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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Jkx Oil & Gas Plc | LSE:JKX | London | Ordinary Share | GB0004697420 | ORD 10P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 41.50 | 39.50 | 42.00 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
TIDMJKX
RNS Number : 4443J
JKX Oil & Gas PLC
29 March 2018
Hot Features
Premium
6 Cavendish Square, London
W1G 0PD, England, UK
Tel: +44 (0)20 7323 4464 Fax:
+44 (0)20 7323 5258
Website: http://www.jkx.co.uk
FOR IMMEDIATE RELEASE 29 March 2018
JKX Oil & Gas plc
('JKX' or the 'Company')
PRELIMINARY RESULTS
FOR THE YEARED 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.
2017 2016 Change %
Group revenues $m $m $m Change
--------------- ---- -------------- ------ --------
Ukraine 57.0 54.8 2.2 4.0
Gas 35.8 35.9 (0.1) (0.3)
Oil 16.5 15.1 1.4 9.3
Liquefied
Petroleum
Gas ('LPG') 4.6 3.8 0.8 21.0
Other 0.1 0 0.1
--------------- ---- -------------- ------ --------
Russia 17.6 19.0 (1.4) (7.4)
Gas 17.0 18.3 (1.3) (7.1)
Condensate 0.6 0.7 (0.1) (14.3)
--------------- ---- -------------- ------ --------
Hungary 1.8 - 1.8 100.0
Gas 1.6 - 1.6 100
Condensate 0.2 - 0.2 100
=============== ==== ============== ====== ========
Total 76.4 73.8 2.6 3.5
--------------- ---- -------------- ------ --------
Sales prices 2017 2016 Change % Change
-------------- ------ ------ ------ --------
Ukraine
Gas ($/Mcf) 6.72 5.92 0.80 13.5
Oil ($/bbl) 64.26 45.94 18.32 39.9
LPG ($/tonne) 467.49 374.81 92.68 24.7
Russia
Gas ($/Mcf) 1.69 1.49 0.2 13.4
Hungary
Gas ($/Mcf) 6.06 - 6.06 N/A
Group
Gas ($/Mcf) 3.50 2.95 0.55 18.6
Oil ($/bbl) 64.26 45.94 18.32 39.9
LPG ($/tonne) 467.49 374.81 92.68 24.7
-------------- ------ ------ ------ --------
Average exchange
rates 2017 2016 Change % Change
----------------- ----- ----- ------ --------
Russia (RUB/$) 58.30 64.31 6.01 9.3
Ukraine (UAH/$) 26.60 25.55 (1.05) (3.9)
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 1/2 " 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.
Hajdunanas 28 sq IV km Hajdunanas V 7 sq km Tiszavasvari IV 41 sq km Emod V 100 sq km Pely I 18 sq km Jaszkiser II 6 sq km
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.
Total remaining 2P reserves
at 31 December 2017
31-Dec-16 Revisions Production 31-Dec-17
------------- ---------- ---------- ----------- ----------
TOTAL
Oil (MMbbl) 3.9 0.2 (0.2) 3.9
Gas (Bcf) 632.6 (68.8) (17.3)* 546.5
Oil + Gas
(MMboe) 109.4 (11.3) (3.0) 95.1
------------- ---------- ---------- ----------- ----------
UKRAINE
Oil (MMbbl) 3.1 0.3 (0.2) 3.2
Gas (Bcf) 155.6 (29.1) (6.1) 120.4
Oil + Gas (MMboe) 29.1 (4.6) (1.2) 23.3 ------------- ---------- ---------- ----------- ---------- RUSSIA Oil (MMbbl) 0.8 (0.1) (0.0) 0.7 Gas (Bcf) 476.9 (40.1) (10.9) 425.9 Oil + Gas (MMboe) 80.3 (6.8) (1.8) 71.7 ------------- ---------- ---------- ----------- ----------
*0.26 Bcf produced in Hungary
Field-by-Field 2P reserves at 31 December 2017
MMboe Dec-16 Revisions Production Dec-17 -------------------- ------- ---------- ----------- ------- Ukraine -------------------- ------- ---------- ----------- ------- Ignativske 3.9 2.2 (0.5) 5.6 -------------------- ------- ---------- ----------- ------- Movchanivske 0.6 0.2 (0.1) 0.7 -------------------- ------- ---------- ----------- ------- Novomykolaivske 0.7 (0.1) (0.1) 0.5 -------------------- ------- ---------- ----------- ------- Rudenkivske 22.2 (7.1) (0.1) 15.0 Zaplavska - - - - -------------------- ------- ---------- ----------- ------- sub-total Novo-Nik production licences 27.4 (4.9) (0.8) 21.8 Elyzavetivske 1.7 0.3 (0.4) 1.6 -------------------- ------- ---------- ----------- ------- Total Ukraine 29.1 (4.6) (1.2) 23.3 -------------------- ------- ---------- ----------- ------- Russia -------------------- ------- ---------- ----------- ------- Koshekhablskoye 80.3 (6.8) (1.8) 71.7 -------------------- ------- ---------- ----------- ------- Total 109.4 (11.3) (3.0) 95.1 -------------------- ------- ---------- ----------- -------
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.
MMboe 1C 2C (best) 3C (high)
(low)
---------------------- ------- ---------- ----------
Ignativske 11.98 17.53 50.10
----------------------- ------- ---------- ----------
Movchanivske 0.00 1.25 2.76
----------------------- ------- ---------- ----------
Novomykolaivske 0.00 0.00 0.15
----------------------- ------- ---------- ----------
Rudenkivske 9.16 65.52 197.89
Zaplavskoye 0.03 0.38 1.41
sub-total
Novo-Nik production
licences 21.17 84.68 252.31
----------------------- ------- ---------- ----------
Elyzavetivske 0.00 6.20 20.83
----------------------- ------- ---------- ----------
Total Ukraine 21.17 90.88 273.14
----------------------- ------- ---------- ----------
Koshekhablskoye 24.12 74.77 107.53
----------------------- ------- ---------- ----------
Hadjunanas 0.0 0.0 0.0
----------------------- ------- ---------- ----------
Tiszavasvari
6 0.2 0.3 0.7
----------------------- ------- ---------- ----------
Total 45.49 165.95 381.37
----------------------- ------- ---------- ----------
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.
What is the risk? How do we manage it?
------------------------------------------ ---------------------------------------
Liquidity, funding, and
portfolio management.
The Board plans to accumulate
Description: As for any sufficient liquidity by
other exploration and production deferring high-risk investment
company, our fields are projects and minimizing
prone to natural production costs. Upon internal review
decline and hence replacing of reserves and development
our reserves is important plans our plan for 2018
for long-term success. Our includes activity to boost
ability to ensure long-term production in our core fields
sustainable production depends and to engage in low risk
on having sufficient funds appraisal. Additionally,
to invest in our development the new plan envisages
and efficient allocation more modest but more realistic
of capital on investment development strategy for
projects or acquisitions. the Rudenkivske field starting
It is important to maintain in 2019.
sufficient liquidity to
allow for operational, technical, PPC, has secured a standing
commercial, legal, and other credit line of approximately
contingencies. Having sufficient $5.3 million and YGE is
funds to invest in development considering options for
projects or other growth a similar facility. Projects
opportunities is subject are analysed and ranked
to not only cash flow generated across the Group and capital
by existing operations, is allocated accordingly.
but also access to external Additionally, the Company
capital (such as equity has established a new Investment
or debt financing) or ability Committee which provides
to carry out corporate transactions an additional venue for
(such as mergers, acquisitions, discussing and making investment
or divestitures). decisions.
Impact: Inability to build Details are provided in
or maintain sufficient liquidity Note 2 to the financial
may result in increased statements.
risk of having insufficient
funds on hand to address
unanticipated cash outflows,
need to suspend planned
payments to third parties,
or other unplanned actions
to urgently build sufficient
liquidity. Poor capital
allocation decisions, inability
to access external sources
of capital or execute corporate
transactions may result
in long-term decline in
production and cash flow
from existing operations
and further reduced ability
to engage in new development
projects. With unrestricted
cash on hand at 31 December
2017 of $6.9 million compared
to $14.1 million at 31 December
2016, this risk has increased
compared to the previous
year.
Geopolitical and fiscal.
Description: Most of the In respect of the 2010 Claims
Group's operations and more and 2015 Claims, provisions
than 97% of our oil and of $11.3 million and $25.7
gas assets are located in million, respectively, have
Ukraine and Russia and the been recognised in these
oil, gas and condensate financial statements to
that we produce is sold reflect the Company's estimate
into their domestic markets. of the potential liability
There are geopolitical risks (see Note 27 to the financial
related to these countries statements).
and relationship between
them. Some of such risks Except for the provision
may be related to changes in respect of the 2010 and
in: 2015 Claims, the Group's
* Taxes financial statements do
not include any other adjustments
to reflect the possible
* capital controls future effects on the recoverability,
and classification of assets
or the amounts or classifications
* laws and regulations of liabilities that may
result from these tax uncertainties.
* political situation, or A key priority for the Group
is to maintain transparent
working relationships with
* investor sentiment all key stakeholders in
our significant assets in
Ukraine and Russia and to
Both countries have relatively improve the methods of regular
weak judicial systems that dialogue and ongoing communications
are susceptible to outside locally. Our strategy is
influence, and it can take to employ skilled local
an extended period for the staff working in the countries
courts to reach final judgment. of operation and to engage
Both countries display emerging established legal, tax and
market characteristics where accounting advisers to assist
the right to production in compliance.
can be challenged by State
and non-State parties. The The Group endeavours to
business environment is comply with all regulations
such that a challenge may via Group procedures and
arise at any time in relation controls or, where this
to the Group's operations, is not immediately feasible
licence history, compliance for practical or logistical
with licence commitments considerations, seeks to
and/or local regulations. enter into dialogue with
the relevant Government
Local legislation constantly bodies.
evolves as the governments
attempt to manage the economies
and business practices regarding
taxation, banking operations
and foreign currency transactions.
The constantly evolving
legislation can create uncertainty
for local operations if
guidance or interpretation
is not clear.
Geopolitical tensions between
Ukraine and Russia, political
instability and military
action in parts of Ukraine
have negatively impacted
its economy, financial markets
and relations with the Russian
Federation. Any continuing
or escalating military action
in eastern Ukraine could
have a further adverse effect
on the economy.
Impact: If Management's
interpretation of tax legislation
does not align with that
of the tax authorities,
the tax authorities may
challenge transactions which
could result in additional
taxes, penalties and fines
which could have a material
adverse effect on the Group's
financial position and results
of operations. PPC has at
times sought clarification
of their status regarding
a number of production related
taxes.
PPC continues to defend
itself in court against
action initiated by the
tax authorities regarding
production related taxes
for August to December 2010
('2010 Claims') and for
January to December 2015
('2015 Claims'). In addition,
in February 2017, the Company
was awarded approximately
$11.8 million in damages
plus interest and costs
of $0.3 million by an international
arbitration tribunal pursuant
to a claim made against
Ukraine under the Energy
Charter Treaty which the
Group is currently legalizing
in Ukraine (see Note 27
to the financial statements).
The Group's operations
and financial position may
also be adversely affected
by interruption, inspections
and challenges from local
authorities, which could
lead to remediation work,
time-consuming negotiations
and suspension of production
licences.
Reservoir and operational
performance.
There is daily monitoring
Description: Subsurface and reporting of the well
and operational risks are and plant performance at
inherent for our business. all our fields. Production
The reservoir performance data is analysed by our
cannot be predicted with in-house technical expertise.
certainty, and operations This supports well intervention
required for hydrocarbon planning and further field
production are subject to development. Our subsurface
risks of interruption or and operations specialists
failure. Production from and industry-recognised
our mature fields at the personnel are part of the
Novomykolaivske Complex daily monitoring and reservoir
in Ukraine require a high management process of our
level of maintenance and field and assets.
intervention to minimize
the production decline.
In Russia, acidization of
deep, high pressure and
high temperature wells and
other well maintenance procedures
to stabilise production
are required, increasing
risk of failure.
Impact: Accurate reservoir
performance forecasts from
fields in Ukraine and Russia
are critical in achieving
the desired economic returns
and to determine the availability
and allocation of funds
for future investment into
the exploration for, or
development of, other oil
and gas reserves and resources.
If reservoir performance
is lower than forecast,
sufficient finance may not
be available for planned
investment in other development
projects which will result
in lower production, profits
and cash flows. Inability
to ensure continuous operation
of wells, flowlines, production
facilities and successful
execution of drilling, workover,
repair, and enhancement
interventions may result
in lower production, profits
and cash flows.
In 2017, the Company embarked
on a major appraisal program
of the Rudenkivske field
in Ukraine, with the results
being significantly lower
than initially expected.
Given the resultant decreased
amounts of liquidity, accuracy
of our forecasts is even
more important.
Financial discipline and
governance.
The Board and the executive
Description: The Group has team are in the process
presence in six countries of a conducting a thorough
with major operations in assessment of existing governance
Russia, Ukraine, and the and control procedures on
United Kingdom. Such a complex a Group and asset levels
structure requires rigorous to identify gaps given Board,
governance and control procedures staff, and
to be in place to ensure management changes and
an appropriate level of implement a new framework
financial discipline and more appropriate for current
controls, as well as delegation circumstances. In the meantime,
of authority along the corporate existing controls have been
and management structure. strengthened significantly
with Executives and the
Over the past few years, Board reviewing and approving
the Group has gone through practically all contracts,
several major Board and payments, and investment
management changes, changes decisions.
of advisors and contractors,
and a significant reduction
of staff across its operations.
These changes require additional
efforts to ensure proper
implementation of governance,
controls, and financial
discipline procedures.
Impact: Failure to establish
appropriate level of financial
discipline, governance and
controls may lead to unnecessary
or inappropriate spending,
lack of control over procurement,
contracting, investing decisions,
and exposure to increased
legal, regulatory, or financial
risks.
Health, safety, and environmental
risks.
Health, safety and the environment
Description: We are exposed is a priority of the Board
to a wide range of significant who are involved in the
health, safety, security planning and implementation
and environmental risks of continuous improvement
influenced by the geographic initiatives. A London-based
range, operational diversity HSECQ Manager reports directly
and technical complexity to the Chief Executive Officer.
of our oil and gas exploration The Group HSECQ Manager
and production activities. is responsible for maintaining
a strong culture of health,
Impact: Technical failure, safety and environmental
non-compliance with existing awareness in all our operational
standards and procedures, and business activities.
accidents, natural disasters The HSECQ Manager reports
and other adverse conditions to the Board with details
where we operate, could of Group performance. Operations
lead to injury, loss of in Ukraine, Russia and Hungary
life, damage to the environment, all have a dedicated HSECQ
loss of containment of hydrocarbons Team of local personnel
and other hazardous material, led by an HSECQ Manager
as well as the risk of fires who reports to the HSECQ
and explosions. Failure Director for that particular
to manage these risks effectively region.
could result in loss of
certain facilities, with All locations have HSE Management
the associated loss of production, Systems modelled on the
or costs associated with ISO 9000 series, OHSAS 18001
mitigation, recovery, compensation and ISO 14001. Appropriate
and fines. Poor performance insurance policies, provided
in mitigating these risks by reputable insurers, are
could also result in damaging maintained at Group level
publicity for the Group. to mitigate the Group's
financial exposure to any
unexpected adverse events
arising out of the normal
operations. In April 2017
during a planned workover
of well 25 in Russia there
were delays in the workover
due to a fire on the workover
rig. The fire was limited
to the rig itself and was
promptly put out without
any injuries.
In February 2018 an accident
happened that resulted in
the fatality of an operator
at PPC. A committee has
been established to conduct
a full investigation of
the accident. It is expected
to conclude in Q2 2018.
Asset integrity.
Description: Our operations Status of our licenses and
depend on maintaining and relevant license obligations
adhering to license requirements are monitored on a country
and related regulations level. In 2015, our subsidiary
by set by government authorities in Russia received notices
in countries we operate from two regulatory authorities,
in. Rosnedra and Rosprirodnadzor,
related to obligations to
Impact: Failure to comply explore deeper Callovian
with license obligations reservoirs in our field.
and other regulations or These notices were addressed
requirements may result in 2017 and will continue
in our licenses being suspended to be addressed in 2018.
or revoked which will require
us to suspend production
and operations.
Major breach of business,
ethical, or compliance standards.
Description: The Company Compliance related activities
is subject to numerous requirements include training, monitoring,
and standards including risk management, due diligence
the UK Bribery Act, UK Listing and regular review of policies
Rules, UK Corporate Governance and procedures.
Code, UK Listing Rules,
and Disclosure and Transparency We prohibit bribery and
Rules, among others. Additionally, corruption in any form by
some of our stakeholders, all employees and by those
such as financial institutions, working for and/or connected
may require us to comply with the business. Employees
with other requirements are expected to report actual,
or ask us to provide information attempted or suspected bribery
on our business, operations, or other issues related
employees and shareholders to compliance to their line
as part of Know Your Client managers or through our
("KYC") procedures. independently managed confidential
I reporting process, which
Impact: Failing to comply is available to all staff
with onerous regulations as well as third parties.
and requirements, such as
failure to implement adequate In 2017, we engaged an independent
systems to prevent bribery consultant to assess our
and corruption, could result anti-bribery and corruption
in prosecution, fines or ("ABC") policies,
penalties imposed on the procedures, and practices
Company or its officers, and we are in the process
suspension of operations of implementing recommendations
or listing. Inability to to further strengthen our
clear KYC procedures to ABC framework. In dealing
satisfaction of the third with the third parties,
parties may result in refusal our policy is to maximize
to engage in business relationships transparency and provide
with the Company. all information available
to address KYC-related procedures
and requests.
Commodity prices and FX
fluctuations.
JKX's policy is not to hedge
Description: JKX is exposed commodity price exposure
to international oil and on oil, gas, LPG or condensate
gas price movements, policy and not to hedge foreign
developments in Russia which exchange risk.
may affect the regulated
gas price, and movements JKX attempts to maximise
in exchange rates. Such its realisations versus
changes will have a direct relevant benchmarks while
effect on the Group's trading keeping credit risk to a
results. minimum by selling mostly
on spot markets and on a
Gas prices in Ukraine are prepayment basis, ensuring
correlated with gas prices sales are as closely matched
in Europe. Since Ukraine as possible, in terms of
stopped purchasing gas from timing and volume, to production.
Russia directly, domestic
gas prices were at a premium In 2017, hydrocarbons produced
to those in Europe. Change in Ukraine were sold by
in gas import flows may way of direct contracts
have impact on gas prices with customers or open and
in Ukraine, and a prolonged transparent auctions conducted
period of low gas prices via an independent provider
would impact the Group's (such as Ukrainian Energy
liquidity. Exchange) or our own sales
platform. As commodity prices
In Russia, from 1 July 2017 in Ukraine closely follow
the regulated price which international benchmarks,
our sales contract is tied significant changes in the
to has increased by 3.9% exchange rates are reflected
however, prevailing prices in commodity prices providing
remain significantly lower a natural hedge.
than in Europe due to existing
regulations. Oil prices In Russia, all gas produced
recovered from recent historic was sold to a single local
lows in 2016 and are predicted gas trading company through
to not increase further a long-term gas sales contract
in the short term by many with prices set in Roubles.
market commentators. Sales price for gas is fixed
and is subject to increase
The Company sells the oil according to changes in
it produces at prices determined a tariff set by relevant
by the global oil market. regulatory bodies. The Company
During 2017, the average continues to seek to engage
Hryvnia exchange rate has other buyers of its gas
depreciated by 4% and average in Russia to improve realisations.
Rouble exchange rate has The Group attempts to match,
appreciated by 15% against as far as practicable, receipts
the US Dollar. and payments in the same
currency and also follow
Impact: A period of low a range of commercial policies
oil and/or gas prices could to minimise exposures to
lead to impairments of the foreign exchange gains and
Group's oil and gas assets losses.
(see Note 5 to the financial
statements) and may impact
the Group's ability to support
its long-term capital investment
programme (see Liquidity,
Funding, and Portfolio Management
Risk) and reduce shareholder
returns including dividends
and share price.
Consolidated income statement (unaudited)
for the year ended 31 December
Note 2017 2016
$000 $000
Revenue 4 76,436 73,848
Cost of sales
Exceptional item -production based taxes 18 (4,357) (24,340)
Exceptional item - reversal of provision for impairment of Ukrainian oil and gas assets 5 5,636 -
Exceptional item - provision for impairment of Hungary and Slovakia 5 (11,450) (2,000)
Exceptional item - write off of appraisal expenditure in Ukraine 5 (9,391) -
Other production based taxes 20 (16,956) (17,737)
Other cost of sales (36,647) (38,290)
Total cost of sales 20 (73,165) (82,367)
Gross profit/(loss) 3,271 (8,519)
Disposal of property, plant and equipment 5 (548) -
Exceptional items 19 (1,513) (4,484)
Other administrative expenses (15,862) (22,182)
Total administrative expenses (17,923) (26,666)
Gain on foreign exchange 1,424 431
Profit/(loss) from operations before exceptional items 7,847 (3,930)
Loss from operations after exceptional items (13,228) (34,754)
Finance income 21 348 1,836
Finance costs 22 (3,164) (4,636)
Fair value movement on derivative liability 13 (3) (599)
Loss before tax (16,047) (38,153)
Taxation - current 27 (2,964) (1,341)
Taxation - deferred
- before the exceptional items 27 (2,765) 1,209
- on the exceptional items 27 4,113 1,170
Total taxation 27 (1,616) 1,038
Loss for the year attributable to equity shareholders of the parent company (17,663) (37,115)
Basic loss per 10p ordinary share (in cents)
- before exceptional items 29 (0.41) (4.34)
- after exceptional items 29 (10.26) (21.56)
Diluted loss per 10p ordinary share (in cents)
- before exceptional items 29 (0.41) (4.34)
- after exceptional items 29 (10.26) (21.56)
Consolidated statement of comprehensive income (unaudited)
for the year ended 31 December
2017 2016
$000 $000
Loss for the year (17,663) (37,115)
Other comprehensive income to be reclassified to profit or loss in subsequent periods when
specific conditions are met
Currency translation differences 7,118 19,634
Other comprehensive income that will not be reclassified to profit or loss in subsequent periods
Remeasurements of post-employment benefit obligations (333) -
Other comprehensive income for the year, net of tax 6,785 19,634
Total comprehensive income attributable to:
Equity shareholders of the parent (10,878) (17,481)
Consolidated statement of financial position (unaudited)
as at 31 December
Note 2017 2016
$000 $000
ASSETS
Non-current assets
Property, plant and equipment 5(a) 194,031 194,510
Intangible assets 5(b) - 7,706
Other receivable 6 3,136 3,277
Deferred tax assets 28 20,840 18,724
218,007 224,217
Current assets
Inventories 8 5,824 4,585
Trade and other receivables 9 4,969 4,174
Restricted cash 10 497 201
Cash and cash equivalents 10 6,929 14,067
18,219 23,027
Total assets 236,226 247,244
LIABILITIES
Current liabilities
Current tax liabilities (645) (592)
Trade and other payables 11 (12,368) (15,095)
Borrowings 12 (7,630) (16,795)
Provisions 18 (37,269) (34,510)
Derivatives 13 - (1,341)
(57,912) (68,333)
Non-current liabilities
Provisions 18 (5,341) (4,264)
Other payables (3,136) (3,277)
Borrowings 12 (9,003) -
Derivatives 13 (3) -
Deferred tax liabilities 28 (14,922) (14,537)
(32,405) (22,078)
Total liabilities (90,317) (90,411)
Net assets 145,909 156,833
EQUITY
Share capital 16 26,666 26,666
Share premium 97,476 97,476
Other reserves 17 (153,126) (159,911)
Retained earnings 174,893 192,602
Total equity 145,909 156,833
Consolidated statement of cash flows (unaudited)
for the year ended 31 December
Note 2017 2016
$000 $000
Cash flows from operating activities
Cash generated from operations 31 15,723 17,038
Interest paid (1,760) (2,392)
Income tax paid (2,933) (10)
Net cash generated from operating activities 11,030 14,636
Cash flows from investing activities
Interest received 348 753
Dividend received 114 -
Proceeds from sale of property, plant and equipment 291 550
Purchase of intangible assets (9,581) (90)
Purchase of property, plant and equipment (7,131) (7,366)
Net cash used in investing activities (15,959) (6,153)
Cash flows from financing activities
Restricted cash (296) 111
Repayment of borrowings (1,920) (10,856)
Repurchase of convertible bonds - (9,036)
Net cash used in financing activities (2,216) (19,781)
Decrease in cash and cash equivalents in the year (7,145) (11,298)
Cash and cash equivalents at 1 January 14,067 25,943
Effect of exchange rates on cash and cash equivalents 7 (578)
Cash and cash equivalents at 31 December 10 6,929 14,067
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 periods
beginning 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:GBP0.74 (2016: $1:GBP 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:
Motor vehicles - 4 years Computer equipment - 3 years Other equipment - 5 to 10 years
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.
UK Ukraine Russia Rest of World Sub Total Eliminations Total
2017 $000 $000 $000 $000 $000 $000 $000
External revenue
Revenue by location of asset:
- Oil - 16,458 636 174 17,268 - 17,268
- Gas - 35,835 16,998 1,630 54,463 - 54,463
- Liquefied petroleum gas - 4,607 - - 4,607 - 4,607
- Management services/other 33 50 15 - 98 - 98
33 56,950 17,649 1,804 76,436 - 76,436
Inter segment revenue:
- Management services/other 11,020 - - - 11,020 (11,020) -
11,020 - - - 11,020 (11,020) -
Total revenue 11,053 56,950 17,649 1,804 87,456 (11,020) 76,436
Loss before tax:
Loss from operations (1,911) 3,733 (2,692) (12,255) (13,125) (103) (13,228)
Finance income 348 - 348
Finance cost (3,164) - (3,164)
Fair value movement on derivative
liability (3) - (3)
(15,944) (103) (16,047)
Assets
Property, plant and equipment 268 90,024 102,961 778 194,031 - 194,031
Intangible assets - - - - - - -
Other receivable - - 3,136 - 3,136 - 3,136
Deferred tax - 7,536 11,293 2,011 20,840 - 20,840
Inventories - 2,497 3,327 - 5,824 - 5,824
Trade and other receivables 572 1,528 2,004 865 4,969 - 4,969
Restricted cash 269 - - 228 497 - 497
Cash and cash equivalents 2,762 3,141 558 468 6,929 - 6,929
Total assets 3,871 104,726 123,279 4,350 236,226 - 236,226
Total liabilities (18,227) (56,732) (9,313) (6,045) (90,317) - (90,317)
Non cash expense (other than
depreciation and impairment) 80 - 36 - 116 - 116
Exceptional item - reversal of
provision for impairment of
Ukrainian oil and gas assets - 5,636 - - 5,636 - 5,636
Exceptional item - provision for
impairment of oil and gas assets - - - 2,755 2,755 - 2,755
Exceptional Item - write off of
exploration and appraisal costs - - - 8,695 8,695 - 8,695
Exceptional item - write off of
appraisal expenditure in Ukraine - 9,391 - - 9,391 - 9,391
Exceptional item - production based
taxes - 4,357 - - 4,357 - 4,357
Exceptional items - other 1,513 - - - 1,513 - 1,513
Increase in property, plant and
equipment and intangible assets 203 12,688 5,771 660 19,322 - 19,322
Depreciation, depletion and
amortisation 116 12,139 5,173 - 17,428 - 17,428
UK Ukraine Russia Rest of World Sub Total Eliminations Total
2016 $000 $000 $000 $000 $000 $000 $000
External revenue
Revenue by location of asset:
- Oil - 15,092 665 - 15,757 - 15,757
- Gas - 35,945 18,343 - 54,288 - 54,288
- Liquefied petroleum gas - 3,776 - - 3,776 - 3,776
- Management services/other - 23 4 - 27 - 27
- 54,836 19,012 - 73,848 - 73,848
Inter segment revenue:
- Management services/other 9,168 - - - 9,168 (9,168) -
9,168 - - - 9,168 (9,168) -
Total revenue 9,168 54,836 19,012 - 83,016 (9,168) 73,848
Loss before tax:
Loss from operations (11,083) (18,984) (741) (3,807) (34,615) (139) (34,754)
Finance income 1,836 - 1,836
Finance cost (4,636) - (4,636)
Fair value movement on derivative
liability (599) - (599)
(38,014) (139) (38,153)
Assets
Property, plant and equipment 204 93,010 97,894 3,402 194,510 - 194,510
Intangible assets - - - 7,706 7,706 - 7,706
Other receivable - - 3,277 - 3,277 - 3,277
Deferred tax - 3,556 12,578 2,590 18,724 - 18,724
Inventories - 1,884 2,701 - 4,585 - 4,585
Trade and other receivables 914 338 2,621 301 4,174 - 4,174
Restricted cash - - - 201 201 - 201
Cash and cash equivalents 6,146 5,480 1,899 542 14,067 - 14,067
Total assets 7,264 104,268 120,970 14,742 247,244 - 247,244
Total liabilities (22,677) (55,093) (7,453) (5,188) (90,411) - (90,411)
Non cash expense (other than
depreciation and impairment) - - 265 257 522 - 522
Exceptional item - provision for
impairment of oil and gas assets - - - 2,000 2,000 - 2,000
Exceptional item - production based
taxes - 24,340 - - 24,340 - 24,340
Exceptional item - administrative
expenses 4,454 - - 30 4,484 - 4,484
Increase in property, plant and
equipment and intangible assets 10 4,051 250 1,339 5,650 - 5,650
Depreciation, depletion and
amortisation 381 12,028 7,355 - 19,764 - 19,764
Major customers 2017 2016
$000 $000
Russia 16,964 19,008
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 assets
Oil and gas fields Gas field Oil and gas fields
Ukraine Russia Hungary Other assets Total
2017 $000 $000 $000 $000 $000
Group
Cost
At 1 January 564,023 213,181 36,971 18,296 832,471
Additions during the year 3,172 5,756 471 344 9,743
Foreign exchange equity adjustment - 12,088 - 117 12,205
Disposal of property, plant and equipment - (876) - (500) (1,376)
At 31 December 567,195 230,149 37,442 18,257 853,043
Accumulated depreciation, depletion and
amortisation and provision for impairment
At 1 January 471,013 115,293 34,687 16,968 637,961
Depreciation on disposals of property,
plant and equipment - (24) - (487) (511)
Exceptional item - reversal of provision
for impairment of Ukrainian oil and gas
assets (5,636) - - - (5,636)
Exceptional item - provision for
impairment of oil and gas assets in
Hungary - - 2,755 - 2,755
Foreign exchange equity adjustment - 6,957 - 58 7,015
Depreciation charge for the year 11,794 4,962 - 672 17,428
At 31 December 477,171 127,188 37,442 17,211 659,012
Carrying amount
At 1 January 93,010 97,888 2,284 1,328 194,510
At 31 December 90,024 102,961 - 1,046 194,031
Oil and gas fields in Ukraine and Russia include $2.6m and $4.8m respectively relating to items under construction (2016: nil).
Oil and gas assets
Oil and gas fields Gas field Oil and gas fields
Ukraine Russia Hungary Other assets Total
2016 $000 $000 $000 $000 $000
Group
Cost
At 1 January 560,186 177,469 36,289 20,315 794,259
Additions during the year 3,947 84 1,249 277 5,557
Foreign exchange equity adjustment - 35,770 - 240 36,010
Disposal of property, plant and equipment (110) (142) (567) (2,536) (3,355)
------------------ ---------- ------------------ ------------- -------
At 31 December 564,023 213,181 36,971 18,296 832,471
------------------ ---------- ------------------ ------------- -------
Accumulated depreciation, depletion and
amortisation and provision for impairment
At 1 January 459,551 89,291 32,687 18,081 599,610
Depreciation on disposals of property,
plant and equipment (110) (54) - (2,265) (2,429)
Exceptional item - provision for
impairment of oil and gas assets - - 2,000 - 2,000
Foreign exchange equity adjustment - 18,837 - 179 19,016
Depreciation charge for the year 11,572 7,219 - 973 19,764
------------------ ---------- ------------------ ------------- -------
At 31 December 471,013 115,293 34,687 16,968 637,961
------------------ ---------- ------------------ ------------- -------
Carrying amount
------------------ ---------- ------------------ ------------- -------
At 1 January 100,635 88,178 3,602 2,234 194,649
------------------ ---------- ------------------ ------------- -------
At 31 December 93,010 97,888 2,284 1,328 194,510
------------------ ---------- ------------------ ------------- -------
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
Ukraine Hungary Rest of World Total
2017 $000 $000 $000 $000
Group
Cost:
At 1 January 1,308 814 13,247 15,369
Additions during the year 9,391 - 190 9,581
Exceptional item - write off of appraisal expenditure in Ukraine (9,391) - - (9,391)
Effect of exchange rates on intangible assets - - 799 799
At 31 December 1,308 814 14,236 16,358
Provision against oil and gas assets
At 1 January 1,308 - 6,355 7,663
Exceptional item - Impairment of Hungarian and Slovakian assets - 814 7,881 8,695
At 31 December 1,308 814 14,236 16,358
Carrying amount
At 1 January - 814 6,892 7,706
At 31 December - - - -
Ukraine Hungary Rest of World Total
2016 $000 $000 $000 $000
Group
Cost:
At 1 January 1,308 814 13,353 15,475
Additions during the year - - 90 90
Effect of exchange rates on intangible assets - - (196) (196)
At 31 December 1,308 814 13,247 15,369
Provision against oil and gas assets
At 1 January and 31 December 1,308 - 6,355 7,663
Carrying amount
At 1 January - 814 6,998 7,812
At 31 December - 814 6,892 7,706
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:
NNC
Increase/(decrease) in Elyzavetivske
headroom of $33.3m for NNC Increase/(decrease) in
CGU headroom of $11.8m for
$m Elyzavetivske CGU $m
Impact if gas price: increased by 20% 38.6 5.8
reduced by 20% (38.6) (5.9)
Impact if gas production
volumes: increased by 10% 19.3 2.9
decreased by 10% (19.3) (2.9)
Impact if future capital
expenditure: increased by 20% (18.5) (0.5)
decreased by 20% 18.5 0.5
Impact if post-tax discount increased by 2 percentage
rate: points to 21.2% (10.5) (0.4)
decreased by 2 percentage points to 17.2% 10.5 0.3
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
Increase/(decrease) in headroom of
$14.5m for Yuzhgazenergie CGU
$m
Impact of Adygean gas price: growth rates increased by 10% annually 11.4
growth rates reduced by 10% annually (11.4)
------------------------------------------------------------------------------ -------------------------------------
Impact of production volumes: Increased by 10% 27.3
Decreased by 10% (27.3)
------------------------------------------------------------------------------ -------------------------------------
Impact of future capital expenditure: Increased by 20% (10.5)
Decreased by 20% 10.5
------------------------------------------------------------------------------ -------------------------------------
Increased by 1 percentage point to
Impact of post-tax discount rate: 12.5% (9.9)
Decreased by 1 percentage point to 10.5% 11.1
------------------------------------------------------------------------------ -------------------------------------
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:
2017 2016
$000 $000
Cost
----------------------------- ------
At 1 January and 31 December 5,617 5,617
----------------------------- ------
Accumulated impairment
----------------------------- ------
At 1 January and 31 December 5,617 5,617
----------------------------- ------
Carrying amount
----------------------------- ------
At 31 December - -
----------------------------- ------
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
2017 2016
$000 $000
Warehouse inventory and materials 4,441 3,095
Oil and gas inventory 1,383 1,490
---------------------------------- ------
5,824 4,585
---------------------------------- ------
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
2017 2016
$000 $000
Trade receivables 3,348 2,657
Less: provision for impairment of trade
receivables (505) (550)
---------------------------------------- ------
Trade receivables - net 2,843 2,107
Other receivables 508 1,019
VAT receivable 469 337
Prepayments 1,149 711
---------------------------------------- ------
4,969 4,174
---------------------------------------- ------
As of 31 December 2017, trade and other receivables of $0.5m (2016: $0.6m) were past due and impaired. The amount of the provision was $0.5m (2016: $0.6m). The impaired receivable relates to a single gas customer, which is 18 months past due. Legal proceedings were initiated at the end of 2016 and are currently ongoing in order to recover the amount outstanding.
As of 31 December 2017, trade and other receivables of $2.8m (2016: $2.1m) were neither past due nor impaired. There is no difference between the carrying value of trade and other receivables and their fair value.
The carrying amounts of the Group's trade and other receivables are denominated in the following currencies:
2017 2016
$000 $000
US Dollar 137 204
Sterling 17 69
Euros 487 131
Hungarian Forints 44 -
Ukrainian Hryvnia 776 182
Russian Roubles 1,890 2,540
------------------ ------
3,351 3,126
------------------ ------
10. Cash and cash equivalents
2017 2016
$000 $000
Cash 4,958 8,874
Short term deposits 1,971 5,193
-------------------------- -------
Cash and cash equivalents 6,929 14,067
Restricted cash 497 201
-------------------------- -------
Total 7,426 14,268
-------------------------- -------
Short term deposits comprise amounts which are held on deposit, but are readily convertible to cash.
-- Restricted cash
Included in Restricted cash is $0.2m (2016: $0.2m) held in Hungary at K & H Bank Zrt, which is deposited in accordance with the Hungarian Mining Act to cover potential compensation for any land damage and the costs of recultivation, including environmental damage of the waste management facilities. The other $0.3m (2016: nil) relates to funds received by the Trustees of the JKX Death in Services scheme pending distribution to the beneficiaries.
11. Trade and other payables
2017 2016
$000 $000
-------------------------------------- ------ ------
Trade payables 2,828 2,562
Other payables 2,209 2,759
Other taxes and social security costs 2,166 2,265
VAT payable 1,121 956
Accruals 4,044 6,553
12,368 15,095
-------------------------------------- ------ ------
12. Borrowings
2017 2016
$000 $000
Current
Convertible bonds due 2020 (2016: 2018)
(1) 7,630 16,795
---------------------------------------- ------
Term-loans repayable within one year 7,630 16,795
---------------------------------------- ------
Non-Current
Convertible bonds due 2020 (2016: 2018) 9,003 -
---------------------------------------- ------
Term-loans repayable after more than
one year 9,003 -
---------------------------------------- ------
1. At 31 December 2017 current liabilities included $7.6m, out of which $6.9m is due to be repaid on 19 February 2018 and represents $5.3m in respect of Bond principal, $0.5m in respect of prior accretion amounts and $1.1m is Bond interest payment; $0.7m is due to be repaid on 19 August 2018 and represents Bond interest payment.
-- Convertible bonds due 2020 (2016: 2018)
On 19 February 2013 the Company successfully completed the placing of $40m of guaranteed unsubordinated convertible bonds with institutional investors which were due 2018 (prior to restructuring) raising cash of $37.2m net of issue costs.
Prior to restructuring the Bonds had an annual coupon of 8 per cent per annum payable semi-annually in arrears.
The Bonds are convertible into ordinary shares of the Company at any time from 1 April 2013 up until seven days prior to their maturity on 19 February 2020 (2018 prior to restructuring) at a conversion price of 76.29 pence per Ordinary Share, unless the Company settles the conversion notice by paying the Bondholder the Cash Alternative Amount (see below).
-- Convertible bonds restructured on 3 January 2017
On 3 January 2017 a special resolution was approved by Bondholders to change the terms and conditions of the Bonds. The main amendments to the terms and conditions of the Bonds were as follows:
-- the Bondholder's option to require redemption of all of the outstanding Bonds on 19 February 2017 was deleted;
-- the final maturity date of the Bonds was extended to 19 February 2020, with the outstanding principal amount of the Bonds being repaid in three instalments; 33% on 19 February 2018; 33 % on 19 February 2019; and 34% on the 19 February 2020;
-- the coupon rate of the Bonds was increased from 8% to 14%;
-- the covenant which limited new borrowings by the Company was removed; and
-- the Company were to make two payments to Bondholders in respect of prior accretion amounts, on 19 February 2017 and on 19 February 2018 of 12.0% and 3.0%, respectively, of the principal amount of the Bonds.
19 February 2017 the Company made the first payment to Bondholders of $1.9m, 12.0% of the principal amount of the Bonds, in respect of prior accretion amounts and in accordance with the terms and conditions of the Bond. On 19 February 2018 the Company made a payment of the first instalment to Bondholders of $5.3m (33% of the principal amount of the Bonds), together with final accretion payment of $0.5m (3.0% of the principal amount of the Bonds), $1.1m interest payment in accordance with the terms and conditions of the Bond.
The revised terms and conditions of the Bond was 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. Interest, after the deduction of issue costs is charged to the income statement using an effective rate of 17.3% (18.0% prior to restructuring).
There is therefore no impact of the restructuring of the Bond on the Consolidated Income Statement in 2017.
The impact of the amendments to the Bond on the Consolidated Statement of Financial Position was to decrease the carrying amount of the total Bond liability of $18.1m (at 31 December 2016, includes the associated derivative) by $0.7m, which will be amortised over the estimated remaining life of the modified Bond.
In accordance with IFRS 9, following a modification or renegotiation of a financial liability that does not result in de-recognition, the Group 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.
-- Cash Alternative Amount
At the option of the Company, the conversion notice in respect of the Bonds can be settled in cash rather than shares, the Cash Alternative Amount payable is based on the Volume Weighted Average Price of the Company's shares prior to the conversion notice.
-- Convertible bonds repurchased and cancelled - 2016 information
On 19 February 2016, in accordance with the terms and conditions of the Bonds, the Company repurchased 50 bonds with a total principal amount of $10m. In June, September and October 2016, the Company repurchased and subsequently cancelled a total of 50 Bonds with par value of $10m resulting in $1.1m gain on redemption, which has been included in Finance income for the year year ended 31 December 2016 (see Group Annual Return for the year ended 31 December 2016, Note 21). The remaining principal amount of outstanding Bonds at 31 December 2016 was $16.0m. There were no Bonds repurchases during 2017.
-- Credit facility
On 15 December 2017, PPC, our subsidiary in Ukraine, has secured a 12 month revolving credit line from Tascombank for UAH150 million. At 31 December 2017 the total short-term line of credit amounted to $5.3m at an exchange rate of $1: 28.07 Hryvnia. The amount outstanding at 31December 2017 was nil, so the undrawn portion totaled $5.3m. The facility will be available through 14 December 2018.
The main terms and conditions of the revolving credit line are as follows:
-- drawdowns can be made either in USD or UAH;
-- interest rate cost for USD drawn down is 10%;
-- interest rate cost for UAH drawn down: 17.5% to 30 days, 18.0% 31 to 90 days, 20.75% 91 to 180 days, 22.5% 181 to 365 days;
-- borrowing above UAH90m, equivalent to $3.2m at 31 December 2017 will require a corporate guarantee from JKX Oil & Gas Plc;
-- assets with a market value of UAH355m, equivalent to $12.6m at 31 December 2017 have been identified for use as a collateral, collateral is to be provided only on drawdown ;
-- amount borrowed will be repaid during the last 4 months, by equal-sized monthly payments, to be effected on the last day of the month/the last day of the credit limit period
The credit facility of $5.3m includes two financial covenants:
-- to keep gross margin at no less than 50% during the period of the credit facility agreement, based on PPC's financial reporting results;
-- starting from the first quarter of 2018 and during the period of the credit facility agreement, PPC is to maintain the following ratio as per the financial reporting: ratio between financial (interest) debt and EBITDA (adjusted to the annual value) at no more than 3.0.
13. Derivatives
2017 2016
$000 $000
Current derivative financial instruments
At the beginning of the year 1,341 -
Reclassification to/ from non-current
derivative financial instruments (1,341) 1,341
--------------------------------------------- -------
At the end of the year - 1,341
--------------------------------------------- -------
Non-current derivative financial instruments
At the beginning of the year - 2,171
Reclassification from/ to current derivative
financial instruments 1,341 (1,341)
Full/partial settlement of derivative
liability (1,341) (1,429)
Fair value loss movement during the year 3 599
At the end of the year 3 -
--------------------------------------------- ------- -------
-- Convertible bonds due 2020 - embedded derivatives
-- Bondholder Put Option- cancelled 3 January 2017
Bondholders had the right to require the Company to redeem the following number of Bonds on the following future dates together with accrued and unpaid interest to (but excluding) such dates:
Redemption Maximum number
Date of Bonds to
be redeemed
----------- ---------------
19 February all outstanding
2017 Bonds
----------- ---------------
At 31 December 2016 current liabilities included $16.8m in respect of the put option available to bondholders on 19 February 2017. On 3 January 2017, this put option was cancelled as part of the Bond restructuring as detailed in Note 12. Bonds with a principal amount of $10.0m were redeemed on 19 February 2016 in addition to an early redemption premium of $0.9m in accordance with the terms and conditions of the bond.
-- Company Call Option
The Company can redeem the Bonds at any time in full but not in part at their principal amount plus one semi-annual coupon plus any accrued interest. If the Bonds are called prior to 19 February 2020, the redemption price will also include an additional U.S. $6,000 per Bond.
The Company can redeem the Bonds any time in full but not in part at their principal amount plus any accrued interest if the aggregate principal amount of the Bonds outstanding is less than 15% of the aggregate principal amount originally issued.
-- Fixed exchange rate
The Sterling-US Dollar exchange rate is fixed at GBP1/$1.5809 for the conversion and other features.
14. Financial instruments
-- Fair values of financial assets and financial liabilities - Group
Set out below is a comparison by category of carrying amounts and fair values of the Group's financial instruments. Fair value is the amount at which a financial instrument could be exchanged in an arm's length transaction. Where available, market values have been used (this excludes short term assets and liabilities).
Book Value Fair Value Book Value Fair Value
2017 2017 2016 2016
$000 $000 $000 $000
Financial assets
Cash and cash equivalents and
restricted cash (Note 10) -
classified as loans and receivables 7,426 7,426 14,268 14,268
Trade receivables (Note 9) -
classified as loans and receivables 2,843 2,843 2,107 2,107
Other receivables (Note 9) -
classified as loans and receivables 508 508 1,019 1,019
Financial liabilities
Trade payables (Note 11) - carried
at amortised cost 2,828 2,828 2,562 2,562
Other payables (Note 11) - carried
at amortised cost 2,209 2,209 2,759 2,759
Accruals (Note 11) - carried
at amortised cost 2,262 2,262 2,351 2,351
Borrowings - convertible bonds
due 2020 (2016: 2018) (Note
12) - carried at amortised cost
(current) 7,630 6,486 16,795 15,955
Borrowings - convertible bonds
due 2020 (2016: 2018) (Note
12) - carried at amortised cost
(non-current) 9,003 7,653 - -
Derivatives - fair value through
profit or loss (Note 13) 3 3 1,341 1,341
------------------------------------- ---------- ---------- ---------- ----------
Financial liabilities measured at amortised cost are carried at $23.9m (2016: $24.5m). The Group's borrowings at 31 December 2017 relate entirely to the convertible bonds due 2020 (31 December 2016: 2018).
-- Fair value hierarchy -- Derivatives
At the year end the Group's derivative financial instrument related to embedded derivative within the convertible bonds due 2020 (2016: 2018) (Note 13). The value of the derivative was calculated at inception using the Monte Carlo simulation methodology and subsequently using the Black-Scholes formula, and the Company's historic share price and volatility, treasury rates and other estimations. As it was derived from inputs that are not from observable market data it was grouped into level 3 within the fair value measurement hierarchy.
The main assumptions used in valuation of the derivative conversion option as at 31 December 2017 were:
-- underlying share price of: GBP0.11 (2016: GBP0.3025);
-- GBP/US$ spot rate of 1.3513 (2016: GBP1/$1.2340 );
-- historic volatility of 56.29% (2016: 53.42%);
-- risk free rate based on the maturity which is 2.14 year US Treasury rate of 1.874%, 1.14 year US Treasury rate of 1.831% and 0.14 year US Treasury rate of 1.302% (continuously compounded). At 31 December 2016 risk free rate was based on 1.14 years US Treasury rate of 0.956%.
A 10% increase/decrease in Company's historic share price volatility would have resulted in an increase in the fair value loss for the year of $0.01m and a decrease in the fair value loss that would bring derivative's fair value to nil (2016: increase in the fair value loss for the year of $0.04m, decrease in the fair value loss of $0.02m, respectively), assuming that all other variables remain constant.
-- Credit risk - Group
The Group has policies in place to ensure that sales of products are made to customers with appropriate credit worthiness. The Group limits credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. Where appropriate, the use of prepayment for product sales limits the exposure to credit risk. There is no difference between the carrying amount of trade and other receivables and the maximum credit risk exposure.
The maximum financial exposure due to credit risk on the Group's financial assets, representing the sum of cash and cash equivalents, trade receivables and other current assets, as at 31 December 2017 was $10.8m (2016: $17.4m).
-- Capital management - Group
The Directors determine the appropriate capital structure of the Group specifically, how much is raised from shareholders (equity) and how much is borrowed from financial institutions (debt) in order to finance the Group's business strategy.
The Group's policy as to the level of equity capital and reserves is to ensure that it maintains a strong financial position and low gearing ratio which provides financial flexibility to continue as a going concern and to maximise shareholder value. The capital structure of the Group consists of shareholders' equity together with net debt. The Group's funding requirements are met through a combination of debt, equity and operational cash flow.
-- Net debt
Net debt comprises: borrowings disclosed in Note 12 and total cash in Note 10 and excludes derivatives. Equity attributable to the shareholders of the Company comprises issued capital, other reserves and retained earnings (see Consolidated statement of changes in equity).
The capital structure of the Group is as follows:
2017 2016
$000 $000
Convertible bonds due 2020 (2016: 2018)
(current and non-current, Note 12) (16,633) (16,795)
Total cash (Note 10) 7,426 14,268
Net debt (9,207) (2,527)
---------------------------------------- -------- --------
Total shareholders' equity 145,909 156,833
---------------------------------------- -------- --------
Following the issue of $40m of convertible bonds in February 2013, the primary capital risk to the Group is the level of indebtedness. The convertible bond included a financial covenant which limited the Group's indebtedness (excluding the bonds themselves) in respect of any new borrowings (in addition to the bond amount) to three times 12-month free cash flow based on the most recently published consolidated financial statements. During 2016 the Group complied with this financial covenant. On 3 January 2017 this indebtedness covenant was cancelled as part of the Bond restructuring as detailed in Note 12.
-- Liquidity risk - Group
The treasury function is responsible for liquidity, funding and settlement management under policies approved by the Board of Directors. Liquidity needs are monitored using regular forecasting of operational cash flows and financing commitments. The Group maintains a mixture of cash and cash equivalents and committed facilities in order to ensure sufficient funding for business requirements.
-- Significant restrictions
Temporary capital controls were established by the National Bank of Ukraine ('NBU') on 1 December 2014 in an attempt by the Ukrainian government to safeguard the economy and protect foreign exchange reserves in the short term.
On 4 March 2015 a number of new NBU Resolutions were implemented with immediate effect (NBU No. 160 dated 3 March 2015; Resolution of the NBU No. 161 dated 3 March 2015; Resolution of the NBU No. 154 dated 2 March 2015).
The Resolutions extended the currency control restrictions implemented in Ukraine on 1 December 2014 and introduced additional measures which have the impact of restricting the remittance of funds to foreign investors under certain conditions and bans the transfer of Hryvnia to purchase Ukrainian Government bonds.
The restrictions were effective until 8 June 2016 but have subsequently been eased by the NBU resolution No. 342 on 9 June 2016. The resolution enabled the repatriation of dividends from JKX's Ukrainian subsidiary for the years 2014 and 2015. NBU issued the Resolution No.33 on 13 April 2017 which enabled the repatriation of dividends for 2016.
Prior to the easing of restrictions, Cash and short-term deposits held in Ukraine were subject to local exchange control regulations which restricted exporting capital from Ukraine. Following the easing of these restrictions, no cash or short term deposits included within this consolidated financial information is restricted.
The following tables set out details of the expected contractual maturity of non-derivative financial liabilities. The tables include both interest and principal cash flows on an undiscounted basis. To the extent that interest flows are floating rate, the undiscounted amount is derived from interest rate curves at the reporting date.
The maturity analysis for financial liabilities was as follows:
3 months
Within 3 months - 1year 1-2 years 2-3 years
Group - 31 December 2017 $000 $000 $000 $000
Maturity of financial liabilities
Trade payables (Note 11) 2,828 - - -
Other payables (Note 11) 2,209 - - -
Accruals (Note 11) 2,262 - - -
Borrowings - Convertible bonds due 2020 6,880 750 6,411 5,821
---------------------------------------- --------------- -------- ---------- ---------
Within 3 months
Group - 31 December 2016 $000
Maturity of financial liabilities
Trade payables (Note 11) 2,562
Other payables (Note 11) 2,759
Accruals (Note 11) 2,351
Borrowings - Convertible bonds due 2018(1) 16,795
-------------------------------------------
(1) Prior to restructuring of the bonds on 3 January 2017. See Note 12.
-- Interest rate risk profile of financial assets and liabilities - Group
Fixed rate interest is charged on the Group's convertible bond (see Note 12). The interest rate profile of the other financial assets and liabilities of the Group as at 31 December is as follows (excluding short-term assets and liabilities, non-interest bearing):
2017 2016
Within Within
1 Year 1 Year
Group - 31 December $000 $000
Floating rate
Short term deposits (Note 10) 1,971 5,193
Other receivables (Note 9) 508 1,019
Other payables (Note 11) 2,209 2,759
------------------------------ ------- -------------
Floating rate financial assets comprise cash deposits placed on money markets at call, seven day and monthly rates.
-- Interest rate sensitivity - Group
The sensitivity analysis below has been determined based on the exposure to interest rates on our short term deposits at the reporting date.
If interest rates had been 1 per cent higher/lower and all other variables were held constant, the Group's loss after tax and net assets for the year ended 31 December 2017 would increase/decrease by $28,150 (2016: $28,000). 1 per cent is the sensitivity rate used as it best represents management's assessment of the possible change in interest rates that could apply to the Group.
-- Foreign currency exposures - Group
The table below shows the extent to which the Group has monetary assets and liabilities in currencies other than the functional currency of the operating company involved. These exposures give rise to the net currency gains and losses recognised in the income statement.
As at 31 December the asset/(liability) foreign currency exposures were:
2017 2016
$000 $000
US Dollar 1 1
Sterling (451) 77
Euros 464 (642)
Hungarian Forints 130 72
Ukrainian Hryvnia 1,263 2,732
Bulgarian Leva 50 43
Russian Roubles 6 24
Canadian Dollar 1 1
------------------ ------ ------
Total net 1,464 2,308
------------------ ------
-- Foreign currency sensitivity - Group
The Group is mainly exposed to the currency fluctuations of Ukraine (Hryvnia), Russia (Rouble) and UK (Sterling). The sensitivity analysis principally arises on money market deposits and working capital items held at the reporting date.
The following table details the Group's sensitivity to a 5 per cent (2016: 20 per cent) increase and decrease in the US Dollar against Sterling and against Hryvnia and Rouble (2016: 20 per cent against Hryvnia and Rouble), all other variables were held constant. Due to the significant foreign currency fluctuation in the UK, Ukraine and Russia 5 per cent has been used to calculate sensitivity for Sterling, Hryvnia and Rouble. 5 per cent (2016: 20 per cent) is the sensitivity rate that best represents management's assessment of the possible change in the foreign exchange rates affecting the Group. A positive number below indicates an increase in profit and equity when the US Dollar weakens against the relevant currency. For a strengthening of the US Dollar against the relevant currency, there would be an equal and opposite impact on the profit and other equity, and the balances below would be negative.
Hryvnia Hryvnia Rouble Rouble Sterling Sterling
2017 2016 2017 2016 2017 2016
$000 $000 $000 $000 $000 $000
Profit/(loss) for the
year and Equity
5 per cent strengthening
of the US Dollar/ (2016:
20 per cent) (60) (455) - (4) 21 (13)
5 per cent weakening
of the US Dollar/(2016:
20 per cent) 60 455 - 4 (21) 13
-------------------------- ------- ------ --------
-- Commodity risk and sensitivity - Group
The Group's earnings are exposed to the effect of fluctuations in oil, gas and condensate prices and the risks relating to their fluctuation in are discussed above, together with the discussion of financial risk factors. The Group's oil, gas and condensate is sold to local trading companies through market related contracts.
The Group is a price taker and does not enter into commodity hedge agreements unless required for borrowing purposes which may occur from time to time. Therefore no sensitivity analysis has been prepared on the exposure to oil, gas or condensate prices for outstanding monetary items at the 31 December 2017 as there is no impact on any outstanding amounts.
15. JKX Employee Benefit Trust
In 2013, JKX Employee Benefit Trust was established and acquired 5,000,000 of shares in JKX Oil & Gas plc at a cost of $4.0m for the purpose of making awards under the Group's employee share schemes and these shares have been classified in the statement of financial position as treasury shares within equity.
None of these shares were used in 2017 (2016: nil) to settle share options, therefore at the year end JKX Employee Benefit Trust held 5,000,000 shares in JKX Oil & Gas plc (2016: 5,000,000).
16. Share capital
Equity share capital, denominated in Sterling, was as follows:
2017 2017 2017 2016 2016 2016
Number GBP000 $000 Number GBP000 $000
Authorised
Ordinary shares
of 10p each 300,000,000 30,000 - 300,000,000 30,000 -
------------------- ----------- -------- ------
Allotted, called
up and fully paid
Opening balance
at 1 January 172,125,916 17,212 26,666 172,125,916 17,212 26,666
Exercise of share - - - - - -
options
------------------- ----------- -------- ------
Closing balance
at 31 December 172,125,916 17,212 26,666 172,125,916 17,212 26,666
------------------- ----------- -------- ------
Of which the following are shares held in treasury:
Treasury shares held at 1 January and 31 December 402,771 40 77 402,771 40 77 ---------------- ------- -------
The Company did not purchase any treasury shares during 2017 (2016: none) and no treasury shares were used in 2017 (2016: none) to settle share options. There are no shares reserved for issue under options or contracts. As at 31 December 2017 the market value of the treasury shares held was $0.1m (2016: $0.2m).
17. Other reserves
Post-employment
Capital redemption Foreign currency benefit obligation
Merger reserve reserve translation reserve reserve Total
$000 $000 $000 $000 $000
At 1 January 2016 30,680 587 (210,812) - (179,545)
Exchange differences
arising on
translation of
overseas operations - - 19,634 - 19,634
---------------------- -------------- --------------------- --------------------- --------------------- ---------
At 31 December 2016 30,680 587 (191,178) - (159,911)
---------------------- -------------- --------------------- --------------------- ---------
At 1 January 2017 30,680 587 (191,178) - (159,911)
Exchange differences
arising on
translation of
overseas operations - - 7,118 - 7,118
Remeasurement of
post-employment
benefit obligations - - - (333) (333)
---------------------- -------------- --------------------- --------------------- --------------------- ---------
At 31 December 2017 30,680 587 (184,060) (333) (153,126)
---------------------- -------------- --------------------- --------------------- --------------------- ---------
Merger reserve was created on 30 May 1995 when JKX Oil & Gas plc acquired the issued share capital of JP Kenny Exploration & Production Limited for the issue of ordinary shares and represents the difference between the fair value of consideration given for the shares and the nominal value of those instruments.
Capital redemption reserve relates to the buyback of shares in 2002, there have been no additional share buy-backs since this time.
Foreign currency translation reserve includes movements that relate to the retranslation of the subsidiaries whose functional currencies are not the US Dollar.
During 2017, the Russian Rouble ('RR') strengthened by approximately 5% (2016: strengthened by 17%) from RR60.66/$ to RR57.60/$ (2016: strengthened RR72.88/$ to RR60.66/$). A significant portion of the currency translation differences of US$7.1m (2016: US$19.6m) included in the Consolidated statement of comprehensive income arose on the translation of property, plant and equipment denominated in RR (see Note 5 (a)).
Post-employment benefit obligation reserve relates to a defined benefit pension plan in PPC, our subsidiary in Ukraine. Under the Ukrainian legislation, employees who work in hazardous conditions have the right for an early retirement. PPC has jobs with hazardous working conditions (hereinafter referred to as the "list II") and participates in the government defined benefit plan. Upon early retirement the pensioners are entitled to a pension which is financed by their employers until they enrolled into a regular pension scheme financed by a Pension Fund of Ukraine. The early pension benefit (in the form of a monthly annuity) is payable by employers only until the employee has reached the statutory retirement age (60 - for males and females). The right to pension emerges once a number of conditions pertaining to pension insurance service record and service record in hazardous jobs have been met and a certain age has been reached. Once employees from the list II have reached 55 years of age, PPC would compensate to Pension Fund of Ukraine pension obligation for the next 5 years on a monthly basis. The employer is responsible for 100% for "list II" categories of early pensioners. Pensions are calculated using a formula based on the employee's salary, pension insurance service record, and total length of past service at specific types of workplaces ("list II" category) and, thus, the pension plan is a defined benefit plan by its nature.
18. Provisions
Onerous Production
lease based
provision taxes
(2) (1) Total
Current provisions $000 $000 $000
----------------------------- ---------- ---------- -------
At 1 January 2017 589 33,921 34,510
Foreign currency translation 28 (1,213) (1,185)
Amount released in the year (31) - (31)
Amount utilised in the year (468) - (468)
Amount provided in the year 86 4,357 4,443
----------------------------- ---------- ---------- -------
At 31 December 2017 204 37,065 37,269
----------------------------- ---------- ---------- -------
1. The provision for production based taxes, is in respect of a claim against PPC for additional rental fee for the period August to December 2010 and January to December 2015. $4.4m was recognised as a charge in the 2017 Consolidated income statement and relates to interest accrued during 2017, out of which $1.1m relates to August to December 2010 liability and $3.3m to January to December 2015. Both claims are being contested in the Ukrainian courts (see Note 27). The amount is denominated in Ukrainian Hryvnia ('UAH') and is stated above at its US$-equivalent amount using the 2017 year end rate of UAH28.07/$ (2016: UAH 27.19/$). The provision at 31 December 2017 includes the total value of the claims plus interest and penalties. The Board believes that the claims are without merit under Ukrainian law and the Company will continue to contest it vigorously. No contingent liabilities exist in respect of Ukrainian production taxes.
2. See Note 19 for details.
Ukraine Russia Hungary Total
Non-current provisions $000 $000 $000 $000
Provision for site restoration
At 1 January 2017 1,543 2,146 575 4,264
Foreign exchange adjustment - (115) 50 (65)
Revision in estimates 900 (84) - 816
Unwinding of discount (Note 22) 131 195 - 326
At 31 December 2017 2,574 2,142 625 5,341
The provision in respect of Ukraine represents the present value of the well and site restoration costs that are expected to be incurred up to 2034 (2016: 2034). The Russia provision results from the decommissioning of 12 wells (2016:12) and removal of plant as required by the license obligation and is due to start from 2049 (2016: 2049). The provisions are made using the Group's internal estimates that management believe form a reasonable basis for the expected future costs of decommissioning.
19. Exceptional items
During the year, the exceptional items as detailed below have been included in administrative expenses in the income statement:
2017 2016
$000 $000
Exceptional item - onerous lease provision
(1) (see Note 18) (55) (594)
Exceptional item - lease costs (2) - (209)
Exceptional item - remuneration and severance
costs (3) (1,364) (3,681)
Exceptional item - legal costs (3) (94) -
(1,513) (4,484)
---------------------------------------------- ------- -------
1. 2017 onerous lease provision concerns the Group's liability for onerous lease contracts relating to its London office. Following a reduction in London office staff in 2016, three out of the four floors of the occupied building became surplus to requirements. Subsequently, two out of three floors have been assigned to new tenants. The provision has been determined as the present value of the unavoidable costs relating to rents and rates to the end of the lease terms, net of the expected sub-lease income, discounted at 6.5% (2016: 6%). The remaining life of the leases at 31 December 2017 was 4 years (2016: 5 years).
2. 2016 lease costs represented rent and rate costs for the 4 months to 31 December 2016 relating to three floors of the London office building.
3. $1.4 million of severance costs paid to two Executive Directors removed from the Board of Directors at the AGM on 30 June 2017 (2016: $2.5 million of severance costs and additional remuneration which the previous Board approved and paid prior to the General Meeting on 28 January 2016. $0.5 million in relation to General Meeting and the replacement of the Board on 28 January 2016. $0.7 million severance costs incurred as a result of staff reductions mainly at the Group's London headquarters);
$0.1 million of professional advisory fees incurred in relation to the removal of two Executive Directors from the Board of Directors.
20. Cost of sales
2017 2016
$000 $000
Operating costs 19,891 19,499
Depreciation, depletion and amortisation 16,756 18,791
Other production based taxes 16,956 17,737
-------------------------------------------------------------------- -------
53,603 56,027
-------------------------------------------------------------------- -------
Exceptional item - production based taxes
(Note 18) 4,357 24,340
Exceptional item - reversal of provision
for impairment of Ukrainian oil and gas
assets (Note 5) (5,636) -
Exceptional item - provision for impairment of Hungary and Slovakia 11,450 2,000
Exceptional item - write off of appraisal expenditure in Ukraine 9,391 -
73,165 82,367
-------------------------------------------------------------------- ------- -------
The cost of inventories (calculated by reference to production costs) expensed in cost of sales in 2017 was $2.0m (2016: $1.1m).
21. Finance income
2017 2016
$000 $000
Interest income on deposits 348 753
Gain on repurchase of Convertible bond - 1,083
--------------------------------------- ------
348 1,836
--------------------------------------- ------
22. Finance costs
2017 2016
$000 $000
------------------------------------------ ------ ------
Borrowing costs 2,838 4,377
Unwinding of discount on site restoration
(Note 18) 326 259
------------------------------------------ ------
3,164 4,636
------------------------------------------ ------
23. Loss from operations - analysis of costs by nature
Loss from operations derives solely from continuing operations and is stated after charging/(crediting) the following:
2017 2016
$000 $000
Depreciation - other assets (Note 5.
(a)) 672 973
Depreciation, depletion and amortisation
- oil and gas assets (Note 5. (a)) 16,756 18,791
Staff costs (net of $0.2m (2016: $0.3m)
capitalised, Note 25) 14,368 17,828
Foreign exchange gain 1,424 431
Operating lease payments
- property lease rentals 817 826
- plant and equipment 2,225 1,797
----------------------------------------- ------
During the year the Group (including its overseas subsidiaries) obtained the following services from the Company's auditors:
2017 2016
$000 $000
Audit of the parent company and consolidated
financial statements 288 276
Fees payable to company's auditors for
other services:
- Audit of the Company's subsidiaries 198 186
- Audit related assurance services 101 109
- Other non-audit services 41 70
--------------------------------------------- ------
628 641
--------------------------------------------- ------
24. Obligations under leases
At the reporting date, the Group's aggregate future minimum commitments under non-cancellable operating leases are as follows:
2017 2016
$000 $000
Within one year 428 442
In the second to fifth years inclusive 932 1,276
1,360 1,718
--------------------------------------- ------ ------
Operating leases primarily relate to rentals payable by the Group for certain of its office premises and staff accommodation.
25. Staff costs
2017 2016
$000 $000
Wages and salaries 14,145 17,226
UK social security costs 300 453
Other pension costs 210 401
Share based payments (equity-settled)
(Note 26) (46) 48
-------------------------------------- ------
14,609 18,128
-------------------------------------- ------
Staff costs are shown gross and $0.2m (2016: $0.3m) was capitalized, representing time spent on exploration and development activities.
During the year, the average monthly number of employees was:
2017 2016
Number Number
Management/operational 448 571
Administration support 79 59
----------------------- -------
527 630
----------------------- -------
There are no Directors on service contracts included within management/operational (2016: 2).
26. Share-based payments
Share options are granted to senior management based on performance criteria. The scheme rules are described in the Directors' Remuneration Report. All share-based payments are equity settled.
According to the Plan that is currently in place, the Remuneration Committee has the ability to grant awards of nil-cost options annually to senior management of the Group, conditional on the Group performance over a period of at least three years.
At 31 December 2017, there were outstanding options under Performance Share Plan (PSP) (2016: under various employee share option schemes), exercisable during the years 2018 to 2026 (2016: 2017 to 2026), to acquire 1,059,650 (2016: 2,168,450) shares of the Company at nil cost per share (2016: share price ranging from nil to GBP59.75p). The vesting period for 1,059,650 (2016: 2,168,450) of the share options is 3 years, with an exercise period of 7 years making a 10 year maximum term.
The following table illustrates the number and weighted average exercise prices ('WAEP') of, and movements in, share options during the year.
2017 2017 2016 2016
Number WAEP Number WAEP
Outstanding as at 1 January 2,168,450 22.78p 12,740,100 28.39p
Granted during the year - - 711,250 0.00p
Lapsed or forfeited during the
year (1,108,800) 44.55p (11,282,900) 27.68p
------------------------------- ----------- ------ ------------ ------
Outstanding at 31 December 1,059,650 0.00p 2,168,450 22.78p
------------------------------- ----------- ------ ------------ ------
Exercisable at 31 December - - - -
------------------------------- ----------- ------ ------------ ------
For the share options outstanding as at 31 December 2017, the weighted average remaining contractual life is 8.0 years (2016: 8.3 years). Weighted average exercise prices ('WAEP') of options outstanding at 31 December 2017is nil (2016:22.78) due to lapse of remaining DSOS awards granted in 2014 during the year, which had an exercise price of 59.75p.
During the year no share options were granted in accordance with the Performance Share Plan ('PSP'), which was introduced in 2010. And no share options were granted in accordance with the Discretionary Share Option Scheme ('DSOS'). This schemes reflect the best practice aspects recommended by the Association of British Insurers following the publication of their guidelines in March 2001 (the 'ABI Guidelines').
From 2015 onwards, grants under DSOS ceased in accordance with our policy.
Lapsed or forfeited Directors share options in 2016
On 28 January 2016, following a General Meeting of the Company, the service contracts of the four Executive Directors were terminated with immediate effect. Prior to the General Meeting, the Board in place at that time approved and made payments of GBP62,772 to forfeit 9,460,000 unexpired share options, which are included in the table above.
Share Option Scheme
-- DSOS
The DSOS is made up of two parts. Options to acquire ordinary shares in the Company granted under Part A are 'Approved Options' and options to acquire Shares granted under Part B of the DSOS are 'Unapproved Options'. No consideration shall be payable for the grant of an Option.
No options were granted under the DSOS in 2017 (2016: nil). For DSOS options to vest there has to be an increase in the Group's Earnings Per Share ('EPS') growth over the performance period measured over the 3 consecutive calendar years commencing from the date the options were granted. The weighted average fair value of options granted during the year under the DSOS was nil per option (2016: nil).
-- PSP
PSP are granted to Executive Directors and senior management. Executive Directors and senior management receive awards under the 2010 Performance Share Plan in the form of nil cost options. No consideration is required to be paid for the grant or exercise of an Option.
No share options were granted under PSP in 2017 (2016: 711,250). The PSP options provide a conditional right to acquire shares at nil cost subject to the satisfaction of the performance conditions and continued employment with the Group. For these options to vest a comparison is performed between the Group's TSR against the FTSE Fledgling index (half the options) (2016: FTSE Fledgling index) and the All-Share Oil & Gas Producers index (other half of options). The weighted average fair value of options granted during 2016 under the PSP was 5.84p per option.
Fair value of share options granted
The fair value of options granted under the PSP in 2016 was estimated as at the date of the grant using a variant of the Monte Carlo model, taking into account the terms and conditions upon which the options were granted, which includes the performance condition related to the TSR directly. No dividends are paid on shares under the scheme prior to exercise.
The total share based payment credit for the year was $0.05m (2016: charge of $0.05m).
The following table lists the inputs to the model used for the options granted in the year ended 31 December 2016. The expected future volatility has been determined by reference to the historical volatility.
2016
PSP
Dividend yield 0.0%
Expected share price volatility 82%
Risk free interest rate 0.6%
Exercise price 0.0p
Expected life of option (years) 3.0
Weighted average share price 19.3p
-------------------------------- -----
Bonus scheme
The full details of the bonus performance criteria for Directors and senior employees and the bonus earned is explained in the Remuneration Report.
27. Taxation
2017 2016
Analysis of tax on loss $000 $000
Current tax
UK - current tax - -
Overseas - current year 2,964 1,341
------------------------ ------------ -------
Current tax total 2,964 1,341
------------------------ ------------ -------
Deferred tax
Overseas - prior year - (1,767)
Overseas - current year (1,348) (612)
------------------------ ------------ -------
Deferred tax total (1,348) (2,379)
------------------------ ------------ -------
Total taxation 1,616 (1,038)
------------------------ ------------ -------
-- Factors that affect the total tax charge
The total tax charge for the year of $1.6m (2016: $1.0m credit) is higher (2016: higher) than the average rate of UK corporation tax of 19.25% (2016: 20%). The differences are explained below:
2017 2016
Total tax reconciliation $000 $000
Loss before tax (16,047) (38,153)
--------------------------------------------- ------------- --------
Tax calculated at 19.25% (2016: 20.00%) (3,089) (7,631)
Other fixed asset differences
Net change in unrecognised losses carried
forward 2,709 3,485
Differences relating to prior years - (1,767)
Permanent foreign exchange differences 913 3,327
Effect of tax rates in foreign jurisdictions 354 271
Rental fee provision (3,280) 3,211
Other non-deductible expenses 2,642 191
De-recognition of prior year losses 1,367 (2,125)
--------------------------------------------- ------------- --------
Total tax charge/(credit) 1,616 (1,038)
--------------------------------------------- ------------- --------
The total tax charge for the year was $1.6m (2016: $1.0m credit) comprising a current tax charge of $3.0m (2016: $1.3m) in respect of Ukraine, a deferred tax charge before exceptional items of $2.7m (2016: credit of $1.2m) and a deferred tax credit of $4.1m in respect of exceptional items (2016: credit of $1.2m). The increase in current tax charge to $3.0m (2016: $1.3m) reflects higher profitability in Ukraine. In Ukraine, the corporate tax rate for 2017 was 18% and remains at this level for 2018. The total deferred tax credit of $1.3m (2016: $2.4m credit) comprises: a $5.4m credit mainly reflecting the recognition of deferred tax assets in respect of Ukrainian Rental fee provision and impairment reversal for Elizavetovskoye field; and a net $4.1m charge (2016: $0.2m) relating to derecognition of deferred tax assets in respect of Hungarian tax losses brought forward and other tax timing differences on our oil and gas assets in Russia and Hungary.
Taxes charged on production of hydrocarbons in Ukraine and Hungary are included in cost of sales (Note 20). The standard rate of corporation tax in the UK changed from 20% to 19% with effect from 1 April 2017. Accordingly, the Company's profits for this accounting year are taxed at an effective rate of 19.25%.
-- Factors that may affect future tax charges
A significant proportion of the Group's income will be generated overseas. Profits made overseas will not be able to be offset by costs elsewhere in the Group. This could lead to a higher than expected tax rate for the Group.
Changes to the UK corporation tax rates were substantively enacted as part of Finance Bill 2015 and Finance Bill 2016. These include reductions to the main rate to reduce the rate to 19% from 1 April 2017 and to 17% from 1 April 2020. The impact of the rate reduction is not expected to have a material impact on UK current taxation.
The corporation tax rate in Ukraine for 2017 was 18% (2016: 18%).
-- Taxation in Ukraine - production taxes
Since Poltava Petroleum Company's ('PPC's') inception in 1994 the Company has operated in a regime where conflicting laws have existed, including in relation to effective taxes on oil and gas production.
In order to avoid any confusion over the level of taxes due, in 1994, PPC entered into a licence agreement with the Ukrainian State Committee on Geology and the Utilisation of Mineral Resources ('the Licence Agreement') which set out expressly in the Licence Agreement that PPC would pay royalties on production at a rate of only 5.5% of sales value for the duration of the Licence Agreement.
Pursuant to the Licence Agreement, PPC was granted an exploration licence and four 20-year production licences, each in respect of a particular field. In 2004, PPC's production licences were renewed and extended until 2024, Subsoil Use Agreements were signed and attached to the licences and operations continued as before.
The Company and PPC have continued to invest in Ukraine on the basis that PPC would pay a royalty on sales at a rate of 5.5%.
In December 1994, a new fee on the production of oil and gas (known as a 'Rental Payment' or 'Rental Fee') was introduced through Ukrainian regulations. On 30 December 1995, JKX, together with its Ukrainian subsidiaries (including PPC), was issued with a Joint Decision of the Ministry of Economy, the Ministry of Finance and the State Committee for the Oil and Gas ('the Exemption Letter'), which established a zero rent payment rate for oil and natural gas produced in Ukraine by PPC for the duration of the Licence Agreement for Exploration and Exploitation of the Fields. Based on the Exemption Letter PPC did not expect to pay any Rental Fees.
-- Rental Fees paid since 2011
In 2011, new laws were enacted which established new mechanisms for the determination of the Rental Fee. Notwithstanding the Exemption Letter, in January 2011 PPC began to pay the Rental Fee in order to avoid further issues with the Ukrainian authorities but without prejudice to its right to challenge the validity of the demands.
Since 2011, the Rental Fees paid by PPC have amounted to more than $180 million. These charges have been recorded in cost of sales in each of the accounting periods to which they relate.
-- International arbitration proceedings
In 2015, the Company and its wholly-owned Ukrainian and Dutch subsidiaries commenced arbitration proceedings against Ukraine under the Energy Charter Treaty, the bilateral investment treaties between Ukraine and the United Kingdom and the Netherlands, respectively. In these proceedings, the Company sought repayment of more than $180 million in Rental Fees that PPC paid on production of oil and gas in Ukraine since 2011, in addition to damages to the business.
During 2015 Rental Fees in Ukraine were increased to 55% and capital control restrictions were introduced. On 14 January 2015, an Emergency Arbitrator issued an Award ordering Ukraine not to collect Rental Fees from PPC in excess of 28% on gas produced by PPC, pending the outcome of the application to a full tribunal for the Interim Award. On 23 July 2015 an international arbitration tribunal issued an Interim Award requiring the Government of Ukraine to limit the collection of Rental Fees on gas produced by PPC to a rate of 28%.
The Interim Award was to remain in effect until final judgement is rendered on the main arbitration case, which was heard in early July 2016. A decision from the tribunal was awarded on 6 February 2017.
The 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.
In March 2017, Ukraine's Ministry of Justice filed a claim with the High Court of the United Kingdom naming JKX as a defendant in an application seeking to set aside the arbitration award for damages against Ukraine and in favour of JKX.
In October 2017 the High Court of the United Kingdom, ordered that the application brought by Ukraine seeking to set aside the recent Uncitral arbitration award against Ukraine and in favour of JKX be dismissed. The Government of Ukraine is therefore still liable to pay to JKX the sum of USD11.8 million plus interest and costs of USD0.3 million in relation to subsidiary claims, as previously ordered. The Judge also ordered that Ukraine should pay JKX's costs of $83,638.
-- Rental Fee demands
The Group currently has two claims (2016: two) for additional Rental Fees being contested through the Ukrainian court process. These arise from disputes over the amount of Rental Fees paid by PPC for certain periods since 2010 (2016: 2010), which in total amount to approximately $37.1 million (2016: $33.9 million) (including interest and penalties), as detailed below. All amounts are being claimed in Ukrainian Hryvnia ('UAH') and are stated below at their US$-equivalent amounts using the year end rate of $1:UAH28.07(2016: $1: UAH 27.2 ).
-- August - December 2010: approximately $11.3 million (2016: $10.6 million) (including $6.8 million (2016: $6.1 million) of interest and penalties). On 11 March 2014 PPC won the case in the Poltava Court. The tax office appealed and the Kharkiv Appellate Administrative Court reversed the earlier decision. PPC then lost an appeal in the High Administrative Court of Ukraine and the Supreme Court rejected PPC's application for the appeal. PPC has discovered that there were in fact certain procedures that were not followed regarding the tax notifications that formed the basis of the original claims against PPC. Certain documentation was found to be missing from the files of the tax authorities. In April 2017 the Poltava Circuit Administrative Court found in favour of PPC and cancelled the tax notification decisions on the grounds that due process had not been followed. On 1 June 2017 the Kharkiv Appellate Administrative Court upheld the judgment of the Poltava Circuit Administrative Court. The tax authorities filed a cassation complaint. On 5 February 2018 the tax authorities' appeal against the decision was dismissed.
-- January - December 2015: approximately $25.8 million (2016: $23.3 million) (including $11.2 million (2016: $10.8 million) of interest and penalties). Following the commencement of international arbitration proceedings at the beginning of 2015 (see above), from July 2015 PPC reverted to paying a 28% Rental Fee for gas production (instead of the revised official rate of 55%) as a result of the awards granted under the arbitration. PPC also declared part of its Rental Fee payments at 55% for the first 6 months of 2015 as overpayments and consequently stopped paying the Rental Fee for gas in order to align the total payments made in 2015 with the 28% rate awarded made under the arbitration proceedings. The Ukrainian tax authorities have issued PPC with claims for the difference between 28% and 55%. PPC is in the process of court hearings in respect of the claim, although the Company considers such claims to be in direct violation of the Interim Award received from the arbitration tribunal, noted above. In addition, in April 2016, the tax authorities issued PPC with a separate demand for $0.1 million of penalties and interest on unpaid Rental Fees for the period of August-October 2015. PPC also filed lawsuits against the tax authorities to cancel the application of such additional penalties and interest.
Following the tribunal's dismissal of the Company's claim for overpayment of Rental Fees, an exceptional charge of $4.4 million has been charged to the Consolidated income statement in the year (2016: $24.3 million) relating to interest accrued on the August - December 2010 and January - December 2015 claims (see Note 18).
No adjustment has been made to recognise any possible future benefit to the Company that may result from the tribunal award in the Company's favour for damages of $11.8 million plus interest, and costs of $0.3 million since the award is still subject to enforcement proceedings in the Ukrainian courts.
In 2015 there was a claim of approximately $6 million (including $3 million of interest and penalties) relating to the period January - March 2007. During 2016 the Supreme Court of Ukraine ruled in favour of the Company in respect of this claim and a second parallel case related to this claim was won by PPC with the High Administration Court of Ukraine. As such no provision is recorded in respect of this claim, and the Group considers the case closed.
28. Deferred tax
Assets Liabilities Net
-------------- ------------------ ----------------
2017 2016 2017 2016 2017 2016
$000 $000 $000 $000 $000 $000
------------------------------ ------ ------ -------- -------- ------- -------
Provided deferred
taxation - Net
Fixed asset differences 5,111 7,696 (14,922) (14,537) (9,811) (6,841)
Other temporary
differences 9,982 5,396 - - 9,982 5,396
Tax losses 5,747 5,632 - - 5,747 5,632
------------------------------ ------ -------- -------
Net deferred tax
asset /(liability)recognized 20,840 18,724 (14,922) (14,537) 5,918 4,187
------------------------------ ------ ------ -------- -------- ------- -------
A net deferred tax asset of $5.9m (2016: $4.2m-asset) arises as a result of PPC's activities $2.8m net liability (2016: $8.2m net liability), Yuzhgazenergie LLC's activities $11.3m net asset (2016: $12.6m net asset) and Riverside Energy kft activities $2.6m net liability (2016: $0.2m net liability).
No deferred tax asset (2016: nil) is recognised in respect of brought forward UK losses. A deferred tax asset of $5.7m (2016: $4.3m-asset) has been recognised in respect of Yuzhgazenergie LLC losses and other differences as sufficient future taxable profits are forecast against which the losses can be utilised. Deferred tax asset of $1.4m (2016: $1.4m) has been derecognised in respect of Riverside Energy kft losses brought forward. No other deferred tax is recognised as the directors do not believe that it would be prudent to do so.
1 January
2017 Exchange differences (Charge)/ credit in the year 31 December 2017
The movement on the deferred tax account in 2017 is as follows: $000 $000 $000 $000
Deferred tax liabilities
Fixed assets differences (6,841) 146 (3,116) (9,811)
---------------------------- ----------------
Deferred tax assets
Other temporary differences 5,396 116 4,470 9,982
Net change in recognised losses carried forward 5,632 121 (6) 5,747
---------------------------- ----------------
11,028 237 4,464 15,729
---------------------------- ----------------
Net deferred tax movement 4,187 383 1,348 5,918
---------------------------- ----------------
1 January
2016 Exchange differences (Charge)/credit in the year 31 December 2016
The movement on the deferred tax account in 2016 is as follows: $000 $000 $000 $000
Deferred tax liabilities
Fixed assets differences (6,097) 496 (1,241) (6,841)
--------- -------------------- --------------------------- ----------------
Deferred tax assets
Other temporary differences 4,559 104 733 5,396
Net change in recognised losses carried forward 2,191 555 2,886 5,632
--------- -------------------- --------------------------- ----------------
6,750 659 3,619 11,028
--------- -------------------- --------------------------- ----------------
Net deferred tax movement 653 1,155 2,379 4,187
--------- -------------------- --------------------------- ----------------
The deferred tax assets in respect of Russian and Ukrainian corporation tax have been recognised with due consideration of the tax rate effective on the expected unwinding of those temporary differences.
2017 2016
Unprovided deferred taxation $000 $000
Tax losses (51,939) (49,458)
Fixed asset differences (3,641) (3,593)
Other temporary differences (27) (51)
----------------------------- --------
(55,607) (53,102)
----------------------------- --------
There is no expiry date on the remaining losses as 31 December 2017. The deductible temporary differences do not expire under current tax legislation. Deferred tax assets have not been recognised in respect of the unprovided deferred taxation items because it is not probable that future taxable profit will be available to utilise these deductible temporary differences. The UK corporation tax main rate will be fixed at 19% for next 2 years and starting from 1 April 2020 - 17%. The impact of the rate reduction is not expected to have a material impact on provided UK deferred taxation but will reduce unprovided UK deferred tax balances in future periods.
In Russia from 2017 till 2020 a restriction has been introduced on the use of brought forward tax losses against future taxable profits. Brought forward tax losses in Russia can only mitigate a maximum of 50% of the taxable profits in those years. This has had the impact of reducing the recognised deferred tax asset on prior year tax losses incurred in Russia. From 2021 it is expected that all brought forward Russian tax losses can be utilised to mitigate all taxable profits. The 10 year limitation on the use of carried forward tax losses in Russia has been cancelled.
29. Loss per share
The calculation of the basic and diluted loss per share attributable to the owners of the parent is based on the weighted average number of shares in issue during the year of 172,125,916 (2016: 172,125,916) and the loss for the relevant year.
Loss before exceptional items in 2017 of $701,204 (2016 loss: $7,461,522) is calculated from the 2017 loss of $17,662,920 (2016: $37,115,477) and adding back exceptional items of $21,074,348 (2016: $30,823,955) less the related deferred tax on the exceptional items of $4,112,632 (2016: $1,170,000).
The diluted earnings per share for the year is based on 172,125,916 (2016: 172,125,916) ordinary shares calculated as follows:
2017 2016
$000 $000
Loss
Loss for the purpose of basic and diluted
earnings per share (loss for the year
attributable to the owners of the parent):
Before exceptional item (701) (7,462)
After exceptional item (17,663) (37,115)
-------------------------------------------- --------
Number of shares 2017 2016
Basic weighted average number of shares 172,125,916 172,125,916
Dilutive potential ordinary shares:
Share options - -
---------------------------------------- ------------
Weighted average number of shares for
diluted earnings per share 172,125,916 172,125,916
---------------------------------------- ------------
In accordance with IAS 33 (Earnings per share) the effects of antidilutive potential have not been included when calculating dilutive loss per share for the year end 31 December 2017 (2016: nil). 13,791,259 (2016: 13,925,410) potentially dilutive ordinary shares associated with the convertible bonds (Note 13) have been excluded as they are antidilutive in 2017, however they could be dilutive in future periods.
There were 1,059,650 (2016: 2,168,450) outstanding share options at 31 December 2017, of which none (2016: 1,341,750) had a potentially dilutive effect. All of the Group's equity derivatives were anti-dilutive for the year ended 31 December 2017.
30. Dividends
No interim dividend was paid for 2017 (2016: nil). In respect of the full year 2017, the directors do not propose a final dividend (2016: no final dividend paid).
31. Reconciliation of loss from operations to net cash inflow from operations
2017 2016
$000 $000
Loss from operations (13,228) (34,754)
Depreciation, depletion and amortisation 17,428 19,764
Loss on disposal of fixed assets 557 311
Exceptional item - reversal of provision
for impairment of Ukrainian oil and gas
assets (5,636) -
Exceptional item - provision for impairment
of Hungary and Slovakia 11,450 2,000
Exceptional item - write off of appraisal
expenditure in Ukraine 9,391 -
Exceptional item - increase in provision
for production based taxes 3,144 24,340
Increase in provisions - onerous lease
provision 83 594
Share-based payment (credit)/charge (46) 48
-------------------------------------------- ---------
Cash (used in)/generated from operations
before changes in working capital 23,143 12,303
(Increase)/decrease in operating trade
and other receivables (1,179) 8,119
Decrease in operating trade and other
payables (4,897) (2,102)
Increase in inventories (1,344) (1,282)
-------------------------------------------- ---------
Cash generated from operations 15,723 17,038
-------------------------------------------- ---------
32. Capital commitments
Under the work programmes for the Group's exploration and development licenses the Group had no commitments to future capital expenditure on drilling rigs and facilities at 31 December 2017 (2016: $3.3m).
33. Related party transactions
The transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation.
Key management personnel are considered to comprise only the Directors. The remuneration of Directors during the year was as follows:
2017 2016
$000 $000
Short-term employee benefits 2,579 5,164
Post-employment benefits 43 62
Share-based payments (credit)/charge (46) 81
------------------------------------- ------
2,576 5,307
------------------------------------- ------
The number of board executives for 2017 was 5 to the 30th June. Then July to October only 3 board executives remained. Therefore board costs were reduced for this period. Also, no bonus was awarded to the Board for 2017.
Share-based payments represents the expenses arising from share-based payments included in the income statement, determined based on the fair value of the related awards at the date of grant (Note 26).
Vladimir Tatarchuk and Vladimir Rusinov were appointed to the Board on 28 January 2016 and were thought to have a beneficial interest in Convertible Bonds with principal amount of $3.4m at 31 December 2017 (2016: $3.4m), which are held by Proxima. In February 2017, in accordance with the terms and conditions of the restructured Bonds, redemptions of Proxima's bonds of $0.4m were made in respect of prior accretion amounts (2016: $1.5m under the Bondholder Put Option) (see Note 12 and 13) and Bond interest payments of $0.4m (31 December 2016: $0.3m) were made to Proxima in relation to their Bond holding.
Since the Annual General Meeting on 30 June 2017 Vladimir Rusinov was removed from the Board of Directors. On 11 December 2017 he was reappointed to the Board.
-- Subsidiary undertakings and joint operations
The Company's principal subsidiary undertakings including the name, country of incorporation, registered address and proportion of ownership interest for each are disclosed in Note B to the Company's separate financial statements which follow these consolidated financial statements.
Transactions between subsidiaries and between the Company and its subsidiaries are eliminated on consolidation.
34. Audit exemptions for subsidiary companies
The Group has elected to take advantage of the full extent of the exemptions available under Section 479A of the Companies Act 2006. As a result, statutory financial statements will not be audited for the following UK entities: JKX Services Limited, JKX Bulgaria Limited, JKX Georgia Ltd, JKX (Ukraine) Ltd, Baltic Energy Trading Ltd, EuroDril Limited, JP Kenny Exploration & Production Limited, Page Gas Ltd, Trans-European Energy Services Limited, JKX Limited.
35. Events after the reporting date
In early February 2018 the Board decided to withdraw from Slovakia. On 16 March 2018 the Company gave formal notice of relinquishment of Svidnik, Medzilaborce and Snina exploration licences to the other parties in the joint venture.
Glossary
2P reserves Proved plus probable 3P reserves Proved, probable and possible P50 Reserves and/or resources estimates that
have a 50 per cent probability of being met or exceeded
AFE Authorisation For Expenditure AIFR All Injury Frequency Rate Bcf Billion cubic feet Bcm Billion cubic metres bcpd Barrel of condensate per day boe Barrel of oil equivalent boepd Barrel of oil equivalent per day bopd Barrel of oil per day bpd Barrel per day bwpd Barrels of water per day cfpd Cubic feet per day EPF Early Production Facility FEN Folyópart Energia Kft GPF Gas Processing Facility HHN HHE North Kft Hryvnia The lawful currency of Ukraine HSECQ Health, Safety, Environment, Community and Quality HTHP High Temperature High Pressure KPI Key Performance Indicator LIBOR London InterBank Offered Rate LPG Liquefied Petroleum Gas LTI Lost Time Injuries Mbbl Thousand barrels Mboe Thousand barrels of oil equivalent Mcf Thousand cubic feet Mcm Thousand cubic metres MMcfd Million cubic feet per day MMbbl Million barrels MMboe Million barrels of oil equivalent PPC Poltava Petroleum Company Roubles The lawful currency of Russia RR Russian Roubles sq. km Square kilometre TD Total depth $ United States Dollars UAH Ukranian Hryvnia US United States VAT Value Added Tax YGE Yuzhgazenergie LLC
Conversion factors 6,000 standard cubic feet
of gas = 1 boe
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR BDGDXDBDBGIC
(END) Dow Jones Newswires
March 29, 2018 08:24 ET (12:24 GMT)
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