JKX.L Regulatory News (JKX)

FOR IMMEDIATE RELEASE 29 March 2018

JKX Oil & Gas plc

('JKX' or the 'Company')

PRELIMINARY RESULTS

FOR THE YEAR ENDED 31 DECEMBER 2017

JKX Oil & Gas plc (LSE: JKX), announces its unaudited preliminary results for the year ended 31 December 2017.

Key financials

· Revenue: $76.4m (2016: $73.8m)

· Pre-exceptional earnings before interest, tax, depreciation and amortisation: $25.3m (2016: $15.8m)

· Profit from operations before exceptional charges: $7.8m (2016: $3.9m loss)

· Exceptional charges: $21.1m (2016: $30.8m)

· Loss for the year: $17.7m (2016: $37.1m)

· Loss per share: 10.26 cents (2016: 21.56 cents)

· Net cash generated from operating activities: $11.0m (2016: $14.6m)

· Capital expenditure: $16.7m (2016: $7.5m)

· Total cash: $7.4m (2016: $14.3m)

· Net debt: $9.2m (2016: $2.5m)

Audited results will be issued pending the completion of the forensic examination being performed by KPMG, as noted in the Chairman's statement below, and its review by the Board of Directors and the Company's auditors PwC.

For further information please contact:

EM Communications +44 (0) 20 3709 5711

Stuart Leasor, Jeroen van de Crommenacker

Chairman's Statement

Dear shareholder, as you are aware, 2017 has been another difficult year for JKX with disappointing results and further changes in the Board and senior leadership teams.

The new Board, appointed at the end of 2017, inherited a company with significantly depleted cash balances, risk management and control systems that had failed to anticipate or address the challenges that 2017 presented and the need for a new strategy. In the light of this difficult scenario the new Board is reassessing the Company strategy based on its assessment of the current situation and prospects ahead.

The Board has identified the following as immediate areas of focus:

1. Restoring a constructive relationship with the shareholders of the Company;

2. Ensuring full operational and financial alignment between all companies of the Group;

3. Operational risk management, developing existing fields with proven, low risk technology;

4. Ensuring financial stability by building liquidity reserves, reducing debt and keeping tight control over cost;

5. Resolving outstanding tax issues.

Relationship with shareholders

The Board strives to make sure that the voices of all our shareholders, big and small, are heard and taken into account in our strategy and actions. We seek an active and open communication with all shareholders while at the same time emphasising the independent role of the Board. All decisions are taken in the interest of the Company as a whole.

As a further step to manifest our approach, our two major shareholders - Eclairs Group Limited ("Eclairs"), which owns 27.54% of our shares and Proxima Capital Group ("Proxima"), which owns 19.97% of our shares - now both have nominees on the Board, indicating a new sense of confidence, alignment and shared focus.

Ensure full operational and financial alignment between all companies of the group

The Board is currently reviewing key processes to ensure they are harmonised throughout the Group and that learnings are shared on a Group wide basis. Procedures for investments (Capex) and operations (Opex) are now measured against Group wide criteria for risk, financial reward and timing. Whilst there is more work to do, interim financial controls have been introduced to ensure that all material expenditure is subject to centralised approval. In the current situation projects with short payback period and low risk are prioritised.

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

In 2017, the Company set out to unlock its reserves potential. Key to this strategy was our Rudenkivske gas fields in Ukraine. The results were disappointing whilst significantly depleting cash balances. To make the best use of available resources, the Company will in the near future concentrate on proven low risk technologies to achieve incremental production increases from each well while keeping the investment for each project at a minimum. This will allow us to spread the risk over many wells, both own wells and leased wells. New technologies and larger projects will be considered when the Board is comfortable with the risks involved, the project meets established criteria and is also acceptable from a cash outlay point of view. Better utilization of the capacity of the existing plants will be another area of focus.

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

On June 30, 2017 the unrestricted cash of the group was at $4.0 million compared to $14.1 million on December 31, 2016. This abrupt decrease was mainly due to $10.4 million spent on capital expenditures in the first half of 2017 ($2.5 million in the first half of 2016) and payments to bondholders in February 2017.

The Board and the new executive team (which includes a new CFO with relevant regional, technical and language skills) are now focussed on using the group's positive operating cashflow to pay off the remaining debt on schedule and consolidate our cash reserves through:

1. Strengthening control over costs and future spending, and

2. Eliminating unnecessary contracts and enhancing procedures and discipline in entering into new ones.

Our unrestricted cash on hand increased to $6.9 million on December 31, 2017 and all planned payments to bondholders were successfully made in February 2018, thus repaying a third of the capital outstanding on the bonds on schedule.

The Company's Ukrainian subsidiary, Poltava Petroleum Company ("PPC"), has secured a standing credit line of approximately $5.3 million and the Russian subsidiary, YGE, is in negotiation for another standing credit line.

More effective governance

We have made a significant effort to create a culturally diverse and widely experienced Board consisting of individuals with knowledge and skills in each of the key areas of risk for the Company - technical and engineering, finance and controls, and funding and capital markets. Additionally, all of your Directors have significant experience of operating in Ukraine or Russia - key markets for JKX.

In the current circumstances, the Board has not yet been able to recruit the full executive team needed to resolve the many issues your Company faces. The Board has therefore, as an interim measure, deployed its range of skills and experience and is playing an unusually active role in the management and leadership of the Company, with the General Directors of the operating companies reporting on all matters directly to the Chairman of the Board.

We believe that the current composition of the Board, and in particular the highly experienced independent Directors that have recently joined the Board, will help the Company navigate this difficult period whilst reinforcing our strong commitment to Board independence. In addition to the non-executive Chairman, the number of independent directors has been increased from 2 to 3, while the number of non-independent directors has been reduced from 4 to 3.

System of internal controls

The current Board, together with the Audit Committee, has carried out a risk-based review of the effectiveness of the Company's internal control and risk management systems and has introduced a number of interim measures to strengthen them. This work is ongoing.

Specifically, a breakdown in controls occurred in the Company's Ukrainian subsidiary during 2017. Several legal advisers were engaged without a proper transparent tender process. These advisers were paid legal fees of approximately $1 million, for which there is a lack of documentation supporting the nature and extent of work performed. As a result, the Audit Committee has appointed KPMG to conduct a forensic examination of the process for appointment of legal advisers in Ukraine, the manner in which these specific payments were made and to investigate the nature of such payments and services provided. As at the date of this release, KPMG's investigation is ongoing and while preliminary recommendations have been made, no conclusive findings have yet been delivered to the Board.

Resolving outstanding tax issues

The Company has three material unresolved tax issues:

1. PPC has received a claim for underpayment of royalty for 2010. The claim, including interest and penalties, amounts to approximately $11.3 million. The claim is currently not being pursued due to a finding on technical grounds in favour of PPC by a court in Poltava. As a result, the tax notification was cancelled. The tax authorities' appeal against the decision was dismissed. The tax authorities have lodged another appeal with the Supreme Court.

2. PPC has received a claim for underpayment of royalty for 2015. The claim, including interest and penalties, amounts to approximately $25.8 million. The tax notification was subsequently cancelled. The case is still being contested in court.

3. PPC was awarded approximately $12.1 million by the Hague international tribunal in 2017. In response, the Government of Ukraine submitted an appeal to the UK High Court which was dismissed.

The Company will continue to defend its position in local courts. Given the materiality of these tax liabilities we have considered the risk to the Group's ability to continue as a going concern further in Note 2 to the financial information. Additional detail on tax litigation cases is provided in Note 27 to the financial information.

Outlook

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

In Ukraine, we expect to stabilize and, shortly, to increase production and take advantage of the favourable market conditions. We will increase the use of leased wells and stimulate the production from our own wells through the implementation of the revised workover program. This is a low risk undertaking consisting of numerous smaller steps to better utilize existing well stock and to drill at least one new infill well.

In Russia we will enhance our technical capabilities and broaden our work with drilling companies and other existing and new contractors to ensure the highest level of technical efficiency. The goal is to enhance our capabilities so as to complete future well workovers on budget and on time.

We see a gradually improved cashflow through the second half of 2018 as the revised strategy starts to yield results. This includes an unrelenting focus on internal control and cost optimization.

People

JKX has gone through significant Board and management change on two occasions in the past two years - a remarkable challenge by itself and especially considering the operating environment it has had to navigate. I would like to thank JKX's staff for ensuring continuity and smooth operations in times of change and for their continued faith in the Company.

Finally, I would like to thank Victor Gladun, who took over as Acting CEO in June 2017 and has now returned to his role as General Director of PPC, Dmitriy Poddubny who served as acting CFO during the latter part of 2017, and Ben Fraser, our new CFO, for stepping up and shepherding the Company through turbulent times towards future success.

Hans Jochum Horn

Chairman

Acting Chief Executive's Statement

2017 was another challenging year for JKX. Lack of positive results following the first stage of the Rudenkivske field fracturing programme and delays in the workovers of two wells in Russia have resulted in an overall production decline for the group of 14.1% from 10,083 boepd in 2016 to 8,658 boepd in 2017. As a result of the operational difficulties, the Company also went through major changes to senior management and the Board of Directors in the second half of the year.

At the same time, on the back of rising oil and gas prices group revenue was up by 3.5% year on year from $73.8m to $76.4m, while operating loss for the year decreased by 62% from ($34.8m) to ($13.2m).

Management was also able to achieve results that bode well for the future:

· In Ukraine a new field development program designed to enhance production from our core fields and engage in low-risk appraisal has been designed and its implementation has begun;

· In addition, we received access to 14 wells owned by state companies on our licenses;

· We restarted production in Hungary after more than a three-year break and sustained production throughout the year;

· Finally, the Company continued to optimize its cost base, reduced its overall debt (through repayment of its bond obligations) and made progress in its legal proceedings with Ukraine.

Ukraine

In Ukraine, overall production for the year was down by 12%. Gas production was down by 10% from 18.6 MMcfd in 2016 to 16.7 MMcfd in 2017, while oil production fell down by 20% from 902 boepd in 2016 to 719 boepd in 2017. Due to the increased price for oil and gas, our revenue was up by 4.0% (from US$54.8 to US$57.0 million) compared to 2016.

One of the key contributing factors to the decline in production was a focus on the ultimately unsuccessful first stage of the Rudenkivske field fracturing program during the first half of the year. Following the fracturing of four Soviet-era wells, which resulted in mostly water production, an extensive review resulted in the key conclusion that a significant amount of geological work is still required to understand this complicated reservoir before further significant expenditure can be justified.

On the positive side, we were able to secure access to 14 old wells that belong to Ukrainian state companies located on our licenses thereby creating opportunities to generate low-cost production through workovers in the future.

Our technical team in Ukraine, which underwent significant changes during the second half of the year, has refocused on our core producing fields and generated a new production enhancement program. Early results have been promising. After carrying out several successful workovers, the Company has returned to drilling after an almost three-year break.

Russia

In Russia, our year-on-year gas production was down by 18% from 36.1 MMcfd in 2016 to 29.8 MMcfd in 2017. Our revenue was down by 7.4 percent (from US$19.0 million to US$17.6 million). The key reason for the decline was delays in two well workovers. The planned production tubing replacement workover at Well 25 was significantly delayed due to a fire on the workover rig and the time required by the rig operator to procure the necessary equipment replacement. As a result, the well was offline for four months.

The workover of well 5 has also not gone as planned. Replacement of damaged tubing at the well took longer than expected and production has not started. A side-track will now have to be performed once a new rig can be secured.

Hungary

In 2017, we relaunched our production at the Hajdunanas field in Hungary for the first time in more than three years. The sidetrack of well Hn-2 was completed in January 2017 and gas sales began in February. This was followed by a successful workover of well Hn-1 completed in October. As a result, in 2017 average gas production was 0.7 MMcfd, while average condensate production was 9.6 bpd.

The Group is now pursuing a full divestment of its remaining Hungarian licence interests due to the refocus on its operations in Ukraine and Russia.

Slovakia

In Slovakia repeated delays to the drilling plans of the operator (Alpine Oil & Gas) have been caused by local protestors and lack of cooperation from authorities at both central and local levels. As a result, all project partners have been considering their future options. In early February 2018 the Board made a decision to withdraw from Slovakia.

Outlook

Since the arrival of the new senior management team and the new Board, we have significantly revised our field development plans in Ukraine.

Our plan for 2018 includes significant activity in Ukraine to boost production in our core fields and engage in low risk appraisal. This includes 12 workovers, 4 side-tracks and one new well. We plan to take advantage of the access we have gained to state-owned wells located on our licenses to target low-cost production enhancement opportunities. Our main development targets are production enhancement through evaluation of clastic reservoirs in the western part of the Ignativske field, infill drilling at the Elyzavetivske field, appraisal of the West Mashivske area of the Elyzavetivske license, and testing the deep Devonian horizons at our Movchanivske field.

Our approach to the development of the Rudenkivske field has changed significantly. The new field development plan now targets the Devonian horizons in the southern section of the field. This is where the Company was able to achieve the best results to date (wells R12 and R103) and where target depths are relatively shallow. Overall, compared to the previous Rudenkivske field development plan, the number of target wells and fracture stages have been significantly reduced.

Our plans in Ukraine are in part underpinned by significant reductions to royalty rates for new gas wells. Starting from January 1, 2018, new gas wells shallower than 5000 meters are taxed at the rate of 12% (instead of 29%). In addition, the recent passage of legislation that significantly deregulates the upstream industry gives us confidence that the Government of Ukraine is more supportive of new investment in gas production than before.

In Russia, we plan to contract a new workover rig for future operations and to complete a side-track of well 5 at our Koshekhablskoye field. Longer term our goal here is to increase production to the maximum operating capacity of our gas plant (60 million cubic feet per day).

Finally, I would like to thank our staff at all offices for their hard work during what was a very difficult period for JKX. I am proud of their commitment to our company and honoured to lead them during tough times. I am now confident that if we continue to persevere, together we will succeed in returning JKX to growth and financial success.

Victor Gladun

Acting Chief Executive Officer

Financial Review

Results for the year

The Group has reported a loss of $17.7m for 2017 compared to a loss of $37.1m for 2016. Both of these losses include significant exceptional charges: $17.0m in 2017 and $29.7m in 2016 (net of deferred tax effects of $4.1m in 2017 and $1.2m in 2016).

Further details on the exceptional items in 2017, which include the unsuccessful Rudenkivske fracturing program, movement in the provision for production based taxes for 2010 and 2015, severance payments and non-cash impairment movements, are included in this review below.

The Group has reported a loss before exceptional items of $0.7m for 2017 which compares favourably to the loss before exceptional items of $7.5m for 2016.

Revenue

Although total Group production decreased 14.4% from 3,691 Mboe in 2016 to 3,160 Mboe in 2017, annual revenue increased 3.5% to $76.4m (2016: $73.8m) thanks to higher commodity prices in both Ukraine and Russia. It continues to be the case that our gas sales prices and netbacks are significantly higher in Ukraine than in Russia.

Ukraine revenues

The $2.2m increase in total revenues was due to the sales price increases shown in the table, the effects of which were offset by the decrease in total sales volumes from 1,336 Mboe in 2016 to 1,144 Mboe in 2017.

In dollar terms the average gas sales price increased by 13.5% from $5.92/Mcf in 2016 to $6.72/Mcf in 2017. This reflects both the 15.3% increase in average sales price in hryvnia terms from 5,379 UAH/Mcm in 2016 to 6,352 UAH/Mcm in 2017 and the hryvnia being weaker in 2017 than 2016. Since 2015 gas prices in Ukraine have been more closely following global market trends, and the increase in price of gas imported from Europe is a reason for the higher average gas sales price in 2017.

Total annual gas sales volumes decreased 12.2% from 171,828 Mcm in 2016 to 150,909 Mcm in 2017, primarily due to the annual gas production volume having decreased 10.3% from 192,732 Mcm in 2016 to 172,939 Mcm in 2017 (from 3,109 boepd in 2016 to 2,789 boepd in 2017). The two main factors for the lower production were the natural decline of the Elyzavetivske field and Novomykolaivske complex and the lower than usual enhancement activity in the first half of 2017 while the Rudenkivske field fracturing programme was being planned and carried out. For more detail please refer to the Regional operations update.

The increase in average oil sales price from $45.94/bbl in 2016 to $64.26/bbl in 2017 reflects both the increase in Brent from an average of $43.55/bbl during the 2016 to $54.55/bbl during the 2017 and also our sales price's considerable average premium to Brent of $9.8/bbl during 2017. Domestic demand has remained robust through 2017 and greater than domestic supply.

The average LPG sales price increased to $467.49/tonne in 2017 (2016: $374.81/tonne) due to tight controls over customs clearance limiting LPG product imports. Higher sales price compensated the fall in sales volumes from 10,075 tonnes in 2016 to 9,855 tonnes in 2017.

Russia revenues

The $1.4m decrease in total revenues from $19.0m in 2016 to $17.6m in 2017 is due to lower gas production. Total annual gas production decreased by 17.8% from 374,176 Mcm in 2016 to 307,841 Mcm in 2017 (from 6,035 boepd in 2016 to 4,965 boepd in 2017), mainly because of delays in the workover of Well 25. This decrease was offset by a 13.4% increase of the average sales price in dollar terms from $1.49/Mcf in 2016 to $1.69/Mcf in 2017 due to both the appreciation of the rouble and a 3.9% rise in the average rouble gas sales price from 2016 to 2017.

Hungary revenues

Hungarian gas and condensate sales, which recommenced in February 2017 and made up 2% of the Group's volumes sold in 2017, are expected to continue throughout 2018.

Cost of sales

Exceptional items

Exceptional charges of $19.7m in 2017 are made up of the following:

· $9.4m costs incurred at Rudenkivske where there was an unsuccessful fracturing programme in the first half of 2017. Two of the wells included in the programme were abandoned due to lack of gas production and the other two wells are not expected to produce enough to pay back their costs.

· $5.9m movement in impairment provisions. As a result of the year end impairment review, impairment charges of $7.9m and $3.6m were made in respect of assets in Slovakia and Hungary and a reversal of $5.6m was made in respect of the Elyzavetivske field (see Note 5 to the financial statements).

· $4.4m of movement in provision for production-based taxes in respect of 2010 and 2015 see Note 18 to the financial statements).

Cost of sales before exceptional items

2017 cost of sales before exceptional items totalled $53.6m (2016: $56m). This includes:

· $19.9m of operating costs, which is similar to the $19.7m recorded in 2016.

· $16.9m of production taxes, which is $0.8m lower than in 2016, mainly because of lower production volumes and the introduction of a lower royalty rate for oil in Ukraine. Only $1.8m of the total production taxes relate to Russia where the mineral extraction tax rate for wells deeper than 5,000m has remained at 312 Roubles/Mcm.

· $16.8m of depreciation, depletion and amortisation ('DD&A') charge for 2017, which is $1.9m lower than in 2016 because of the lower production volumes in Ukraine and Russia in 2017.

Analysis showing production costs, production taxes and netbacks for both our Ukrainian and Russian operations is shown in the Markets section.

Administrative expenses

Exceptional items

Exceptional charges of $1.5m in 2017 consist of severance and legal costs relating to the departure of the previous CEO and CFO.

Other administrative expenses before exceptional items

Other administrative expenses before exceptional items have decreased by $6.3m to $15.9m in 2017 (2016: $22.2m) as a result of the following:

· A $4.7m decrease in legal and professional fees consisting of a $4.2m reduction in legal fees due to the completion of arbitration case and the cutting of a further $0.5m of advisory costs.

· A $2.1m decrease in staff and other administrative costs across the Group mainly as a result of cost savings initiatives.

The effect of these decreases was offset by a $0.5m increase in marketing and lobbying costs to raise awareness of the previous strategy. Contracts with agencies engaged in this were cancelled in the second half of 2017.

Net finance charges

Finance costs, mainly comprising convertible bond interest, decreased from $4.6m in 2016 to $3.2m in 2017 due to the reduction in principal outstanding that occurred in 2016. $10.0m of the bonds were redeemed in February 2016 and subsequently bonds with face values of $2.2m, $1.4m and $6.4m were repurchased and subsequently cancelled in June, September and October 2016, respectively. In January 2017 the remaining $16.0m bonds outstanding were restructured as noted below.

Finance income of $0.3m comprises income from bank deposits of $0.3m (2016: $0.8m). 2016 income also included a $1.0m gain on the repurchase of convertible bonds noted above.

Taxation

The total tax charge for the year was $1.6m (2016: $1.0m) comprising a current tax charge of $3.0m (2016: $1.3m) and a deferred tax credit of $1.3m (2016: credit $2.4m) (see Note 27 to the financial statements). The higher 2017 $3.0m current tax charge relates to Ukraine due to the higher annual profit recorded.

Cash flows

Unrestricted cash held at the end of 2017 was $6.9m, or less than a half of the amount held at the start of the year. The main reason for this is the significant cash spent on capex during the year.

Cash generated from operations was $15.7m (2016: $17.0m). Interest paid during the period comprised $1.8m bond interest (2016: $2.4m). Income tax paid in the period increased to $2.9m (2016: $0.01m), due to higher profits earned by our Ukrainian subsidiary.

Of the $16.7m total cash spent on investment projects during the year (2016: $7.5m), $9.4m relates to costs incurred at Rudenkivske already referred to as an exceptional item. Of the remaining $7.1m cash spent on capex in 2017, $1.1m relates to other enhancement projects in Ukraine, $1.5m relates to Hungary and $4.2m relates to Russia where there were workovers of Wells 25 and 5. At the year-end creditor balances totalling $1.6m of further capex incurred in respect of the Well 5 workover remained unpaid.

Net cash outflow from financing activities in the period mainly relates to the $1.9m of accretion payment to the bondholders in February 2017 (2016: $10.9m redemption of the Bond in February 2016 and $9.0m used to repurchase 50 convertible bonds).

No dividends were paid to shareholders in the period (2016: nil).

The resultant decrease in cash and cash equivalents in the period before adjusting for foreign exchange effects was $7.1m (2016: $11.3m).

Liquidity

At start of 2017 the Company completed the restructuring of the remaining $16 million of Bonds. The financing of the Bonds is within the operating cash flow capabilities of the Company. The payment of $6.9 million due in February 2018 was made on time. The remaining payments are as follows: $0.8m in August 2018, $6.0m in February 2019, $0.4m in August 2019 and $5.8m in February 2020.

In December 2017 our operating subsidiary in Ukraine secured a 12 month revolving credit line from Tascombank for UAH150 million, equivalent to $5.3m as at 31 December 2017, which remains undrawn.

Going concern

While there are sensitivities related to issues such as sales prices, and technical and geological risks, and material uncertainties regarding production-related tax disputes with the Ukrainian Government, the Group has the resources and ability to address these. Both the Ukrainian and the Russian assets have positive cash flow and the Group's liquidity is forecast to improve through 2018 and 2019. As noted above, at current market prices and planned production levels, operating cash flow is sufficient to cover the bond repayment schedule. As a result the consolidated financial statements have been prepared on a going concern basis (see note 2 to the financial statements).

Ben Fraser

Chief Financial Officer

Regional operations update

Group production

In 2017 group average production was 8,658 boepd (2016: 10,083 boepd), comprising of 47.2 MMcfd of gas (2016: 54.7 MMcfd) and 784 bpd of oil and condensate (2016: 967 bpd), an overall reduction in production of 14%. The decline in gas production was mainly attributed to Well 25 being offline in Russia for 4 months due to a fire on the workover rig. The remaining drop in gas production was due to ongoing decline in the Elyzavetivske field in Ukraine. The reduction in group oil production was due to the decline of IG132 in the Ignatovskoye field in Ukraine.

Ukraine

Novomykolaivske licences

Production

Average production from the Novomykolaivske group of fields in 2017 was 2,336 boepd (2016: 2,553 boepd) comprising 9.8 MMcfd of gas (2016: 10.0 MMcfd) and 701 bpd of oil and condensate (2016: 879 bpd). Despite the disappointing results of the Phase 1 fracturing campaign, gas production only reduced by 2% however oil reduced by 20%. The gas production during 2017 increased significantly in the Rudenkivske field due to the successful workovers of NN16 and NN47 at the end of 2016 which offset natural production declines in the rest of the fields. The decline in oil is mainly attributed to the decline of production of IG132.

Development and drilling

No drilling of new wells took place in 2017 as efforts were focused on delivering the Phase 1 frac project in the Northern part of the Rudenkivske field during the first half of the year. Enhancements continued through the year and towards the end of the year the first drilling related activity since 2014 resulted in the successful completion of the IG101 Sidetrack using the SMS rig.

Ignativske Field

Average production from the Ignativske field in 2017 was 949 beopd (2016: 1452 boepd) comprising 3.6 MMscf/d (2016: 4.5 MMscf/d) and 358 bopd (2016: 513 bopd). Natural decline contributed the most to the year on year decline with the reduction in IG132 having the largest effect on oil output. The following enhancement activities were carried out on wells in the Ignativske license during 2017:

· An electrical submersible pump (ESP) was installed in IG128 in May which increased the oil rate from 38 stb/d to 132 stb/d. At the end of the year the water cut had increased with the well producing 61 bopd during the last test of the year.

· De-waxing units were installed in IG132 and IG137 during 2017 to reduce downtime by removing the need for regular wax cutting jobs using slickline.

· IG101ST was completed at the end of December and was the first sidetrack of an existing well which has been carried out by PPC since 2006 and was the first drilling related operation carried out by PPC since IG140 at the end of 2014. The well was drilled to test the Tournaisian clastics in a neighbouring fault block and initial rates were 8.6 MMscf/d and 365 b/d of condensate.

Ignativske South waterflood project

Water injection continued into IG126 during 2017. In late January an ESP was installed in IG110 to increase the supply of water from 753 bwpd to 3447 bwpd. An acid job in IG126 further increased the rate of water injection to 7087 bwpd before problems with sand production meant that the ESP in IG110 had to be stopped in late February. Water injection was re-started in July once the pump had been repaired and a screen had been installed. The water injection rate averaged 3132 bwpd until after a flow meter check the ESP could not be re-started in August. A total of 245 Mstb of water was injected into IG126 during 2017.

Since the start of the pilot water injection in 2012 a total of 1.74 MMstb of water has been injected into IG126 and over the same period 229 Mstb of oil, 0.74 Bcf of gas and 0.02 Mstb of water has been produced from two wells in this part of the field. It is estimated that the incremental production as a result of the water flood project is 120 Mstb of oil and 0.4 Bcf of gas to date. The reservoir pressure has increased by 352 psi since the start of the waterflood project with 140 psi of this pressure increase occurring in the last year indicating that fill up has been progressing.

Due to problems with the water supply for the water injector and no incremental production achieved during 2017 this project is to be re-evaluated during 2018 leading to a decision whether to resume water injection.

Movchanivske Fields

Average production from the Movchanivske field in 2017 was 685 boepd (2016: 771 boepd) comprising 3.0 MMscf/d (2016: 3.4 MMscf/d) and 181 bopd (2016: 198 bopd). Natural decline was only partially offset by the enhancements listed below. The following enhancement activities were carried out on wells in the Movchanivske license during 2017:

· M202 was placed on gas lift in August which resulted in an increase in the production rate by 0.2 MMscf/d and 20 bopd and has enabled consistent production from this well which was previously only able to produce periodically.

· M166X was re-started in September after having been shut-in since November 2016 due to only water being produced. This well produced 3.7 Mstb of oil and 22 MMscf of gas in the second half of 2017.

· M153 was successfully worked over in September to remove the packer and deepen the gas lift injection point. This resulted in an increase in production from 26 boepd to 130 boepd.

· M161-V16 was worked over in November to re-shoot the current interval with 4 ½" TCP guns. This was an attempt at increasing the oil rate by reducing the near wellbore skin damage. The average oil rate in December from this well was 33 bopd up from 25 bopd prior to the workover.

· De-waxing units were installed in M153 and M171 during 2017.

Novomykolaivske Field

Average production from the Novomykolaivske field in 2017 was 356 beopd (2016: 392 boepd) comprising 1.4 MMscf/d (2016: 1.4 MMscf/d) and 129 bopd (2016: 159 bopd). The GOR in two of the key producers has increased through the year contributing to the decline in oil rate and stabilisation of the gas production. The following enhancement activities were carried out on wells in the Novomykolaivske field during 2017:

· Additional W/L perforations were added in NN80 in September however no additional gas production was achieved and as such there were no other interventions on this field in 2017.

Rudenkivske Field

Average production from the Rudenkivske field in 2017 was 346 beopd (2016: 140 boepd) comprising 1.9 MMscf/d (2016: 0.8 MMscf/d) and 33 bopd (2016: 12 bopd). A significant increase in the production from Rudenkivske occurred in 2017 due to the successful workovers of the two leased wells NN16 and NN47 late in 2016. The following enhancement activities were carried out on wells in the Rudenkivske license during 2017:

· NN16 was placed on gas lift in January 2017 and is still producing intermittently.

· 6R had 17m of perforations added in April producing a total of 58.5 MMscf of gas at the beginning of May.

· R25 was abandoned in September due to no significant quantities of gas production being achieved, from this well, following the fracturing campaign.

· NN22 was worked over in June and produced an initial rate of 8 MMscf/d before production became hampered by water production. The well produced a total of 34 MMscf and 681 stb of condensate.

· R6 was placed on gas lift in October in an effort to accelerate clean-up following the fracturing of this well during the first half of the year. So far to date only minor quantities of gas have been produced from this well since fracturing.

· R10 was abandoned in November due to no significant quantities of gas production being achieved, from this well, following the fracturing campaign.

· R19 is currently on intermittent production and like R6 has only produced minor quantities of gas since fracturing.

Rudenkivske Frac Project

During the first half of the year the focus was on delivering Phase 1 of the fracturing campaign in the Northern part of the Rudenkivske field. The objective was to de-risk contingent resources in this part of the field. Four wells, 19R, 25R, 10R and 6R, had a total of 12 stages pumped (including 2 re-fracs) using Schlumberger for the pumping operation. All chemicals were sourced by PPC. Operationally the project went smoothly with all stages pumped in 29 days and all 5 stages pumped on 19R were pumped in 6 days. This was a significant improvement on the last fracturing operation conducted by the company when 10 stages took a total of 62 days to pump. A post job review was carried out in the second half of 2017 which determined that the key failing was attributed to petrophysically derived properties not accurately representing the mobile water saturation in tight rock. This led to unexpected formation water production from the target zones. Based on the results of the Phase 1 fracturing campaign the contingent resources in both the Tournaisian and the northern part of the Devonian reservoirs have been removed from the total amount of contingent resources in the Rudenkivske license.

Production facilities

Operations at the main processing facility, the LPG plant and the oil loading facility continued smoothly throughout the year. A routine annual plant shutdown of 2 days for maintenance was successfully completed in September. Manifold pressure was reduced to 50 psig in October from 90 psig having a positive effect on 9 of the gas producing wells and also increasing oil production.

Elyzavetivske Production Licence

Production

Average production from the Elyzavetivske field in 2017 was 1,172 boepd (2016: 1,448 boepd) comprising 6.9 MMcfd of gas (2016: 8.6 MMcfd) and 18 bpd of condensate (2016: 23 bpd), an overall 19% decrease in production on the average for 2016. The decrease is as a result of the pressure decline in the field.

Development and drilling

There was no drilling activity on the Elyzavetivske field during the year. The following enhancements were carried out during 2017:

· EM53 was brought online in April with a rate of 1.3 MMscf/d on a 48/64ths" choke however the rate declined through the year due to liquid loading.

· EM205 was brought on line in June 2017 but was only able to produce 0.1 MMscf/d due to liquid loading.

Production facilities

The Elyzavetivske production facility continues to operate efficiently. The manifold pressure was dropped from 100 to 75 psig in November which helped stabilise the gas rate decline in the final quarter of 2017.

Russia

Koshekhablskoye licence

Production

Average production from the Koshekhablskoye field in 2017 was 5,019 boepd (2016: 6082

boepd) comprising 29.8 MMcfd of gas (2016: 36.1 MMcfd) and 55 bpd (2016: 65 bpd) of condensate, a 17% decrease on the average for 2016. This decrease in production is due to the delays in working over Well 25 caused by a fire. In total Well 25 was offline for 4 months in 2017.

Development and drilling

 Well 25 was shut-in during the first week of March for the rig up with the workover commencing in the first week of April. The workover was on schedule when a fire broke out around the drillers control cabin on the 12th April. At which point operations were suspended until 18th June once repairs had been completed. CRA (chrome) tubing was then run in hole and the well re-started production on the 6th July following an acid job.

Well 5 workover commenced on the 21st August. The ratch-latch was unable to be released due to difficulties in transmitting sufficient torque downhole. The tubing was then cut and retrieved in 3 separate parts taking a month more than planned. The casing repair and running of the completion was successful. Communication with the reservoir was not possible despite repeated efforts with coiled tubing during December.

Production from crestal well-20 has declined from 13.9 MMcfd to 11.7 MMcfd through the year without any additional acid stimulation. Production from this well has continued to exceed expectations despite the presence of a fish.

Since the workover to install chrome tubing in Well 25, production from this well has been more stable than prior to the workover. Production after the workover peaked at 10.5 MMscf/d on the 5th October prior to declining to 9.5 MMscf/d at the year end.

Well-27 has been producing gas at rates between 8.8-12.0 MMcfd on a monthly average basis, having required five acid treatments through the year (8 in 2016). The deep east-flank well-15 continues to produce approximately 0.6 MMcfd on a monthly average basis.

Production facilities

There were no changes to the facilities in 2017.

Hungary

Following applications made in 2015, JKX operates six Mining Plots (production licences) in Hungary which cover a total of 200 sq km. Theses licences are 100% owned by Riverside Energy Kft, the Company's wholly-owned Hungarian subsidiary, with the exception of the Emod V licence where Riverside has a 100% Paying Interest and a 97% Working Interest through the end of 2018.

The licence terms enable JKX to carry out appraisal and development activity over a 30 year period.

Hajdunanas field

Production from the Hajdunanas and Gorbehaza Fields in north east Hungary, which form the Hajdunanas IV Mining Plot, was suspended by the previous operator in 2013.

In December 2016 a sidetrack to the Hn-2 well (Hn-2ST) was completed. It had been planned to access remaining "attic" Pannonian reservoir gas and to test the oil potential of the underlying Miocene volcanoclastic sequence, previously productive in the Hn-1 well. An additional Pannonian gas bearing interval was identified, brought onto production in February 2017. This was the first drilling operation completed since JKX assumed operatorship in November 2014.

The Hn-2ST well tested 1.5 MMcfd from the Pannonian Pegasus sands and 2.8 MMcfd from a lower Pannonian sand interval. The latter was a newly discovered productive horizon in the field. The underlying Miocene interval was found to be dry.

Gas sales commenced in February 2017 at an initial rate of 1.8 MMcfd, after a production and sales break of more than three years. Production continued through September 2017 when the Hn-2ST well was shutin, as a result of high water and sand production. In October the Hn-1 well was worked over and the Hn-1 Lower Pannonian reservoir was brought back on stream at a sales rate of 0.7 MMcfd.

As a result of strategic refocusing of JKX on its core areas, the Group is now pursuing a full divestment of its remaining Hungarian licence interests.

Slovakia

JKX holds a 25% equity interest in the Svidnik, Medzilaborce, Snina and Pakostov exploration licences in the Carpathian fold belt in north east Slovakia. A programme of magneto-telluric geophysical surveys combined with seismic re-interpretation has led to the identification of a number of shallow but sizeable prospects, both oil and gas targets, across the licences.

The combination of revised permitting procedures and local activist environmental opposition has delayed well location permitting, access and construction throughout 2017. Numerous initiatives have been followed in an effort to resolve the wellsite access and protestor issues. As a result of strategic refocusing of JKX on its core areas, the Group is now pursuing a withdrawal from Slovakia.

JKX Reserves & Resources

Reserves update

Following an internal re-evaluation, we have reduced our 2P reserves from 109.4 to 95.1 million boe or 13% year-on-year. The most significant reduction is due to the negative results from the pilot fracturing program carried out at the Rudenkivske field in June 2017 in Ukraine.

An extensive review following the fracturing of 12 intervals in 4 Soviet era wells has led the Company to temper its assumptions about recovery rates per well throughout the field. A new field development plan has been generated based on this analysis (see below). As a result, we have reduced our Rudenkivske 2P reserves all of which were attributed to the Devonian clastic horizons located in the southern section of the field. Although some reserves were added to reflect historical production (and remaining potential) in the Visean horizons to the north of the field, total Rudenkivske 2P reserves have been reduced by 7.1 million boe or by 32%.

At the same time, 2.2 million boe of 2P reserves have been added in the Ignativske field to reflect the potential of Devonian clastics that extend from southern Rudenkivske into the Ignativske section of the field and which were previously not included in field development plans.

Once 2017 production of 1.2 million boe has been taken into account, total reduction of our reserves in Ukraine amounts to 5.8 million boe.

In addition, we have reduced our 2P reserves in Russia attributed to the planned Callovian well by 6.8 million boe. Given our current estimates of US$25-30 million required to drill a well to the target of 5800 meters on the one hand, and low gas prices in Russia on the other, the well is at present considered not economic. This reduction in reserves will have no impact on current production rates. An additional 1.8 million boe reduction in reserves is attributed to production in 2017.

*0.26 Bcf produced in Hungary

Field-by-Field 2P reserves at 31 December 2017

JKX contingent resources

There is no change to the contingent resources this year in any of the other fields except Rudenkivske. Rudenkivske requires a reduction in contingent resources to reflect the failure of the Frac campaign in 2017. The frac campaign was specifically targeting contingent resources in the Tournaisian and Devonian reservoirs in the north of Rudenkivske. The frac campaign in 2017 showed that these reservoirs are unable to produce sufficient quantities of gas to justify further development of this area.

Ukraine field development plans update

Since the arrival of the new senior management team and new Board, we have significantly revised our field development plans in Ukraine.

Our plan for 2018 includes significant activity to boost production in our core fields and engage in low risk appraisal. This includes 12 workovers, 4 sidetracks and one new well. We plan to take advantage of access we have gained to 5 state-owned wells located on our licenses to target low-cost production enhancement opportunities. Our main development targets are production enhancement through evaluation of clastic reservoirs in the western part of the Ignativske field, infill drilling at the Elyzavetivske field, appraisal of the West Mashivske area of Elyzavetivske, testing the deep Devonian horizons at our Movchanivske field and a sidetrack to target the same fault block as IG132.

Our approach to the development of the Rudenkivske field has changed significantly. The new field development plan now targets the Devonian horizons in the southern section of the field. This is where the Company was able to achieve the best results to date (wells R12 and R103) and where target depths are relatively shallow. Meanwhile, the number of planned wells targeting Visean sands in the northern part of the field - the main target of the previous field development plans - has been significantly reduced. Overall, compared to the previous Rudenkivske field development plan, the number of target wells and fracture stages have been significantly reduced. To achieve lower costs per reservoir penetration, the use of multilateral wells is envisaged. We expect to be able to finance the program from cashflow when drilling begins in 2019.

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 (unaudited)

for the year ended 31 December

Consolidated statement of comprehensive income (unaudited)

for the year ended 31 December

Consolidated statement of financial position (unaudited)

as at 31 December

Consolidated statement of cash flows (unaudited)

for the year ended 31 December

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

The consolidated financial information for the Group set out in this preliminary announcement has been derived from the unaudited consolidated financial statements of the Group for the year ended 31 December 2017 (the 'financial statements').

The 2016 financial statements have been filed at Companies House. The auditors' report on the 2016 financial statements was unqualified and did not contain statements under s498(2) or (3) Companies Act 2006. The auditors' report on the 2016 financial statements did contain an emphasis of matter, which drew attention to the existence of a material uncertainty which may cast significant doubt about the Company's ability to continue as a going concern.

The auditors' report on the 2017 financial statements has not yet been issued. The auditors have indicated that, consistent with 2016, their report will contain a "material uncertainty related to going concern" section drawing attention to the existence of a material uncertainty that may cast significant doubt about the Company's ability to continue as a going concern, for further details see Note 2.

As described in the Chairman's statement on page 3, an investigation into the procurement of legal services in Ukraine, and subsequent payments made to legal advisers, has been commissioned by the Audit Committee and is ongoing. The auditors have indicated their report may be modified in respect of this matter, depending on the outcome of this investigation and finalisation of their audit procedures.

2. Basis of preparation

The Group's financial statements have been prepared in accordance with International Financial Reporting Standards ('IFRSs') as adopted by the European Union, IFRS Interpretations Committee ('IFRS IC') interpretations and the Companies Act 2006 applicable for Companies reporting under IFRS and therefore the consolidated financial statements comply with Article 4 of the EU IAS Regulations. The Group's financial statements have been prepared under the historical cost convention, as modified for derivative instruments held at fair value through profit or loss. The principal accounting policies adopted by the Group are set out below.

Going concern

The majority of the Group's revenues, profits and cash flow from operations are currently derived from its oil and gas production in Ukraine, rather than Russia.

The Company's Ukrainian subsidiary, Poltava Petroleum Company ('PPC') has made provision for potential liabilities arising from separate court proceedings regarding the amount of production taxes ('Rental Fees') paid in Ukraine for certain periods since 2010, which total approximately $37.1 million (including interest and penalties, see Note 27 to the consolidated financial statements). PPC continues to contest these claims through the Ukrainian legal system.

In February 2017, the international arbitration tribunal ruled that Ukraine was found not to have violated its treaty obligations in respect of the levying of Rental Fees but awarded the Company damages of $11.8 million plus interest, and costs of $0.3 million in relation to subsidiary claims. No adjustment has been made in these financial statements to recognise any possible future benefit to the Company, with the tribunal ruling subject to enforcement proceedings in Ukrainian courts.

Taking into account the damages awarded to the Company and the Ukrainian court proceedings against PPC in respect of production taxes, there is a net shortfall of $25 million owed by the Group to Ukraine. Should PPC lose the claims against it in respect of production taxes due for 2010 and 2015, and the Ukrainian Authorities demand immediate settlement, the Group does not currently have sufficient cash resources to settle the claims and this would affect its ability to meet its obligations to creditors and bondholders.

Accordingly, the Group's going concern assessment is sensitive to the outcome of the production-related tax disputes with the Ukrainian Government.

The Directors have concluded that it is necessary to draw attention to the potential impact of the Group becoming liable for additional Rental Fees in Ukraine as a result of unfavourable outcomes in one or both of the ongoing court proceedings. It is unclear whether either or both of these claims against PPC will be realised and settlement enforced but they are material uncertainties which may cast significant doubt about the Group's ability to continue as a going concern.

However, 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 and/or negotiation with Ukraine for the settlement of any successful production tax claim, mean that it is appropriate to continue to adopt the going concern basis of accounting in preparing these financial statements. These financial statements do not include the adjustments that would result if the Group was unable to continue as a going concern.

· Adoption of new and revised standards

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 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 2016, except for the following:

§ IAS 7 'Statement of cash flows' (Amendments) 01-Jan-17

§ IAS 12 'Income taxes' (Amendments) 01-Jan-17

The application of the amendments has had no impact on the disclosures of the amounts recognized in the Group's consolidated financial statements.

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 2017 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 for annual periodsbeginning on or after

§ IFRS15 'Revenue from contracts with customers' 01-Jan-18

The IASB has issued a new standard for the recognition of revenue. This will replace 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. The standard permits either a full retrospective or a modified retrospective approach for the adoption.

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 no impact is expected from the adoption of the new standard on 1 January 2018.

§ IFRS 9 'Financial instruments' 01-Jan-18

The Group has reviewed its financial assets and is expecting no impact from the adoption of the new standard on 1 January 2018. The majority of the Group's financial assets that are currently classified at amortised cost will satisfy the conditions for classification at amortised cost and hence there will be no change to the classification for these assets. However, investments in equity instruments do not meet the criteria to be classified at amortised cost and will have to be reclassified to financial assets at fair value through profit or loss as of 1 January 2018. The Group is currently estimating the impact of reclassification on the value of its unlisted investment as there is a lack of liquid market and the fair value is judgemental.

We have also focused on the potential impact of transition to IFRS 9 on the carrying value of trade receivables. The new impairment model requires the recognition of impairment provisions based on expected credit losses (ECL) rather than only incurred credit losses as is the case under IAS 39. It applies to financial assets classified at amortised cost, debt instruments measured at FVOCI, contract assets under IFRS 15 Revenue from Contracts with Customers, lease receivables, loan commitments and certain financial guarantee contracts. The Group does not expect the new guidance in IFRS 9 to result in material changes to impairment provisioning based on the assessments undertaken to date.

Financial liabilities held by the Group comprise of 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 is expecting 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 trivial and hence there will be no impact on adoption of IFRS 9 on 1 January 2018.

§ IFRS 2 'Share-based payment' (Amendments) 01-Jan-18

§ IFRS 16 'Leases' 01-Jan-19

As a Lessee, the Group is required to recognise all lease contracts on the balance sheet subject to certain, limited exceptions. The Group will not be required to recognise lease contracts with a term of less than 12 months on the balance sheet. The Group is currently assessing the impact of IFRS 16.

3. Significant accounting policies

· Basis of consolidation

The consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. All intragroup balances, transactions, income and expenses and profits or losses, including unrealised profits arising from intragroup transactions, have been eliminated on consolidation.

Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases. The consolidated financial statements include all the assets, liabilities, revenues, expenses and cash flows of the Companies and their subsidiaries after eliminating intragroup transactions as noted above. Uniform accounting policies are applied across the Group.

· Interests in joint arrangements

A joint arrangement is one in which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.

Where the Group's activities are conducted through joint operations, whereby the parties that have joint control of the arrangement have the rights to the assets, and obligations for the liabilities, relating to the arrangement, the Group reports its interests in joint operations using proportionate consolidation - the Group's share of the assets, liabilities, income and expenses of the joint operation are combined with the equivalent items in the consolidated financial statements on a line-by-line basis.

A joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties that have joint control of the arrangement have the rights to the arrangement's net assets. The results, assets and liabilities of a joint venture are incorporated in the consolidated financial statements using the equity method of accounting.

Where the Group transacts with its joint operations, unrealised profits and losses are eliminated to the extent of the Group's interest in the joint operation.

· Foreign currencies

All amounts in these financial statements are presented in thousands of US dollars, unless otherwise stated. The presentation currency of the Group is the US Dollar based on the fact that the Group's primary transactions originate in, or are dictated by, the US Dollar, these being, amongst others, oil sales and procurement of rigs and drilling services.

Each entity in the Group is measured using the currency of the primary economic environment in which the entity operates ('the functional currency'). Foreign currency transactions are translated into functional currency using the exchange rates prevailing at the dates of the transactions or valuation where items are re-measured. Foreign exchange gains and losses resulting from the settlement of such transactions and from translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement.

On consolidation of subsidiaries and joint operations with a non US Dollar presentation currency, their statements of financial position are translated into US Dollar at the closing rate and income and expenses at the average monthly rate. All resulting exchange differences arising in the period are recognised in other comprehensive income, and cumulatively in the Group's translation reserve. Such translation differences are reclassified to profit or loss in the period in which any such foreign operation is disposed of.

Subsidiaries within the Group hold monetary intercompany balances for which settlement is neither planned nor likely to occur in the foreseeable future and thus this is considered to be part of the Group's net investment in the relevant subsidiary. An exchange difference arises on translation in the company income statement which on consolidation is recognised in equity, only being recognised in the income statement on the disposal of the net investment.

The major exchange rates used for the revaluation of the closing statement of financial position at 31 December 2017 were $1:£0.74 (2016: $1:£ 0.81), $1: 28.07 Hryvnia (2016: $1: 27.19 Hryvnia), $1: 57.60 Roubles (2016: $1: 60.66 Roubles), $1: 258.63 Hungarian Forint (2016: $1: 293.40 Hungarian Forint).

Goodwill and fair value adjustments arising on acquisition are treated as assets/liabilities of the foreign entity and translated at the closing rate.

· Property, plant and equipment and other intangible assets

Property plant and equipment comprises the Group's tangible oil and gas assets together with computer equipment, motor vehicles and other equipment and are carried at cost, less any accumulated depreciation and accumulated impairment losses. Cost includes purchase price and construction costs for qualifying assets, together with borrowing costs where applicable, in accordance with the Group's accounting policy. Depreciation of these assets commences when the assets are ready for their intended use.

Oil and gas assets

Exploration, evaluation and development expenditure is accounted for under the 'successful efforts' method. The successful efforts method means that only costs which relate directly to the discovery and development of specific oil and gas reserves are capitalised.

Exploration and evaluation costs are valued at costs less accumulated impairment losses and capitalised within intangible assets. Development expenditure on producing assets is accounted for in accordance with IAS 16, 'Property, plant and equipment'. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the income statement.

All lease and licence acquisition costs, geological and geophysical costs and other direct costs of exploration, evaluation and development are capitalised as intangible assets or property plant and equipment according to their nature. Intangible assets are not amortised and comprise costs relating to the exploration and evaluation of properties which the Directors consider to be unevaluated until reserves are appraised as commercial, at which time they are transferred to property plant and equipment following an impairment review and are depreciated accordingly. 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.

Costs related to hydrocarbon production activities are depreciated on a field by field unit of production method based on commercial proved plus probable reserves of the production licence, except in the case of assets whose useful life differs from the lifetime of the field, which are depreciated on a straight-line basis over their anticipated useful life of up to 10 years.

The calculation of the 'unit of production' depreciation takes account of estimated future development costs and is based on current period end unescalated price levels. The 'unit of production' rate is set at the beginning of each accounting period. Changes in reserves and cost estimates are recognised prospectively.

Other assets

Depreciation is charged so as to write off the cost, less estimated residual value, over their estimated useful lives, using the straight-line method, for the following classes of assets:

The estimated useful lives of property plant and equipment and their residual values are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively. Assets under construction are not subject to depreciation until the date on which the Group makes them available for use.

The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in the income statement for the relevant period.

· Business combinations

The acquisition of subsidiaries is accounted for using the purchase method. The cost of the acquisition is measured at the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed and equity instruments issued by the Group in exchange for control of the acquiree. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the criteria for recognition under IFRS 3 (revised) are recognised at their fair value at the acquisition date. In a business combination achieved in stages, the previously held equity interest in the acquiree is re-measured at its acquisition date fair value and the resulting gain or loss, if any, is recognised in the income statement. Acquisition costs are expensed.

Goodwill is recognised as an asset and is initially measured at cost being the excess of the cost of the business combination over the Group's share in the net fair value of the acquiree's identifiable assets, liabilities and contingent liabilities. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill impairment reviews are undertaken annually or more frequently if events or changes in circumstances indicate a potential impairment. Impairment losses on goodwill are not reversed.

On disposal of a subsidiary or joint arrangement, the attributable amount of unamortised goodwill, which has not been subject to impairment, is included in the determination of the profit or loss on disposal.

· Impairment of property, plant and equipment and intangible assets

Whenever events or changes in circumstances indicate that the carrying amount may not be recoverable, the Group reviews the carrying amounts of its property, plant and equipment and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. Individual assets are grouped together as a cash-generating unit for impairment assessment purposes at the lowest level at which their identifiable cash flows, that are largely independent of the cash flows of the other Groups assets, can be determined.

If any such indication of impairment exists the Group makes an estimate of its recoverable amount.

The recoverable amount is the higher of fair value less costs of disposal and value in use. Where the carrying amount of an individual asset or a cash-generating unit exceeds its recoverable amount, the asset/cash-generating unit is considered impaired and is written down to its recoverable amount. Fair value less costs of disposal is determined by discounting the post-tax cash flows expected to be generated by the cash-generating unit, net of associated selling costs, and takes into account assumptions market participants would use in estimating fair value. In assessing the value in use, the estimated future cash flows are adjusted for the risks specific to the asset/cash-generating unit and are discounted to their present value that reflects the current market indicators.

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 as income immediately.

· JKX Employee Benefit Trust

The JKX Employee Benefit Trust was established in 2014 to hold ordinary shares purchased to satisfy various new share scheme awards made to the employees of the Company which will be transferred to the members of the scheme on their respective vesting dates subject to satisfying the performance conditions of each scheme.

The trust has been consolidated in the Group financial statements in accordance with IFRS 10. The cost of shares temporarily held by the trusts are reflected as treasury shares and deducted from equity.

· Financial instruments

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

Convertible bonds due 2020 - embedded derivative

The net proceeds received from the issue of convertible bonds at the date of issue have been split between two elements: the host debt instrument classified as a financial liability in Borrowings, and the embedded derivative.

The fair value of the embedded derivative has been calculated first and the residual value is assigned to the host debt liability. The difference between the proceeds of issue of the convertible bonds and the fair value assigned to the embedded derivative, representing the value of the host debt instrument, is included as Borrowings and is not remeasured. The host debt component is then carried at amortised cost and the fair value of the embedded derivative is determined at inception and at each reporting date with the fair value changes being recognised in profit or loss.

Issue costs are apportioned between the host debt element (included in Borrowings) and the derivative component of the convertible bond based on their relative carrying amounts at the date of issue.

The interest expense on the component included in Borrowings is calculated by applying the effective interest method, with interest recognised on an effective yield basis.

Upon redemption of convertible bonds by the Company in the market, the difference between the repurchase cost and the total of the carrying amount of the liability plus the repurchased embedded option to convert is recorded in the income statement. 2016 gain on the repurchase of convertible bonds (see Note 21) had been recognised in the income statement under Finance income in the year ended 31 December 2016.

Borrowings

Borrowings are initially measured at fair value, net of transaction costs and are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis. 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 through the expected life of the financial liability, or, where appropriate, a shorter period.

Trade and other receivables

Trade and other receivables are recognised initially at fair value and are subsequently measured at amortised cost, reduced by any provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due. Indicators of impairment would include financial difficulties of the debtor, likelihood of the debtor's insolvency, default in payment or a significant deterioration in credit worthiness. Any impairment is recognised in the income statement within 'Administrative expenses'.

Cash and cash equivalents

Cash and cash equivalents comprise cash in hand and current balances with banks and similar institutions, which are readily convertible to known amounts of cash. Cash equivalents are short-term with an original maturity of less than 3 months.

Restricted cash

Restricted cash is disclosed separately on the face of the statement of financial position and denoted as restricted when it is not under the exclusive control of the Group.

Trade and other payables

Trade and other payables are initially measured at fair value, and are subsequently measured at amortised cost, using the effective interest rate method if the time value of money is significant.

Financial liabilities and equity

Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities. Equity instruments issued by the Company are recorded at the proceeds received net of direct issue costs.

· Inventories

Inventory is comprised of produced oil and gas or certain materials and equipment that are acquired for future use. The oil and gas is valued at the lower of average production cost and net realisable value; the materials and equipment inventory is valued at purchase cost. Cost comprises direct materials and, where applicable, direct labour costs plus attributable overheads based on a normal level of activity and other costs associated in bringing the inventories to their present location and condition. Cost is calculated using the weighted average method. Net realisable value represents the estimated selling price less all estimated costs of completion and costs to be incurred in marketing, selling and distribution and any provisions for obsolescence.

· Taxation

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

The current tax payable is based on taxable profit for the year. Taxable profit differs from net profit as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Tax is charged or credited in the income statement, except when it relates to items charged or credited directly to equity or in other comprehensive income, in which case the tax is also dealt with in equity or other comprehensive income respectively.

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax base used in the computation of taxable profit. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax profit nor the accounting profit.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, and interests in joint ventures, 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.

The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the asset to be recovered. Any such reduction shall be reversed to the extent that it becomes probable that sufficient taxable profit will be available.

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 tax rates and laws substantively enacted by the reporting date. Deferred tax assets and liabilities are offset when there exists a legal and enforceable right to offset and 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.

· Segmental reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the Chief Operating Decision Maker. The Chief Operating Decision Maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Directors of the Group that make the strategic decisions.

· Pension obligations

The liability recognised in the balance sheet in respect of defined benefit pension plans is the present value of the defined benefit obligation at the end of the reporting period. The defined benefit obligation is calculated annually by an independent actuary using the projected unit credit method.

The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using interest rates of government bonds that are denominated in the currency in which the benefits will be paid (Hryvnia), and that have terms approximating to the terms of the related obligation. Currently, there is no sufficiently developed market of bonds denominated in Hryvnia with a sufficiently long period of repayment which would be consistent with an estimated period of payment of all benefits. In such cases the Standard allows using current market rates to discount respective short-term payments and calculating the discount rate for long-term liabilities by extending the current market rates along the yield curve.

The current service cost of the defined benefit plan, recognised in the Income Statement, except where included in the cost of an asset, reflects the increase in the defined benefit obligation resulting from employee service in the current year, benefit changes curtailments and settlements. Past-service costs are recognised immediately in the Income Statement.

The net interest cost is calculated by applying the discount rate to the net balance of the defined benefit obligation. This cost is included in employee benefit expense in the statement of profit or loss.

Actuarial gains and losses arising from experience adjustments and changes in actuarial assumptions are charged or credited to equity in other comprehensive income in the period in which they arise.

· Share options

The group operates a number of equity-settled, share-based compensation plans, under which the Company receives services from Executive Directors and Senior Management as consideration for equity instruments (options) of the group. The fair value of the services received from Executive Directors and Senior Management in exchange for the grant of the options is recognised as an expense. The total amount to be expensed is determined by reference to the fair value of the options granted:

§ including any market performance conditions; (for example, the Company's share price);

§ excluding the impact of any service and non-market performance vesting conditions (for example, profitability, sales growth targets and remaining an employee of the entity over a specified time period); and

§ including the impact of any non-vesting conditions (for example, the requirement for employees to save).

Non-market performance and service conditions are included in assumptions about the number of options that are expected to vest. The total expense is recognised over the vesting period, which is the period over which all of the specified vesting conditions are to be satisfied.

In addition, in some circumstances employees may provide services in advance of the grant date and therefore the grant date fair value is estimated for the purposes of recognising the expense during the period between service commencement period and grant date.

At the end of each reporting period, the group revises its estimates of the number of options that are expected to vest based on the non-market vesting conditions. It recognises the impact of the revision to original estimates, if any, in the income statement, with a corresponding adjustment to equity.

When the options are exercised, the company issues new shares or shares held by the JKX Employee Benefit Trust. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium.

The grant by the Company of options over its equity instruments to the employees of subsidiary undertakings in the group is treated as a capital contribution. The fair value of employee services received, measured by reference to the grant date fair value, is recognised over the vesting period as an increase to investment in subsidiary undertakings, with a corresponding credit to equity in the parent entity financial statements.

The social security contributions payable in connection with the grant of the share options is considered an integral part of the grant itself, and the change will be treated as a cash-settled transaction.

The rules regarding the scheme are described in the Remuneration Report and in Note 26 on share based payments.

· Bonus scheme

The Group operates a bonus scheme for its Directors and employees. The scheme has three performance conditions: 1. financial objectives; 2. key strategic objectives and 3. safety performance conditions. The bonus payments are made annually, normally in January of each year and the costs are accrued in the period to which they relate.

· Pension costs

The Group contributes to the individual pension scheme of the qualifying employees' choice. Contributions are charged to the income statement as they become payable. The Group has no further payment obligations once the contributions have been paid.

· Decommissioning

Provision is made for the cost of decommissioning assets at the time when the obligation to decommission arises. Such provision represents the estimated discounted liability for costs which are expected to be incurred in removing production facilities and site restoration at the end of the producing life of each field. A corresponding item of property plant and equipment is also created at an amount equal to the provision. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure attributable to changes in the estimates of the cash flow or the current estimate of the discount rate used are reflected as an adjustment to the provision and the property plant and equipment. The unwinding of the discount is recognised as a finance cost.

· Provisions

Provisions are created where the Group has a present obligation as a result of a past event, where it is probable that it will result in an outflow of economic benefits to settle the obligation, and where it can be reliably measured. Provision for onerous lease is recognised when the net cash outflows exceed the expected benefits to be received under the lease.

Provisions are measured at the best estimate of the expenditure required to settle the obligation at the balance sheet date, and are discounted to present value where the effect is material. The amounts provided are based on the Group's best estimate of the likely committed outflow.

· Revenue recognition

Sales of oil and gas products are recognised when the significant risks and rewards of ownership have passed to the buyer and it can be reliably measured. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenue from other services are recognised when the services have been performed. Revenue is measured at the fair value of the consideration received, excluding discounts, rebates, value added tax ("VAT") and other sales taxes or duty.

Revenue resulting from the production of oil and natural gas from properties in which the Group has an interest with other producers is recognised on the basis of the Group's working interest (entitlement method). Gains and losses on derivative contracts are reported on a net basis in the consolidated income statement.

Interest income is recognised as the interest accrues, by reference to the net carrying amount at the effective interest rate applicable.

· Share capital and treasury shares

Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of ordinary shares are recognised as a deduction from share premium, net of any tax effects. When share capital recognised as equity is repurchased, the amount of the consideration paid, which includes directly attributable costs, net of any tax effects, is recognised as a deduction from share premium.

Repurchased JKX Oil & Gas plc shares are classified as treasury shares in shareholders' equity and are presented in the reserve for own shares. The consideration paid, including any directly attributable incremental costs is deducted from equity attributable to the Company's equity holders until the shares are cancelled or reissued.

When treasury shares are sold or reissued subsequently, the amount received is recognised as an increase in equity, and the resulting surplus or deficit on the transaction is presented in share premium. No gain or loss is recognised in the financial statements on the purchase, sale, issue or cancellation of treasury shares.

· Leasing

Rentals payable under operating leases are charged to the income statement on a straight-line basis over the term of the relevant lease. Under operating leases, the risks and rewards of ownership are retained by the lessor. The Group has no finance leases.

· Dividends

Interim dividends are recognised when they are paid to the Company's shareholders. Final dividends are recognised when they are approved by shareholders.

· 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 giving 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. See Notes 5 and 19 for further details.

· Critical accounting estimates and assumptions

The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions 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)

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 and (v) the value ascribed to contingent resources associated with the asset.

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 a project is sufficiently advanced the recoverability of intangible exploration assets is assessed by comparing the carrying value to estimates of the present value of projects. 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 5a)

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 proved 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.

d) Taxation (Notes 27 and 28)

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.

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 (2016: 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 includes the head office and purchases material, capital assets and services on behalf of other segments. The 'Rest of World' segment comprises operations in Hungary and Slovakia.

Transfer prices between segments are set on an arm's length basis in a manner similar to transactions with third parties. 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.

There is one customer in Russia that exceeds 10% of the Group's total revenues (2016: one in Russia).

5. Property, plant and equipment and Intangible assets

5.(a) Property, plant and equipment

Oil and gas fields in Ukraine and Russia include $2.6m and $4.8m respectively relating to items under construction (2016: nil).

Exceptional item - provision for impairment of oil and gas assets

During 2016 and 2017 impairment triggers were noted in respect of our oil and gas assets in Ukraine, Russia and Hungary. 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, Russian and the Hungarian assets.

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

The latest reserve estimates for the Novomykolaivske Complex included a significant downwards revision from 29.1 MMboe to 23.3 MMboe which constituted an impairment trigger. In addition, a review was also undertaken for the Elyzavetivske filed where performance through 2017 was significantly better than expected.

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 21.8 MMboe and 1.6 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 2031). The economic life of the Elyzavetivske field is currently expected to be around 2023.

§ 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 2018 is based on current and forecast gas prices realised by PPC. 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 19.2%. 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 ($117.2m) exceeds its carrying amount ($83.9) by $33.3m and therefore NNC's oil and gas assets were not impaired.

§ Elyzavetivske's recoverable amount (including the West Mashivska extension) ($12.3) exceeds its carrying amount ($0.5) by $11.8m, and therefore a reversal has been made, as explained in more detail below.

· Elyzavetivske impairment reversal

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 has been recognised.

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, production tax rates, 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.

During 2017 YGE experienced delays in its workover of Well 5 that was not successfully completed. This was considered significant enough to trigger an impairment review.

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 71.7 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 2048). 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 2018 and annually thereafter, the gas prices have been increased by 3.9% through to 2021, and estimated Russian inflation of 4.0% thereafter.

§ 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 11.5%. 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 ($115.3m) exceeds it carrying amount ($100.8m) by $14.5m 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

· Hungarian property plant and equipment - Folyópart Energia Kft ('FEN')

The Company now holds a 100% interest in six development licences (Mining Plots) through its wholly owned Hungarian subsidiary, Folyópart Energia Kft.

In December 2016, well Hn-2ST (sidetrack) was successfully completed on the Hajdunanas IV Mining Plot (HMP). This was the first drilling operation completed since JKX assumed operatorship in November 2014. The Hn-2ST (sidetrack) did not encounter any productive oil horizons, which had been included in the pre-drill estimates of contingent resources. In October 2017 workover of well Hn-1 was completed however actual results were lower than expected. The results from the Hn-2ST (sidetrack) and Hn-1 therefore constituted an impairment trigger and a full impairment review was completed in respect of HMP.

· Hungarian Cash Generating Unit ('CGUs')

HMP forms a single CGU which is serviced by a single processing facility and commonality of facilities, personnel and services. In accordance with IAS 36, the impairment review for HMP has been undertaken in US$ being the currency in which future cash flows from HMP will be generated.

· Key Assumptions - HMP

The key assumptions used in the impairment testing in 2017 were:

§ Production profiles: these were based on the latest available test and production data from the recent production from Hn-1 and internal assessment. The Company included internally assessed 2P reserves of 0.04 MMboe;

§ Oil and gas prices: these were based on current prices being realised and short term price curves derived from expectations in the Hungarian oil and gas market.

§ Capital and operating costs: these were based on project estimates provided by third parties and the partner and operator of our Hungarian assets.

The post tax discount rate of 10% was applied based on a Capital Asset Pricing Model analysis for the Group's Hungarian assets.

Based on the key assumptions set out above HMP's recoverable amount of nil is lower than its carrying amount by $2.8m and therefore HMP's 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 - 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 is $9.4m.

Impairment of Hungarian exploration and evaluation expenditure

The Tiszavasvári-IV Mining Plot contains the Tiszavasvári-6 discovery well ('TZ-6'), which, due to the early stage of appraisal, is 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 is no clear indication that FVLCD is greater than zero and the assets were impaired in full by $0.8m.

Impairment of Slovakian exploration and evaluation expenditure

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

6. Other receivable

Other receivables consist of VAT recoverable as a result of expenditures incurred in Russia. The receivable is expected to be recovered between two and five years (2016: two and five years).

7. Investments

The net book value of unlisted investments comprises:

Full provision was made against investments in 2007 which comprise an investment in a Ukrainian oil and gas company. At the end of 2007 there were no clear development plans relating to the investment and this continues to be the position at 31 December 2017. The investment reflects a 10% holding of the Company's ordinary share capital.

8. Inventories

During the year obsolete inventories of $0.6m were written off to profit and loss under 'cost of sales' at Poltava Petroleum Company ('PPC'), our wholly owned subsidiary in Ukraine.

9. Trade and other receivables