the recognition of revenue. This replaced IAS 18 which covers contracts for goods and services and IAS 11 which covers construction contracts. The new standard is based on the principle that revenue is recognised when control of a good or service transfers to a customer.

To assess the impact of IFRS 15 on the Group's revenue recognition, a 5-step model had been applied to analyse sales contracts in Ukraine, Russia and Hungary. According to the analysis carried out by the Group, the current practice of revenue recognition complies with the new IFRS 15 revenue recognition standard and there was no impact from the adoption of the new standard on 1 January 2018.

IFRS 9 'Financial instruments'

IFRS 9 replaces the provisions of IAS 39 that relate to the recognition, classification and measurement of financial assets and financial liabilities, derecognition of financial instruments, impairment of financial assets and hedge accounting. The classification depends on the entity's business model for managing the financial assets and the contractual terms of the cash flows. Financial assets are derecognised when the rights to receive cash flows from the financial assets have expired or have been transferred and the group has transferred substantially all the risks and rewards of ownership.

From 1 January 2018, the Group classifies its financial assets in the following measurement categories:

Those to be measured at amortised cost

Trade and intergroup receivables are held to collect contractual cash flows and are expected to give rise to cash flows representing solely payments of principal and interest. The Company analysed the contractual cash flow characteristics of those instruments and concluded that they meet the criteria for amortized cost measurement under IFRS 9. Therefore, reclassification for these instruments is not required.

IFRS 9 sets out a new forward looking 'expected loss' impairment model which replaces the incurred loss model in IAS 39 and applies to financial assets classified at amortised cost, debt instruments measured at FVOCI, contract assets under IFRS 15 Revenue from Contracts with Customers, intergroup receivables, lease receivables, loan commitments and certain financial guarantee contracts. Under the IFRS 9 'expected credit loss' model, a credit event (or impairment 'trigger') no longer has to occur before credit losses are recognised. It is therefore appropriate that the Group's policy for recognition of trade and other receivables is amended.

Based on the review of the historic occurrence of credit losses, consideration of prospective factors and given the short-term nature of trade and other receivables and the Group's active management of credit risk, the Group did not identify any credit losses requiring provision except for specific items in Note 8. The outlook for the oil and gas industry is not expected to result in a significant change in the Group's exposure to credit losses.

Those to be measured subsequently at fair value (either through OCI, or through profit or loss)

Investments in unquoted equity instruments were previously measured at cost less impairment as allowed by IAS 39. As of 1 January 2018 investments in equity instruments were reclassified to financial assets at fair value through other comprehensive income. The Group has made an irrevocable election at the time of initial recognition to account for the equity investment at fair value through other comprehensive income (FVOCI). Movements in the carrying amount are taken through OCI, except for the recognition of impairment gains or losses, interest income and foreign exchange gains and losses which are recognised in profit or loss. There was no impact of reclassification on the carrying value of its unlisted investment. Please refer to Note 6 for details.

Financial liabilities

Financial liabilities held by the Group comprise trade and other payables and Convertible Bonds due 19 February 2020. Convertible Bonds were restructured on 3 January 2017. The Group has reviewed its financial liabilities and there was no impact from the adoption of the new standard on 1 January 2018.

Under IAS 39 the revised terms and conditions of the Bond were considered to be a modification and therefore the difference in the amortised cost carrying amount at the modification date was recognised through a change in the effective interest rate at the modification date through to the end of the revised estimated term of the Bond. In accordance with IFRS 9, following a modification or renegotiation of a financial asset or financial liability that does not result in de-recognition, an entity is required to recognise any modification gain or loss immediately in profit or loss. Any gain or loss is determined by recalculating the gross carrying amount of the financial liability by discounting the new contractual cash flows using the original effective interest rate. The difference between the original contractual cash flows of the Bond and the modified cash flows discounted at the original effective interest rate is immaterial and hence there is no impact on adoption of IFRS 9 on 1 January 2018.

New standards, interpretations and amendments not yet effective

Below is a list of new and revised IFRSs that are not yet mandatorily effective (but allow early application) for the year ending 31 December 2018 and have not been early adopted by the Group. The Group's assessment of the impact of these new standards and interpretations is set out below:

Effective as of 1 January 2019, IFRIC 23 explains how to recognise and measure deferred and current income tax assets and liabilities where there is uncertainty over a tax treatment. An uncertain tax treatment is any tax treatment applied by an entity where there is uncertainty over whether that treatment will be accepted by the tax authority. IFRIC 23 applies to all aspects of income tax accounting where there is an uncertainty regarding the treatment of an item, including taxable profit or loss, the tax bases of assets and liabilities, tax losses and credits and tax rates. There will be no impact on adoption of IFRIC 23 on 1 January 2019, as detailed disclosures on judgements and estimates used in calculation of taxation as well as rental fees and deferred tax assets are included in accounting policies under 'critical accounting estimates, assumptions and judgements' and Notes 27 and 28.

IFRS 16 specifies how to recognize, measure, present and disclose leases. The standard provides a single lessee accounting model, requiring lessees to recognize right-of-use assets and lease liabilities for all material leases. It will result in almost all leases being recognised on the balance sheet by lessees, as the distinction between operating and finance leases is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term and low-value leases. The Group's well service and rental arrangements in Ukraine for oil and gas extraction activities are outside of the scope of IFRS 16.

The Group's accounting policy under IFRS 16 will be as follows: at inception of a contract, the Group will assess whether a contract is, or contains, a lease based on whether the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

The Group will recognize a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset will be initially measured based on the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.

The assets will be depreciated to the earlier of the end of the useful life of the right-of-use asset or the lease term using the straight-line method as this most closely reflects the expected pattern of consumption of the future economic benefits. The lease term will include periods covered by an option to extend if the Group is reasonably certain to exercise that option. Lease terms range from two to three years for offices. Service agreements for equipment on the working sites are not considered leases. In addition, the right-of-use asset is periodically reduced by impairment losses, if any, and adjusted for certain remeasurements of the lease liability.

The lease liability will be initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Group's incremental borrowing rate. Generally, the Group will use its incremental borrowing rate as the discount rate. The lease liability will be measured at amortized cost using the effective interest method. It will be remeasured when there will be a change in future lease payments arising from a change in an index or rate, if there is a change in the Group's estimate of the amount expected to be payable under a residual value guarantee, or if the Group changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment will be made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

The Group will elect to apply the practical expedient not to recognize right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less and leases of low-value assets.

The lease payments associated with these leases will be recognized as an expense on a straight-line basis over the lease term.

The Group is planning to adopt IFRS 16 from 1 January 2019 using the modified retrospective approach and accordingly the information presented for 2018 is not going to be restated. It would remain as previously reported under IAS 17 and related interpretations. On initial application, the Group will elect to record right-of-use assets based on the corresponding lease liability. A right-of-use assets and lease obligations of $0.8m will be recorded as of 1 January 2019, with no net impact on retained earnings. When measuring lease liabilities, the Group will discount lease payments using its incremental borrowing rate at 1 January 2019. The weighted-average rate applied is 17%.

The Group has not elected to apply the practical expedient to grandfather the assessment of which transactions are leases on the date of initial application, as previously assessed under IAS 17 and IFRIC 4. The Group will apply the definition of a lease under IFRS 16 to all existing contracts.

The following table reconciles the Group's operating lease obligations at 31 December 2018, as disclosed in the Group's consolidated financial statements, to the lease obligations recognized on initial application of IFRS 16 at 1 January 2019.

Non-current assets held for sale and discontinued operations

A discontinued operation is a component of the entity that has been disposed of or is classified as held for sale and that represents a separate major line of business or geographical area of operations, is part of a single co-ordinated plan to dispose of such a line of business or area of operations, or is a subsidiary acquired exclusively with a view to resale.

Assets that are classified as held for sale are carried at the lower of carrying amount and fair value less costs to sell. An asset classified as held for sale is not depreciated.

Non-current assets (or disposal groups) are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at the lower of their carrying amount and fair value less costs to sell, except for assets such as deferred tax assets, and financial assets within the scope of IFRS 9, which are specifically exempt from this requirement.

Non-current assets classified as held for sale and the assets of a disposal group classified as held for sale are presented separately from the other assets in the statement of financial position. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the statement of financial position.

Any gain or loss from disposal, together with the results of these operations until the date of disposal, is reported separately as discontinued operations. The financial information of discontinued operations is excluded from the respective captions in the Consolidated financial information and related notes for all periods presented. Comparatives in the statement of financial position are not represented when a non-current asset or disposal group is classified as held for sale. Comparatives are represented for presentation of discontinued operations in the Statement of cash flow and Statement of comprehensive income. Further information on discontinued operations and non-current assets held for sale can be found in note 8 "Discontinued operations and assets classified as held for sale".

Exceptional items

Exceptional items comprise items of income and expense, including tax items, that are material either because of their size or their nature and unlikely to recur and which merit separate disclosure in order to provide an understanding of the Group's underlying financial performance. Examples of events which may give rise to the disclosure of material items of income and expense as exceptional items include, but are not limited to, impairment events, disposals of operations or individual assets, litigation claims by or against the Group and the restructuring of components of the Group's operations. Exceptional items are disclosed separately on the face of the income statement.

Critical accounting estimates, assumptions and judgements

The Group makes estimates, assumptions and judgements concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates, assumptions and judgements that have a risk of causing material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

a) Recoverability of oil and gas assets and intangible oil and gas costs (Note 5 (a))

Costs capitalised as oil and gas assets in property, plant and equipment, and intangible assets are assessed for impairment when circumstances suggest that the carrying value may exceed its recoverable value. As part of this assessment, management has carried out an impairment test (ceiling test) on the oil and gas assets classified as property, plant and equipment, where indicators of impairment have been identified on a CGU. This test compares the carrying value of the assets at the reporting date with the expected discounted cash flows from each project prepared under the fair value less cost of disposal approach. For the discounted cash flows to be calculated, management has used a production profile based on its best estimate of proven and probable reserves of the assets and a range of assumptions, including an internal oil and gas price profile benchmarked to mean analysts' consensus and a discount rate which, taking into account other assumptions used in the calculation, management considers to be reflective of the risks. This assessment involves judgement as to (i) the likely commerciality of the asset, (ii) proven, probable ('2P') reserves which are estimated using standard recognised evaluation techniques (iii) future revenues and estimated development costs pertaining to the asset, (iv) the discount rate to be applied for the purposes of deriving a recoverable value, (v) . In cases where impairment tests demonstrate headroom, reversals of impairment charges are not recognised in the Group income statement if the existence of the headroom is sensitive to pricing, production or discount rates.

b) Carrying value of intangible exploration and evaluation expenditure (Note 5 (b))

The carrying value for intangible exploration and evaluation assets represent the costs of active exploration projects the commerciality of which is unevaluated until reserves can be appraised. Where properties are appraised to have no commercial value, the associated costs are treated as an impairment loss in the period in which the determination is made. The recoverability of intangible exploration assets is assessed by comparing the carrying value to estimates of the present value of projects where indicators of impairment have been identified on an asset. The present values of intangible exploration assets are inherently judgemental. Exploration and evaluation costs will be written off to the income statement unless commercial reserves are established or the determination process is not completed and there are no indications of impairment. The outcome of ongoing exploration, and therefore whether the carrying value of exploration and evaluation assets will ultimately be recovered, is inherently uncertain.

c) Depreciation of oil and gas assets (Note 5 ((a))

Oil and gas assets held in property, plant and equipment are mainly depreciated on a unit of production basis at a rate calculated by reference to proven plus probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells, future production facilities and operating costs; together with assumptions on oil and gas realisations based on the approved field development plans.

d) Taxation including rental fees and deferred tax assets (Note 10)

Tax provisions are recognised when it is considered probable that there will be a future outflow of funds to the tax authorities. In this case, provision is made for the amount that is expected to be settled. The provision is updated at each reporting date by management by interpretation and application of known local tax laws with the assistance of established legal, tax and accounting advisors. These interpretations can change over time depending on precedent set and circumstances in addition new laws can come into effect which can conflict with others and, therefore, are subject to varying interpretations and changes which may be applied retrospectively. A change in estimate of the likelihood of a future outflow or in the expected amount to be settled would result in a charge or credit to income in the period in which the change occurs.

Tax provisions are based on enacted or substantively enacted laws. To the extent that these change there would be a charge or credit to income both in the period of charge, which would include any impact on cumulative provisions, and in future periods.

Deferred tax assets are recognised only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse, and a judgement as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the level of deferred tax assets recognised that can result in a charge or credit in the period in which the change occurs.

e) Provisions for decommissioning costs (Note 9)

Estimates of the cost of future decommissioning and restoration of production facilities are based on current legal and constructive requirements, technology and price levels, while estimates of when decommissioning will occur depend on assumptions made regarding the economic life of fields which in turn depend on such factors as oil and gas prices, decommissioning costs, discount rates and inflation rates. The management reviewed the estimation process and the basis for the principal assumptions underlying the cost estimates, noting in particular the reasons for any major changes in estimates as compared with the previous year. The Group was satisfied that the approach applied was fair and reasonable. The Group was also satisfied that the discount and inflation rates used to calculate the provision were appropriate. The discount rates were based on government bonds issued in the respective countries.

f) Judgement used in the fair value of unlisted investments (Note 6)

The fair value of financial instruments that are not traded in an active market is determined by using valuation techniques. The objective of a fair value measurement is to estimate the price at which an orderly transaction would take place between market participants under the market conditions that exist at the measurement date. IFRS 13 requires that valuation techniques maximise the use of observable inputs and minimise the use of unobservable inputs. The Group has used a market approach to estimate fair value of the unlisted investments. The Group used its judgements to (i) select a valuation method, (ii) make assumptions that are based on market conditions existing at the end of the reporting period, (iii) determine the point in a range of values that is 'most representative of a fair value', (iv) determine discounts applied to the fair value.

g) Enforcement of arbitration award (Note 10)

No asset has been recognised in respect of the arbitration award due to the uncertainty inherent in the process for, and likely success of, enforcing collection.

h) Exceptional items (Note 5 and 10)

Judgment is required when determining whether items meet the definition of 'exceptional' under the Group's accounting policy. Impairments and reversals of impairments reflecting specific circumstances including strategic re-focusing of the business, changes arising due to unusual market conditions or geopolitical factors are considered to qualify as exceptional items. 

Provisions for August to December 2010 and January to December 2015 rental fee claims have been included in 'exceptional items' due to their material, specific and unusual nature and the Board considered that it was appropriate to highlight these items to users of the financial information. In particular, the issues are considered to represent isolated historical disputes that will not recur having related to specific circumstances and discrete periods of time with production based taxes currently paid at standard Ukrainian government rates. Whilst the Board is cognisant that items should not be disclosed as exceptional when they recur, in this instance the Board considered items to be exceptional, because the two underlying claims are not anticipated to recur and the additional charges refer to accrual of interest and penalties of the original claims.

4. Segmental analysis

The Group has one single class of business, being the exploration for, evaluation, development and production of oil and gas reserves. Accordingly the reportable operating segments are determined by the geographical location of the assets.

There are four (2017: four) reportable operating segments which are based on the internal reports provided to the Chief Operating Decision Maker ('CODM'). Ukraine and Russia segments are involved with production and exploration; the 'Rest of World' are involved in exploration, development and production and the UK is the home of the head office and purchases material, capital assets and services on behalf of other segments.

The Group derives revenue from the transfer of goods at a point in time. The Group is only engaged in one business of upstream oil and gas exploration and production, therefore all information is being presented for geographical segments. This is consistent with the revenue information that is disclosed for each reportable segment under IFRS 8 Operating Segments.

Segment revenue, segment expense and segment results include transfers between segments. Those transfers are eliminated on consolidation.

Segment results and assets include items directly attributable to the segment. Segment assets consist primarily of property, plant and equipment, inventories and receivables. Capital expenditures comprise additions to property, plant and equipment and intangible assets.

1 Total assets and liabilities exclude assets and liabilities of the Hungarian disposal group classified as held for sale. Please refer to Note 8 for details

1 Assets and liabilities include Hungary at 31 December 2017 within 'Rest of the World'. The loss before tax excludes the loss of the Hungarian disposal group classified as held for sale in 2018 with the comparative results of the disposal group reclassified to discontinued operations. Please refer to Note 8 for details

There are two customers, one in Ukraine and one in Russia, that exceed 10% of the Group's total revenues (2017: one in Russia).

5. Property, plant and equipment and Intangible assets

5.(a) Property, plant and equipment

Exceptional item - provision for impairment of oil and gas assets

During 2017 and 2018 impairment test triggers were identified in respect of our oil and gas assets with impairments and reversals of impairments recorded in 2017. Full impairment disclosures for each of the impairment tests are made in the Note 5 (c).

5.(b) Intangible assets: exploration and evaluation expenditure

Exceptional item - write off of appraisal expenditure in Ukraine and provision for impairment of intangible assets

Full details are provided in the Note 5 (d).

5.(c) Impairment test for property, plant and equipment

A review was undertaken at the reporting date of the carrying amounts of property, plant and equipment to determine whether there was any indication of a trigger that may have led to these assets suffering an impairment loss. Following this review impairment triggers were noted in relation to the Ukrainian and Russian assets due to the carrying amount of the Group net assets exceeding the Company's market capitalisation.

As there is no readily available market for the Group's oil and gas properties, fair value is derived as the net present value of the estimated future cash flows arising from the continued use of the assets, incorporating assumptions that a typical market participant would take into account.

The value in use of an oil and gas property is generally lower than its Fair Value Less Costs of Disposal ('FVLCD') as value in use reflects only those cash flows expected to be derived from the asset in its current condition. FVLCD includes appraisal and development expenditure that a market participant would consider likely to enhance the productive capacity of an asset and optimise future cash flows. Consequently, the Group determines recoverable amount based on FVLCD using a Discounted Cash Flow ('DCF') methodology.

The DCF was derived by estimating discounted after tax cash flows for each CGU based on estimates that a typical market participant would use in valuing such assets.

The impairment tests compared the recoverable amount of the respective CGUs noted below to the respective carrying values of their associated assets. The estimates of FVLCD meet the definition of level three fair value measurements as they are determined from unobservable inputs.

Impairment test for the Ukrainian oil and gas assets

Poltava Petroleum Company ('PPC'), a wholly owned subsidiary of JKX, holds 100% interest in five production licences (Ignativske, Movchanivske, Rudenkivske, Novomykolaivske, Elyzavetivske) and one exploration licence (Zaplavska) in the Poltava region of Ukraine.

The Ignativske, Movchanivske, Rudenkivske, Novomykolaivske production licences contain one or more distinct fields which, together with the Zaplavska exploration licence, form the Novomykolaivske Complex ('NNC').

The Elyzavetivske production licence is located 45km from the Novomykolaivske Complex and has its own gas production facilities.

Ukrainian Cash Generating Units ('CGUs')

In respect of the Group's Ukraine assets the NNC forms a single CGU as these contain oil and gas fields which are serviced by a single processing facility and do not have separately identifiable cash inflows. In addition they have commonality of facilities, personnel and services.

The Elyzavetivske licence also has its own separate processing facilities and separately identifiable cash flows and therefore is a distinct CGU for the purpose of the impairment test. During 2015 an extension to the Elyzavetivske production licence was awarded to PPC which included the West Mashivska field. Due to the proximity of the West Mashivska field to the Elyzavetivske plant, production will be tied back to the Elyzavetivske processing facilities and therefore forms part of this CGU.

In accordance with IAS 36, the impairment review was undertaken in US$ being the currency in which future cash flows from NNC and Elyzavetivske will be generated.

Key Assumptions - NNC and Elyzavetivske

The key assumptions used in the impairment testing were:

§ Production profiles: these were based on the latest available information assessed internally. Such information included 2P reserves for NNC and Elyzavetivske of 21.7 MMboe and 2.5 MMboe, respectively.

§ Economic life of field: it was assumed that the title to the licences is retained and that the NNC licence term will be successfully extended beyond its current 2024 expiration date through to the economic life of the field (expected to be around 2035). The economic life of the Elyzavetivske field is currently expected to be around 2029 as per management's current expectation.

§ Gas prices: during 2015 Ukraine acquired the ability to purchase gas from Europe rather than being completely dependent on Russia for imports. As such, Ukrainian gas prices are expected to be more aligned with European gas prices in future but also influenced by Russian-Ukrainian border price and international oil prices. The gas price used for 2019 is based on current and forecast gas prices realised by our Ukrainian subsidiary. For the following ten years a forward gas price curve was used with gas prices remaining constant thereafter.

§ Oil prices: the Company used a forward price curve for the next ten years and remaining constant thereafter.

§ Production taxes: the Company has assumed production tax rates of 29% for gas and oil. A gas tax rate of 12% is applied to new wells. 

§ Capital and operating costs: these were based on current operating and capital costs in Ukraine for both projects. Estimates were provided by third parties and supported by estimates from our own specialists, where necessary.

§ Post tax nominal discount rate of 19.1%. This was based on a Capital Asset Pricing Model analysis consistent with that used in previous impairment reviews.

§ Based on the key assumptions set out above:

§ the recoverable amount of NNC's oil and gas assets ($105.5m) exceeds its carrying amount ($83.0m) by $22.5m and therefore NNC's oil and gas assets were not impaired.

§ Elyzavetivske's recoverable amount (including the West Mashivska extension) ($14.6m) exceeds its carrying amount ($8.0m) by $6.6m, and therefore the CGU's oil and gas assets were not impaired.

Elyzavetivske impairment reversal in 2017

During 2014 the Elyzavetivske field was impaired by $12.8m after significant erosion of the headroom from 2013. The main driver of the impairment was the reduction in reserves. Had this impairment not been made, then the carrying value of Elyzavetivske would have been $6.1m as at 31 December 2017. Therefore, a reversal of $5.6m was recognised in 2017.

Sensitivity analysis for the NNC and Elyzavetivske

Any impairment is dependent on judgement used in determining the most appropriate basis for the assumptions and estimates made by management, particularly in relation to the key assumptions described above. Sensitivity analysis to likely and potential changes in key assumptions has therefore been provided below.

The impact on the impairment calculation of applying different assumptions to gas prices, production volumes, future capital expenditure and post-tax discount rates, all other inputs remaining equal, would be as follows:

Impairment test for Yuzhgazenergie LLC ('YGE'), Russia

Following the 2007 acquisition of YGE in Russia, a technical and environmental re-evaluation of YGE's Koshekhablskoye gas field redevelopment was undertaken by the Group. The re-evaluation resulted in a revised development plan and production profile. The development plan and production profile have continued to be refined since that time.

In accordance with IAS 36, the impairment review has been undertaken in Russian Roubles, which is the functional currency of YGE.

Key Assumptions - YGE

The key assumptions used in the impairment testing were:

§ Production profiles: these were based on the latest available information assessed internally. Such information included 2P reserves for YGE of 69.8 MMboe.

§ Economic life of field: it was assumed that YGE will be successful in extending the licence term beyond its current 2026 expiration to the economic life of the field (expected to be around 2049). The discounted cash flow methodology used has not taken account of any opportunities that may exist to extract reserves in a shorter timeframe by investing to increase the current plant capacity.

§ Gas prices: from 1 July 2019 and annually thereafter, the gas prices have been increased by 4.0% through to 2026 based on historical experience.

§ Capital and operating costs: these were based on current operating and capital costs in Russia, project estimates provided by third parties and supported by estimates from our own specialists, where necessary.

§ Post tax nominal Rouble discount rate of 13.6%. This was based on a Capital Asset Pricing Model analysis consistent with that used in previous impairment reviews.

Based on the key assumptions set out above YGE's recoverable amount ($104.7m) exceeds it carrying amount ($80.6m) by $24.1m and therefore YGE's Koshekhablskoye gas field was not impaired.

Any impairment is dependent on judgement used in determining the most appropriate basis for the assumptions and estimates made by management, particularly in relation to the key assumptions described above. Sensitivity analysis to likely and potential changes in key assumptions has therefore been reviewed below.

The impact on the impairment calculation of applying different assumptions to gas prices, production, future capital expenditure and post-tax discount rates, all other inputs remaining equal, would be as follows:

Sensitivity Analysis

Impairment test for Hungarian oil and gas assets in 2017

As a result of impairment testing of Hungarian oil and gas assets, the carrying amount exceeded the CGU's recoverable amount of nil by $2.8m and therefore the assets were impaired to nil due to the reduction in the estimated recoverable oil and gas volumes from this field.

5.(d) Appraisal expenditure written off and impairment test for intangible assets

Exceptional item in 2017 - appraisal expenditure written off

After the well stimulation programme to target contingent resources in the Northern part of Rudenkivske two of the wells were abandoned due to lack of gas production. Other wells are only expected to produce insignificant quantities of gas. The total amount of written off expenditure was $9.4m.

Impairment of Hungarian exploration and evaluation expenditure in 2017

The Tiszavasvári-IV Mining Plot contains the Tiszavasvári-6 discovery well ('TZ-6'), which, due to the early stage of appraisal, was classified as an exploration and appraisal asset and recognised within intangible assets.

In 2017, the absence of a firm work programme at year end to develop the Hungarian reserves constituted an impairment trigger and accordingly an impairment test was undertaken. At year end there were no further exploration or evaluation planned or budgeted. There was no clear indication that FVLCD was greater than zero and the assets were impaired in full by $0.8m.

Impairment of Slovakian exploration and evaluation expenditure in 2017

During 2017 there was no progress with the exploration licences in Slovakia and at year end there was no further exploration or evaluation planned or budgeted. There was no clear indication that FVLCD was greater than zero and the assets were impaired in full by $7.9m.

6. Investments

Group unquoted equity investments comprise a 10% holding of the ordinary share capital of PJSC of "Mining Company Ukrnaftoburinnya" ("UNB"), a Ukrainian oil and gas company, and a 1.43% holding of the ordinary share capital of Linx Telecommunications holding B.V. ("Linx"), a Netherlands telecommunications company. These investments were previously measured at cost as allowed by IAS 39 (paragraph 46 (c)) and were fully impaired at 31 December 2017 and had been for several years.

As of 1 January 2018 Group's investments in equity instruments were reclassified to financial assets at fair value through other comprehensive income in accordance with the provisions of IFRS 9. The Group has made an irrevocable election at the time of initial recognition to account for the equity investment at fair value through other comprehensive income (FVOCI).

At 31 December 2018 the carrying value of UNB remained fully impaired following assessment by the Board considering relevant available information and valuation techniques, reflecting:

§ the lack of liquidity in the shares of UNB and considerations regarding the nature of markets for such an investment;

§ the absence of any history of dividends or other returns on the investment since acquisition in 2006 and the significant uncertainty regarding future returns;

§ the absence of regular formal communication with UNB or potential buyers; and

§ the level of uncertainty regarding any market valuation method based on quoted Ukrainian oil and gas companies given key differences in the respective businesses and corporate structures;

§ the limited number of quoted Ukrainian oil and gas companies that can be used for the market valuation approach, defined in IFRS 13.

At 31 December 2018 the carrying value of Linx remained fully impaired following assessment by the Board considering relevant available information and valuation techniques, reflecting:

§ the lack of liquidity in the shares of Linx and considerations regarding the nature of markets for such an investment;

§ the absence of dividends or other returns on its investment since the investment acquisition in 2002 (apart from a one-off dividend received during 2017 of $0.1m due to reorganisation of Linx).

§ the absence of formal communication with any potential buyers; and

§ the level of uncertainty regarding any market valuation method based on the limited number of quoted Netherlands telecommunication companies and key differences in the respective businesses.

7. Borrowings

Convertible bonds due 2020

On 19 February 2013 the Company successfully completed the placing of $40m of guaranteed unsubordinated convertible bonds with institutional investors which were due 2018 (prior to restructuring) raising cash of $37.2m net of issue costs.

Prior to restructuring the Bonds had an annual coupon of 8 per cent per annum payable semi-annually in arrears.

The Bonds are convertible into ordinary shares of the Company at any time from 1 April 2013 up until seven days prior to their maturity on 19 February 2020 at a conversion price of 76.29 pence per Ordinary Share, unless the Company settles the conversion notice by paying the Bondholder the Cash Alternative Amount (see below).

Convertible bonds restructured on 3 January 2017

On 3 January 2017 a special resolution was approved by Bondholders to change the terms and conditions of the Bonds. The main amendments to the terms and conditions of the Bonds were as follows:

§ the Bondholder's option to require redemption of all of the outstanding Bonds on 19 February 2017 was deleted;

§ the final maturity date of the Bonds was extended to 19 February 2020, with the outstanding principal amount of the Bonds being repaid in three instalments; 33% on 19 February 2018; 33 % on 19 February 2019; and 34% on the 19 February 2020;

§ the coupon rate of the Bonds was increased from 8% to 14%;