TIDMJKX
RNS Number : 4443J
JKX Oil & Gas PLC
29 March 2018
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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