TIDMGKP
RNS Number : 2525U
Gulf Keystone Petroleum Ltd.
28 March 2019
28 March 2019
Gulf Keystone Petroleum Ltd. (LSE: GKP)
("Gulf Keystone", "GKP", "the Group" or "the Company")
2018 Full Year Results Announcement
Record profit after tax and declaration of first dividend on
strong financial performance
On track for 55,000 bopd in Q1 2020 as next milestone in phased
production uplift
Gulf Keystone Petroleum, a leading independent operator and
producer in the Kurdistan Region of Iraq ("Kurdistan" or "Kurdistan
Region") announces its results for the full year ended 31 December
2018.
Highlights to 31 December 2018 and post reporting period
Financial
-- Record revenue of $250.6 million (FY 2017: $172.4 million)
-- EBITDA of $149.3 million (FY 2017: $104.3 million)
-- Profit after tax of $79.9 million (FY 2017: $14.1 million)
-- Net capital investment in Shaikan of $35.7 million (FY 2017: $8.1 million)
-- Cash balance of $295.6 million at year end (2017: $160.5 million)
-- The Company anticipates being fully funded for all phases of the Shaikan expansion
programme under its current set of assumptions
-- $100 million bond refinancing in July 2018
Dividend
-- The Board confirms a dividend policy to shareholders, which
will comprise an annual dividend on the ordinary shares of the
Company of no less than $25 million per financial year
-- The Company is therefore pleased to announce its intention to
pay an ordinary dividend on the ordinary shares of $25 million in
2019 and, given its current financial strength, the Board is also
proposing to complement the ordinary dividend in 2019 with a $25
million supplemental dividend to shareholders on the ordinary
shares
-- The total dividend of $50 million will be subject to approval
at the next AGM in June 2019. One third of the total dividend will
be paid following approval at the Company's AGM, with the balance
payable following release of the Company's half-year results
Operational
-- Full year gross average production of 31,563 bopd (2017:
35,298), at the upper end of guidance
-- GKP and its partner MOL reached agreement with the MNR in
June 2018 to recommence investment into Shaikan, towards an initial
production target of 55,000 bopd by Q1 2020
-- Common vision for a phased development that will grow gross
Shaikan production to 110,000 bopd
-- The development vision described by the revised Field
Development Plan ("FDP") was submitted in October 2018. This
revision has not been accepted by the MNR, specifically due to a
request for additional assurances on the timing and commitment to
eliminate gas flaring. As the parties aim to progress this matter
and reach an agreement, investment on the ground continues as per
the initial phases of this plan
-- On target to achieve plant de-bottlenecking by year-end and
tie-in of the pipeline from PF-1 to the export system mid-year
-- GKP internal review indicates an upgrade in Proven (1P)
reserves and no material changes to Probable reserves (2P). A
revised Competent Person's Report to be released following FDP
approval
-- Robust HSSE performance with one LTI in 2018, the first in three years
Corporate
-- Signature of Crude Oil Sales Agreement in January 2018
normalised payments in line with oil prices and production. Renewed
in February 2019 through to 2020 providing certainty over payments
for the foreseeable future
-- Further strengthening of the Board in 2018 with Jaap Huijskes
appointed as Non-Executive Chairman, Martin Angle as Senior
Independent Non-Executive Director and Kimberley Wood as
Non-Executive Director
Outlook
-- On track for material uplift in production to 55,000 bopd in Q1 2020
-- In 2019, gross Capex associated with 55,000 bopd phase of
between $130 million and $150 million, in addition to $20 million
to $45 million associated with the subsequent development phase
-- Dividend distribution from 2019 onwards
-- Gross production guidance for 2019 unchanged at 32,000 - 38,000 bopd
Jón Ferrier, Gulf Keystone's Chief Executive Officer, said:
"Throughout 2018, our focus was on laying the foundations for
the delivery of the Company's phased growth plans, which envisages
a step change in production profile. The Company is on track to
achieve its near-term production target of 55,000 bopd in Q1 2020,
and with our partner MOL continues to work towards delivering the
staged investment programme. The remarkable Shaikan reservoir
presents a straightforward, low-cost onshore development
opportunity with unrivalled near-term upside.
The new dividend policy represents another major milestone for
the Company. It crystallises returns to shareholders while we
preserve the ability to fully fund the Shaikan development and
maintain a strong balance sheet; our platform for growth."
Capital Markets Event
Gulf Keystone will host a Capital Markets Event for analysts and
institutional investors. This will be webcast live today at 10am on
the Company's website www.gulfkeystone.com
Enquiries:
Celicourt Communications: +44(0) 20 7520 9266
Mark Antelme
Jimmy Lea
or visit: www.gulfkeystone.com
The information communicated in this announcement is inside
information for the purposes of Article 7 of Regulation
596/2014.
Disclaimer
This announcement contains certain forward-looking statements
that are subject to the risks and uncertainties associated with the
oil & gas exploration and production business. These statements
are made by the Company and its Directors in good faith based on
the information available to them up to the time of their approval
of this announcement but such statements should be treated with
caution due to inherent risks and uncertainties, including both
economic and business factors and/or factors beyond the Company's
control or within the Company's control where, for example, the
Company decides on a change of plan or strategy. This announcement
has been prepared solely to provide additional information to
shareholders to assess the Group's strategies and the potential for
those strategies to succeed. This announcement should not be relied
on by any other party or for any other purpose.
CHAIRMAN'S STATEMENT
I am pleased to report that 2018 was a pivotal year for Gulf
Keystone when following an extensive period of negotiations, the
Company recommenced investment into the Shaikan oil field. This
could not have happened without the diligent work of the Company
and the continued support from the Kurdistan Regional Government
("KRG") and the Ministry of Natural Resources of the KRG ("MNR").
Following our agreement with the KRG and our partner MOL Hungarian
Oil & Gas plc ("MOL"), Gulf Keystone will ramp up gross
production capacity to 55,000 barrels of oil per day ("bopd") at
Shaikan, which we expect to achieve in Q1 2020.
As with other oil and gas companies across the globe, the strong
oil price in 2018 was a favourable macro factor for Gulf Keystone.
Whilst prices eased towards the end of the period, the increase in
value from a low of $55 a barrel for Brent crude in Q4 2017 to a
high of $86 a barrel in 2018 meant the Company was able to announce
a record profit after tax for the year of $79.9 million. The
combination of stable production and exports, regular payments from
the KRG since September 2015 and a new bond, secured in July 2018,
has enabled Gulf Keystone to build a robust balance sheet, leaving
the Company well financed for the future development of
Shaikan.
Kurdistan remained largely stable during the reporting period
and we were able to significantly advance our development plans for
Shaikan whilst enjoying safe and secure operating conditions. The
revised Field Development Plan ("FDP") submitted to the MNR in
October 2018, has not been accepted. However, both GKP and MOL are
aligned on a vision for the development of Shaikan and continue to
make considerable operational headway with the necessary
construction and drilling works that will enable the Company to
meet its production target of 55,000 bopd in Q1 2020 - an important
milestone on the way to full development of the field.
Strong corporate governance continued to be a priority for the
Company, with the composition of the Board changing considerably
during the year. After many years of distinguished service, Philip
Dimmock stood down as Senior Independent Director in July 2018 and
was replaced by Martin Angle, who brings substantial financial,
commercial and boardroom experience to the Company. Kimberley Wood
also joined the Board in 2018, as a Non-Executive Director.
Kimberley adds significant legal expertise to the Board with over
18 years in the oil and gas sector, advising a wide range of oil
and gas companies during this time. In line with industry best
practice we remain committed to maintaining a strong, independent
Board. We also continue to strive to achieve greater diversity
throughout all levels of the business and see the further
development of our extensive local employee workforce as being
pivotal to the success of the Company.
Following a period of significant commercial and operational
achievements in Kurdistan, the Board has decided to establish a
dividend policy to ordinary shareholders, which comprises an annual
dividend on the ordinary shares of the Company of no less than a
total of $25 million per financial year, payable semi-annually and
split between an interim and final payment (1/3:2/3).
The Company is therefore pleased to announce its intention to
pay an ongoing ordinary dividend on the ordinary shares of $25
million in 2019 and, given its current financial strength, the
Board is also proposing to complement this ordinary dividend in
2019 by a $25 million supplemental dividend to shareholders on the
ordinary shares. The total dividend of $50 million for 2019 will be
subject to approval at the next AGM in June 2019. It is the Board's
current intention that one third of the total dividend will be paid
following approval at the Company's AGM, with the balance payable
following release of the Company's half-year results on dates to be
determined in due course.
In future periods of strong cash flow generation, the Board will
also look to complement the annual ordinary dividend with further
supplemental dividends to shareholders while preserving its ability
to grow the business.
When setting the appropriate ordinary, and any supplemental,
dividend levels in future periods, the Board of Directors will look
at a range of factors including; inter alia, the macro environment
including the oil price, the commercial environment, the balance
sheet of the Company, and all current and future investment plans.
The payment of any dividend will be subject at all times to
appropriate Board and shareholder approvals and compliance with
Bermuda law.
I have relished my first year as Chairman of Gulf Keystone and
believe the Company has made considerable positive progress during
2018. I would like to thank our shareholders for their continued
support during what has been a busy time for the business. On a
final note, I would like to express my gratitude to all of the
Company's employees, whose hard work and dedication over the last
year has enabled the business to recommence investment into
Shaikan, which has the potential to deliver significant value to
all stakeholders for the foreseeable future.
EXECUTIVE REVIEW
Throughout 2018, our focus was on laying the foundations for the
delivery of the Company's phased growth plans, which entail an
unrivalled step change in production profile. In this regard, 2018
was another successful year for Gulf Keystone. The Company is on
track to achieve its near-term production target of 55,000 bopd in
Q1 2020, and with our partner MOL, continues to work towards
delivering the staged investment programme, which is expected to
lead ultimately to a gross production of up to 110,000 bopd.
We are pleased to report that the Shaikan Field maintained its
track record of consistent performance, allowing the Company to
announce full year gross average production of 31,563 bopd, at the
upper end of the guidance range of 27,000 - 32,000 bopd. There have
been no signs of water or gas breakthrough and quality of the crude
produced at Shaikan has remained consistent.
2018 began favourably with the Company announcing its first
Crude Oil Sales Agreement, ensuring that payments were normalised
in line with oil prices and actual production from Shaikan.
Importantly, this paved the way for the Company to once again
invest in Shaikan. In February 2019, the Company renewed the Crude
Oil Sales Agreement through to 2020, giving Gulf Keystone greater
certainty over oil sales payments for the foreseeable future.
After a detailed planning phase, GKP began an extensive work
programme in the second half of 2018, which is now fully underway.
GKP has gone to considerable lengths to mitigate risks where it can
with its Shaikan expansion plans. Given the project is onshore and
the reservoir is well understood, the Company believes that the
project carries relatively low execution risk.
The development vision of the Shaikan Field is described by the
revised FDP which was submitted in October 2018. This revision was
not accepted by the MNR, in particular due to a request for
additional assurances on the timing and commitment to eliminate gas
flaring - the single most complex and expensive component of the
field's development. We are hopeful that GKP along with MOL will
reach an agreement with the MNR for the benefit of all parties. As
the parties progress this matter, investment on the ground
continues as per the initial phases of the plan.
The Company is in a robust financial position, and a disciplined
approach to capital management remains central to everything we do.
In 2018, the Company continued to receive regular oil payments from
the KRG, with cash receipts in the year totalling $225 million net
to GKP. At the time of this report, the cash balance stands at $296
million. It is also important to stress that the Company has
immaterial outstanding revenue arrears. Under our current market
assumptions and predicted field performance, the Company is now
fully funded for all phases of the Shaikan expansion programme, up
to 110,000 bopd. The gross capital expenditure guidance for the
55,000 bopd phase of the uplift in production remains unchanged
between $200 million to $230 million gross. With imminent growth in
production, the Company expects to accelerate recovery of the
ca.$500 million outstanding petroleum cost pool (gross). As a
result of this robust financial position, the Board was pleased to
confirm a dividend policy effective this year, subject to approval
by the shareholders at the next AGM.
The Company has spoken in the past of discussions with the MNR
and MOL which could potentially lead to an amendment to the
existing Shaikan Production Sharing Contract ("PSC") where the MNR
is seeking a carried interest that is common in many other PSCs in
the Kurdistan Region of Iraq. Should a new PSC amendment be
concluded, the Company is confident that the revised fiscal terms
are expected to be at least value neutral to GKP. This matter has
no reason to impede development progress, investment and increasing
production from Shaikan, as evidenced by our considerable activity
in 2018 which continues apace in 2019.
The Company has received final clearance from Sonatrach in
relation to the Ferkane Permit (Block 126). This officially marks
Gulf Keystone's exit from its Algerian operations. This positive
development has allowed the Company to release $10 million of past
liabilities, with no further costs to be incurred.
Ensuring the safety of our people remains our number one
priority and we are pleased to have maintained a strong track HSSE
record throughout 2018. As the operational tempo increases, so do
risks in the workplace; there can be no complacency with our HSSE
performance.
2019 is set to be another significant year for the Company as we
continue to create value for all of our stakeholders, in particular
our shareholders and the Kurdistan Region of Iraq.
Key Financial Highlights
Year Ended Year Ended
------------------------------------------
31 December 31 December
2018 2017
$'000 $'000
------------------------------------------ ------------ ------------
Gross average production (bopd) 31,563 35,298
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Realised price ($/bbl) 49.0 34.6
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Revenue 250.6 172.4
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Operating costs ($m)(1) (30.7) (28.8)
------------------------------------------ ------------ ------------
Operating costs per bbl ($/bbl)(1) (3.2) (2.7)
------------------------------------------ ------------ ------------
General and administrative expenses ($m) (17.8) (21.3)
------------------------------------------ ------------ ------------
Profit from operations ($m) 78.2 24.1
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Profit after tax ($m) 79.9 14.1
------------------------------------------ ------------ ------------
Basic earnings per share (cents) 34.84 6.16
------------------------------------------ ------------ ------------
EBITDA ($m)(1) 149.3 104.3
------------------------------------------ ------------ ------------
Capital investment ($m) (1) 35.7 8.1
------------------------------------------ ------------ ------------
Net cash ($m) (1) 191.2 58.5
------------------------------------------ ------------ ------------
Net increase in cash ($m) 135.2 67.0
------------------------------------------ ------------ ------------
Revenue receipts ($m) 224.7 132.0
------------------------------------------ ------------ ------------
(1) Operating costs, operating costs per barrel, EBITDA, capital
investment and net cash are either non-financial or non-IFRS
measures and are explained in the summary of significant accounting
policies.
Revenues
The Group has delivered a year of strong financial results. 2018
revenue stands at $250.6 million (2017: $172.4 million), the
highest recorded level since the Group started selling its Shaikan
crude oil. This is the result of a higher Brent price and the
signing of a Crude Oil Sales agreement in January 2018 which
allowed the Group to receive revenues based on its entitlement
rather than the capped amount of $12 million (net) received for the
first nine months of 2017. Revenue recognised includes $16.2
million MNR liability offset (2017: $14.9 million).
The Group continues to recognise revenues on a cash receipt
assured basis, leaving past revenue arrears off balance sheet. The
Group's current assessment is that the possible range of revenue
arrears is not material.
Operating costs, depreciation, other cost of sales and
administrative expenses
The Group's operating costs increased to $30.7 million (2017:
$28.8 million) as the Group undertook certain one-off maintenance
projects during the year and started incurring costs associated
with the preparation for the future production ramp up, mostly in
relation to hiring additional resource.
Other cost of sales components include depletion and
amortisation of oil and gas assets, capacity building charge,
production bonuses, and certain other cost of sales such as the
cost of trucking oil to Fishkhabour and oil inventory movements.
Cost of sales increased to $154.5 million (2017: 127.0 million),
which was mostly driven by the production bonus of $16.0 million
(2017: $nil) and transportation costs of $14.3 million (2017: $2.4
million). With the completion of the export pipeline from PF-1 to
the main export pipeline expected to become operational mid-year,
trucking costs will be eliminated.
General and administrative expenses ("G&A") have come down
from $21.3 million in 2017 to $17.8 million in 2018, with the
Kurdistan office contributing $7.8 million (2017: $5.4 million) of
this amount. The reduction in G&A is the result of prudent
resource management which is a core part of the corporate culture
and an important element of the Group's KPIs. The G&A amount
includes $1.8 million of share-based payments (2017: $2.7 million)
and $0.4 million (2017: $0.4 million) of depreciation costs.
The movement in these three components has allowed the Group to
record an EBITDA of $149.3 million a 43% increase in comparison to
the previous year (2017: $104.3 million).
Net finance costs and other gains
The Group incurred net finance costs of $9.4 million (2017:
$10.3 million). This includes $2.9 million of accelerated
amortisation of the refinanced Notes' issue costs (2017: $nil).
The Company has received final clearance from Sonatrach in
relation to the Ferkane Permit (Block 126). This officially marks
Gulf Keystone's exit from its Algerian operations. This resulted in
a $10.2m release of past liabilities recognised in other gains.
A solid financial foundation underpinning the Group's
strategy
Strong free cash flow generation
In 2018, the Group received revenue payments of $224.7 million
(2017: $132.0 million). This, combined with strong capital
discipline and low-cost operations, allowed us to generate a net
cash increase of $135.2 million (2017: $67.0 million).
The cash balance at the end of 2018 stood at $295.6 million
(2017: $160.5 million), serving as a solid base for the Shaikan
investment programme.
In July 2018, the Group redeemed the $100 million Reinstated
Notes due in 2021 at a price equal to 100% of the principal, plus
accrued and unpaid interest. The Group also successfully completed
the private placement of a 5-year senior unsecured $100 million
bond issue (the "New Notes") carrying a 10% fixed semi-annual
coupon. The bond placement was oversubscribed receiving strong
investor demand, both from existing and new investors across
international markets. The New Notes give the Group the flexibility
to raise up to $200m of additional borrowing.
Capital investment
In 2018, capital investment in Shaikan amounted to $35.7million.
This investment covered the work on the export pipeline from the
production facilities to the main export pipeline, the SH-1
workover, work in preparation to the upcoming drilling campaign,
production facilities improvement, various studies and reservoir
engineering.
Capital investment in Shaikan will continue this year with the
Group's work programme aimed at achieving the near-term production
target of 55,000 bopd. In 2019, the gross capital expenditure
associated with this project is expected to total $130-150 million.
In addition, the Company has initiated certain workstreams in
relation to the subsequent phase of the development which includes
expansion to 75,000 bopd and the gas re-injection project, although
the investment decision has not been finalised. In 2019, the gross
capital expenditure associated with this workstream, which includes
installation of additional electrical submersible pumps, certain
long lead items, well pads civil works and engineering and design
work on the gas re-injection project, is expected to be in the
range of $20-45 million, depending on the timing of the project
investment decision and achievement of key milestones.
OPERATIONAL REVIEW
2018 was a year of operational delivery from the Shaikan Field,
with the Company focused on laying the foundations to increase
gross production from the field to 55,000 bopd and beyond.
The Company delivered strong operational performance in 2018,
following a similarly good year in 2017.
Gulf Keystone attained gross average production of 31,563 bopd
during the period, at the upper end of our 27,000 - 32,000 bopd
guidance for the year. The production figures were achieved by
maintaining safe and reliable operations underpinned by predictable
performance from the Shaikan Jurassic reservoir, which continues to
produce in line with expectations. Plant uptime remained very high
throughout the year at 99%.
The year marked the beginning of direct pipeline exports from
Shaikan with the commissioning in July of the spur line from PF-2
to the Kurdish export pipeline. During 2018, the reduction in
trucking operations to Fishkhabour a reduced the risk of road
traffic accidents, and today, following the installation of
temporary unloading facilities at PF-2, only ca.3,000 bopd are
exported by trucks via Fishkhabour. Trucking will be eliminated in
the summer 2019 when the tie-in from PF-1 to the main export line
is finalised.
The Company continues to focus on cost discipline at Shaikan.
Operating costs have increased in comparison to 2017, due to
various maintenance projects undertaken during the year and other
investments in preparation for the increase in production. This,
together with the lower average production for the year, has
resulted in an increase in Opex per barrel from $2.7/bbl in 2017 to
$3.2/bbl in 2018.
Over the last year, the Company has conducted an internal
in-depth assessment of reserves. This used as a foundation: new
petrophysical and geological interpretations, a comprehensive
fracture network modelling study, updated well and facilities
performance data, production history to the end of 2018 and dynamic
reservoir simulation modelling incorporating all of these data. On
this basis, GKP's internal review of reserves indicates an upgrade
in Proven (1P) reserves and no material changes to Probable
reserves (2P) compared to previous work. The lack of any
significant change in the mid-case is reassuring, but more
importantly the increase in 1P reserves is indicative of the
reduced uncertainty and risk as production and reservoir
performance becomes better understood.
However, GKP continues to report reserves based on the 2016 ERCE
Competent Person's Report ("CPR"), the last audited assessment of
reserves. Using the gross 1P and 2P reserves of Shaikan are
estimated at 207 MMstb ("Million Stock Tank Barrels") and 591 MMstb
respectively at the end of 2018, accounting for production in 2017
and 2018. A revised CPR is expected to be released following FDP
approval.
At the end of 2018, Gulf Keystone had produced over 56 MMstb
from Shaikan, representing 9% of Shaikan's Gross 2P reserves. This
knowledge proved instrumental when designing the phased investment
programme at Shaikan and gives the Company comfort when setting out
its future investment plans for the field.
Next stage of growth - 55,000 bopd project in the next 12
months
In June 2018, Gulf Keystone with its partner MOL, reached
agreement with the MNR to recommence investment into Shaikan; a
landmark event for the business. Since this time, a number of
workstreams have commenced which will enable the Company to reach
the target of 55,000 bopd in Q1 2020. The target of the investment
in this phase is the continued exploitation of the high quality
Jurassic reservoir, which benefits from an unusually high oil
column of up to 950 metres and an east-west closure mapped of ca.25
kilometres. The scale of the reservoir affords several infill well
locations.
The Company signed an agreement with Independent Oil Tools
("IOT") to use 'Rig 1' for its planned workover programme. The rig
has now successfully completed a workover on the SH-1 well,
resulting in an increase in production from the well by ca.90%, to
over 7,000 bopd. The IOT rig used will complete a workover for
another operator in the region before returning to Shaikan for the
remaining workovers in the 55,000 bopd expansion programme. This
will include the SH-3 tubing change-out along with installation of
Electric Submersible Pumps ("ESPs") in wells SH-5, SH-10 and
SH-11.
A drilling campaign using 'Rig 40' (owned by DQE) is planned to
commence shortly, with the first four wells (needed for the 55,000
bopd target) expected to be completed in Q1 2020. The four wells
will target infill locations between existing wells to exploit the
Jurassic Sargelu, Alan, Mus and Butmah formations, the source of
all Shaikan production to date. Well pad construction for the first
two wells of the campaign is complete.
Progress with the debottlenecking work at PF-1 and PF-2, remains
on track for completion late 2019. After incurring minor
operational delays, largely from the late delivery of drilling and
well completion equipment, the 55,000 bopd production target is now
expected in Q1 2020. The Company has made significant progress
since construction commenced and remains on track to achieve this
milestone. Gulf Keystone expects gross capital expenditure for the
55,000 bopd development phase to remain unchanged in the range of
$200 million to $230 million, including a 25% contingency.
Gross production this year up to 26 March 2019 averaged 27,845
bopd; somewhat lower than the forecast range due to an unplanned
export pipeline shutdown and the SH-1 workover. Nevertheless,
average gross production guidance for 2019 remains in the range of
32,000 - 38,000 bopd as previously communicated.
Staged production growth over next five years
Looking beyond the 55,000 bopd project initiated in June 2018,
Gulf Keystone and its partner MOL have formulated a phased
investment programme, which envisages gross field production
increase in stages to 75,000 bopd, then up to 85,000 bopd
(collectively "Phase 1"), and eventually 110,000 bopd ("Phase 2")
once the Triassic reservoir is fully on-stream. Compared to the
previous development plan, this revised plan has been de-risked and
optimised on phasing, timeline and expenditures. A revised Field
Development Plan reflecting the strategy was submitted to the MNR
in Q4 2018. This revision has not been accepted by the MNR,
specifically due to a request for additional assurances on the
timing and commitment to eliminate gas flaring. As the parties aim
to progress this matter and reach an agreement for the benefit of
all parties, investment on the ground continues as per the initial
phases of this plan.
Whilst the FDP has not been accepted, the Company has commenced
with various workstreams (including planning and procurement of
certain long lead items) to prepare for the increase in output to
75,000 bopd. This project includes a new train plus utilities to be
constructed at PF-1 and PF-2, which would increase total processing
capacity at the field to 75,000 bopd. The expansion beyond 55,000
bopd to 75,000 bopd includes a gas re-injection facility which is
expected to eliminate flaring, help maintain reservoir pressure,
mitigate HSSE risks and lay the foundation for the development of
the Triassic reservoir by enabling the handling of the higher
gas-oil ratio expected from lighter Triassic oil. Gulf Keystone
currently estimates the gross costs associated with the gas
re-injection project, and the step up to 75,000 bopd, to be in the
range of $400 million and $450 million, including a 25%
contingency, but this remains subject to a final review and
sanction. The gross Capex of the expansion to 75,000 bopd is
estimated between $150 million and $175 million with an estimated
project duration of 18 to 24 months, while the Capex for the gas
re-injection is estimated between $225 million and $300 million
with an estimated project duration of 24 to 30 months.
The 85,000 bopd phase requires production from Shaikan's
Triassic reservoir, which is yet to be exploited. Installation of
oil processing facilities at a new site, adjacent to the Jurassic
gas reinjection facility and the drilling of two new Triassic
production wells, plus a possible third contingent well, would also
need to be carried out to achieve the initial phase of production
of ca.10,000 bopd from the Triassic. In this initial, or pilot
phase, the Company plans to use dynamic data from the first six to
twelve months of production to better understand the reservoir's
behaviour. Once this has been quantified, a final investment
decision on the planned expansion work will be made. Further
details on the costs of this Triassic pilot phase will be disclosed
in due course, but initial estimates suggest gross Capex for this
stage in the region of $135 million to $165 million, including a
25% contingency, over a duration between 18 to 24 months.
It is currently envisaged that a final investment decision on
Phase 2 (which includes expansion of the Triassic and a Cretaceous
pilot) will be made before moving ahead with the ordering of
compression and facility equipment in addition to the drilling of a
further five wells required to increase output at Shaikan to the
110,000 bopd target level. The timing of Shaikan's Phase 2
development decision will be dependent on the outcome of the Phase
1 project. Further details on the costs of the subsequent 110,000
bopd phase will be disclosed in due course, but initial estimates
suggest gross Capex for these stages in the region of $450 million
to $550 million, including a 25% contingency, over a duration
between 24 to 30 months.
The Company has been thorough in designing this staged
investment scheme and believes that the blueprint laid out
represents prudent reservoir management and is in the best
interests of all stakeholders. Realising the full potential from
Shaikan and maximising its value for shareholders, remains a
priority for the Company and we believe our approach to be the
optimal method of achieving this.
HSSE & CSR
Gulf Keystone strives to be at the forefront of HSSE performance
in Kurdistan and monitors and continually improves its safety
practices accordingly. HSSE performance was robust during the
period with one Lost Time Incident ("LTI") recorded, the first for
three years.
Connecting PF-2 to the export pipeline in July 2018
significantly reduced the need to truck crude and the installation
of a temporary unloading facility at PF-2 has allowed PF-1 trucks
to materially reduce the distance they need to travel and has
resulted in decreased HSSE exposure. The connection of PF-1 to the
main export pipeline in mid-2019 is expected to eliminate the need
for trucking at Shaikan entirely.
Gulf Keystone remains committed to having a high proportion of
the Company's workforce made up of local personnel. During 2018
ca.80% of in-country staff were local employees, 35% of which live
in the nearby villages surrounding Shaikan. Last year, a total of
25 promotions for local personnel took place; awarded on the basis
of successful development and performance. A number of companies
from the Shaikan area have been successful in our tendering
processes and this, as well as providing excellent service, enables
a higher proportion of local communities and personnel to share in
the success of the Shaikan development.
We remain focussed on assuring our environmental impact is
minimised and in 2018 a number of drilling sites, where storage
pits had been left in place, were remediated and landscaped. The
programme was carried out in close collaboration with the MNR, who
have agreed that it met all requirements. The programme continues
in 2019, but by the end of this year we hope to have completed the
remediation of all those sites. We were also very pleased to
receive approval from the MNR for our Environmental and Social
Impact Studies (ESIA) in relation to the drilling programme and the
pipeline installation.
In 2018, the Company was pleased to agree a long term corporate
social responsibility ("CSR") strategy with local and government
stakeholders. The aim of the strategy is to ensure community
investment is built into the framework of Gulf Keystone's business
actions. We have started a number of projects - in particular two
relating to improvement to agricultural practice - and have
identified a number of others which we are in the process of
evaluating. We actively work with NGOs in the region using their
expertise in the implementation of these projects.
Consolidated Income Statement
For the year ended 31 December 2018
Notes 2018 2017
$'000 $'000
----- --------- ---------
Continuing operations
Revenue 2 250,554 172,372
Cost of sales 3 (154,534) (126,996)
--------- ---------
Gross profit 96,020 45,376
General and administrative expenses 4 (17,813) (21,304)
--------- ---------
Profit from operations 78,207 24,072
Finance revenue 7 4,441 702
Finance costs 7 (13,873) (11,023)
Other gains and losses 6 10,925 314
--------- ---------
Profit before tax 79,700 14,065
Tax credit 8 189 61
--------- ---------
Profit after tax for the year 79,889 14,126
--------- ---------
Profit per share (cents)
Basic 9 34.84 6.16
Diluted 9 33.87 6.12
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2018
2018 2017
$'000 $'000
------ ------
Profit after tax for the year 79,889 14,126
Items that may subsequently be reclassified
to profit or loss:
Exchange differences on translation
of foreign operations (800) 1,281
------ ------
Total comprehensive profit for the
year 79,089 15,407
====== ======
Consolidated Balance Sheet
As at 31 December 2018
Notes 2018 2017
$'000 $'000
----- --------- ---------
Non-current assets
Intangible assets 10 84 63
Property, plant and equipment 11 380,537 417,473
Deferred tax asset 18 559 403
381,180 417,939
--------- ---------
Current assets
Inventories 13 14,190 17,190
Trade and other receivables 14 67,909 61,710
Cash and cash equivalents 295,566 160,456
--------- ---------
377,665 239,356
--------- ---------
Total assets 758,845 657,295
========= =========
Current liabilities
Trade and other payables 15 (81,478) (57,038)
Provisions 17 (4,155) (7,197)
(85,633) (64,235)
--------- ---------
Non-current liabilities
Borrowings 16 (97,795) (97,067)
Provisions 17 (22,600) (24,107)
--------- ---------
(120,395) (121,174)
--------- ---------
Total liabilities (206,028) (185,409)
--------- ---------
Net assets 552,817 471,886
========= =========
Equity
Share capital 19 229,430 229,430
Share premium 19 920,728 920,728
Exchange translation reserve (3,818) (3,018)
Accumulated losses (593,523) (675,254)
--------- ---------
Total equity 552,817 471,886
========= =========
The financial statements were approved by the Board of Directors
and authorised for issue on 27 March 2019 and signed on its behalf
by:
Jón Ferrier
Chief Executive Officer
Sami Zouari
Chief Financial Officer
Consolidated Statement of Changes in Equity
For the year ended 31 December 2018
Attributable to equity holders of
the Company
----------
Exchange
Share Share translation Accumulated Total
Notes capital premium reserve losses equity
$'000 $'000 $'000 $'000 $'000
Balance at 1 January
2017 229,430 920,728 (4,299) (692,090) 453,769
---------- --------- ------------- ------------ ----------
Net profit for the
year - - - 14,126 14,126
Other comprehensive
loss for the year - - 1,281 - 1,281
---------- --------- ------------- ------------ ----------
Total comprehensive
loss for the year - - 1,281 14,126 15,407
---------- --------- ------------- ------------ ----------
Share-based payment
expense 22 - - - 2,710 2,710
Balance at 31 December
2017 229,430 920,728 (3,018) (675,254) 471,886
---------- --------- ------------- ------------ ----------
Net profit for the
year - - - 79,889 79,889
Other comprehensive
profit for the year - - (800) - (800)
---------- --------- ------------- ------------ ----------
Total comprehensive
profit for the year - - (800) 79,889 79,089
---------- --------- ------------- ------------ ----------
Share-based payment
expense 22 - - - 1,842 1,842
Balance at 31 December
2018 229,430 920,728 (3,818) (593,523) 552,817
========== ========= ============= ============ ==========
Consolidated Cash Flow Statement
For the year ended 31 December 2018
Notes 2018 2017
$'000 $'000
----- -------- --------
Operating activities
Cash generated from operations 20 161,483 85,300
Interest received 7 4,441 702
Interest paid on Reinstated Notes 16 (7,713) (10,111)
Net cash generated from operating activities 158,211 75,891
-------- --------
Investing activities
Purchase of intangible assets (66) -
Purchase of property, plant and equipment (20,589) (8,856)
Net cash used in investing activities (20,655) (8,856)
-------- --------
Financing activities
Issue costs of new notes (2,366) -
Net cash from financing activities (2,366) -
-------- --------
Net increase in cash and cash equivalents 135,190 67,035
Cash and cash equivalents at beginning
of year 160,456 92,870
Effect of foreign exchange rate changes (80) 551
Cash and cash equivalents at end of the
year being bank balances and cash on
hand 295,566 160,456
======== ========
.
Summary of Significant Accounting Policies
General information
The Company is incorporated in Bermuda (registered address:
Cumberland House, 9(th) Floor, 1 Victoria Street, Hamilton,
Bermuda). On 25 March 2014, the Company's common shares were
admitted, with a standard listing, to the Official List of the
United Kingdom Listing Authority ("UKLA") and to trading on the
London Stock Exchange's Main Market for listed securities.
Previously, the Company was quoted on Alternative Investment Market
("AIM"), a market operated by the London Stock Exchange. In 2008,
the Company established a Level 1 American Depositary Receipt
programme in conjunction with the Bank of New York Mellon, which
has been appointed as the depositary bank. The Company serves as
the holding company for the Group, which is engaged in oil and gas
exploration and production, operating in the Kurdistan Region of
Iraq. During 2018 the company was still operating in Algeria,
however it formally exited the country in January 2019.
Adoption of new and revised Standards
Amendments to International Financial Reporting Standards
("IFRS") that are mandatorily effective for the current year
In the current year, the Group has applied a number of
amendments to IFRSs issued by the International Accounting
Standards Board (IASB) that are mandatorily effective for an
accounting period that begins on or after 1 January 2018. Their
adoption has not had any material impact on the disclosures or on
the amounts reported in these financial statements.
IFRS 9 Financial The Group has adopted the IFRS 9 for the
instruments first time in the current year. The standard
requires an entity to address the classification,
measurement and recognition of financial
assets and liabilities. The impact of this
adoption has not had a material impact on
the Group's financial statements. In applying
IFRS 9 on trade receivables the expected
credit loss is not determined to be
material.
IFRS 15 Revenue The Group has adopted IFRS 15 for the first
from contracts time in the current year. The Group's accounting
policy under IFRS 15 is that revenue is
recognised when the Group satisfies a performance
obligation by transferring oil to our customer
and completing transportation services on
their behalf. The application of IFRS 15
is not determined to be material.
---------------------------------------------------
New and revised IFRSs in issue but not yet effective
At the date of authorisation of these financial statements, The
Group has not applied the following new and revised IFRSs that have
been issued but are not yet effective and in some cases had not yet
been adopted by the EU:
IFRS 16 Leases
IFRS 17 Insurance Contracts
IFRS 9 Prepayment Features with Negative Compensation
IAS 28 (amendments) Long-term interests in Associates and Joint
Ventures
Annual Improvements Amendments to IFRS 3 Business combinations,
Standards 2015-17 IFRS 11 Joint Arrangements
Cycle IAS 12 Income taxes and IAS 23 Borrowing
costs
IAS 19 (amendments) Employee benefits, plan amendments, curtail
or settlement.
IFRS 10 and IAS Sale or Contribution of Assets between an
28 (amendments) Investor and its Associate or Joint Venture
Annual Improvements Amendments to IFRS 1 First-time Adoption
to IFRSs 2014-2016 of International Financial Reporting Standards
Cycle and IFRS 28 Investments in Associates and
Joint Ventures
IFRIC 23 Uncertainty over Income Tax Treatments
The directors do not expect that the adoption of the Standards
listed above will have a material impact on the financial
statements of the Group in future periods, except as noted
below:
IFRS 16 Leases
IFRS 16 introduces a comprehensive model for the identification
of lease arrangements and accounting treatments for both lessors
and lessees. IFRS 16 will supersede the current lease guidance
including IAS 17 Leases and the related interpretations when it
becomes effective for accounting periods beginning on or after 1
January 2019. The date for the initial application of IFRS for the
Group will be 1 January 2019.
IFRS 16 will change how the Group accounts for leases previously
classified as operating leases under IAS 17, which were off balance
sheet.
On initial application of IFRS 16 the Group will;-
a) Recognise right-of-use assets and lease liabilities,
initially measured at the present value of the future lease
payments;
b) Recognise depreciation of right-to-use assets and interest on
lease liabilities in the consolidated statement of profit and
loss;
c) Separate the total amount of cash paid into a principal
portion(presented within financing activities) and (interest
presented within operating activities) in the consolidated cash
flow statement.
Under the transition rules of IFRS16 the Group has chosen to
adopt the cumulative catch-up approach. The Group will not restate
any prior year figures and make any necessary adjustments between
assets and liabilities through opening retained earnings. The Group
does not expect the implementation of IFRS 16 to have a material
impact on the financial statements.
The impact of IFRS 16 on the Group has set out in the table
below:
Retained
Date of assessment Assets Liabilities Net Assets Expenses Earnings
$'000 $'000 $'000 $'000 $'000
1 January 2019 979 (979) - - -
Year Ended 31 December
2019 221 (14) 207 8 8
Year Ended 31 December
2020 234 (255) (21) (10) (2)
Year Ended 31 December
2021 47 (54) (7) (14) (16)
Year Ended 31 December
2022 - - - 7 (9)
Statement of compliance
The financial statements have been prepared in accordance with
IFRS as adopted by the European Union.
Basis of accounting
The financial statements have been prepared under the historical
cost basis, except for the valuation of hydrocarbon inventory and
the valuation of certain financial instruments, which have been
measured at fair value, and on the going concern basis.
Equity-settled share-based payments are initially recognised at
fair value, but are not subsequently revalued. The principal
accounting policies adopted are set out below.
Going Concern
The Group's business activities, together with the factors
likely to affect its future development, performance and position
are set out in the Chairman's Statement, the Executive Review and
the Operational Review. The financial position of the Group at the
year end and its cash flows and liquidity position are included in
the Financial Review.
The Group continues to closely monitor and manage its liquidity
risk. Cash forecasts are regularly produced and sensitivities run
for different scenarios including, but not limited to, changes in
commodity prices, different production rates from the Shaikan
block, costs contingencies, disruptions to revenue receipts, etc.
The Group has taken appropriate action to reduce its cost base and
has $196 million of net cash as at 27 March 2019. The Group's
forecasts, taking into account the risks applicable, show that the
Group has sufficient financial headroom for the 12 months from the
date of approval of the 2018 Annual Report and Accounts.
Based on the analysis performed, the directors have a reasonable
expectation that the Group has adequate resources to continue in
operational existence for the foreseeable future. Thus, they
continue to adopt the going concern basis of accounting in
preparing the annual financial statements.
Basis of consolidation
The consolidated financial statements incorporate the financial
statements of the Company and enterprises controlled by the Company
(its subsidiaries) made up to 31 December each year. Control is
achieved where the Company has the power to govern the financial
and operating policies of an investee entity, so as to obtain
benefits from its activities.
Non-IFRS measures
The Group uses certain measures to assess the financial
performance of its business. Some of these measures are termed
"non-IFRS measures" because they exclude amounts that are included
in, or include amounts that are excluded from, the most directly
comparable measure calculated and presented in accordance with
IFRS, or are calculated using financial measures that are not
calculated in accordance with IFRS. These non-IFRS measures include
financial measures such as operating costs and non-financial
measures such as gross average production.
The Group uses such measures to measure and monitor operating
performance and liquidity, in presentations to the Board and as a
basis for strategic planning and forecasting. The directors believe
that these and similar measures are used widely by certain
investors, securities analysts and other interested parties as
supplemental measures of performance and liquidity.
The non-IFRS measures may not be comparable to other similarly
titled measures used by other companies and have limitations as
analytical tools and should not be considered in isolation or as a
substitute for analysis of the Group's operating results as
reported under IFRS. An explanation of the relevance of each of the
non-IFRS measures and a description of how they are calculated is
set out below. Additionally, a reconciliation of the non-IFRS
measures to the most directly comparable measures calculated and
presented in accordance with IFRS and a discussion of their
limitations is set out below, where applicable. The Group does not
regard these non-IFRS measures as a substitute for, or superior to,
the equivalent measures calculated and presented in accordance with
IFRS or those calculated using financial measures that are
calculated in accordance with IFRS.
Operating costs
Operating costs is a useful indicator of the Group's costs
incurred to produce Shaikan oil. Operating costs, in comparison
with cost of sales, exclude certain non-cash accounting
adjustments, contractual PSC payments and transportation costs.
Year Ended Year Ended
31 December 31 December
2018 2017
$ million $ million
--------------------------------- ------------ ------------
Cost of sales 154.5 127.0
Depreciation of oil & gas assets (70.7) (79.8)
Production bonus (16.0) -
Capacity building payments (17.0) (17.2)
Transportation costs (14.3) (2.4)
Working capital movement (5.8) 1.2
Operating costs 30.7 28.8
============ ============
Gross operating costs per barrel (unaudited)
Gross operating costs are divided by gross production to arrive
at operating costs per bbl.
Year Ended Year Ended
31 December 31 December
2018 2017
Gross production (MMbbls) 11.5 12.9
Gross operating costs ($ million) 36.8 35.4
Gross operating costs per barrel
($ per bbl) 3.2 2.7
EBITDA
EBITDA is a useful indicator of the Group's profitability, which
excludes the impact of costs attributable to income tax
(expense)/credit, finance costs, interest revenue, depreciation,
depletion and amortisation and other gains and losses.
Year Ended Year Ended
31 December 31 December
2018 2017
$ million $ million
--------------------------------- ------------ ------------
Profit from operations 78.2 24.1
Depreciation of oil & gas assets 70.7 79.8
Depreciation and amortisation 0.4 0.4
EBITDA 149.3 104.3
============ ============
Capital Investment
Capital investment is the value of the Group's additions to oil
and gas assets excluding any movements in decommissioning
assets.
Year Ended Year Ended
31 December 31 December
2018 2017
$ million $ million
-------------------------------- ------------ ------------
Additions to oil and gas assets 35.7 8.1
Capital Investment 35.7 8.1
============ ============
Net Cash
Net Cash is a useful indicator of the Group's indebtedness,
financial flexibility and capital structure because it indicates
the level of cash and cash equivalents less cash borrowings within
the Group's business. Net cash is defined as current and
non-current borrowings plus non-cash adjustments, less cash and
cash equivalents. Non-cash adjustments include unamortised
arrangement fees and other adjustments.
Year Ended Year Ended
31 December 31 December
2018 2017
$ million $ million
-------------------------- ------------ ------------
Outstanding New Notes (100.0) (100.0)
Non-cash adjustments (4.4) (2.0)
Cash and cash equivalents 295.6 160.5
Net Cash 191.2 58.5
============ ============
Joint arrangements
The Group is engaged in oil and gas exploration, development and
production through unincorporated joint arrangements; these are
classified as joint operations in accordance with IFRS 11. The
Group accounts for its share of the results and net assets of these
joint operations. Where the Group acts as Operator of the joint
operation, the gross liabilities and receivables (including amounts
due to or from non-operating partners) of the joint operation are
included in the Group's balance sheet.
Sales revenue
The recognition of revenue, particularly the recognition of
revenue from export sales of crude oil, is considered to be a key
accounting judgement.
All oil is sold to the KRG, who in turn resell the oil either
export in the pipeline at PF-2, at Fishkhabour or by trucking it to
domestic customers. The selling price is determined in accordance
with the principles of the crude oil export sales agreement ("Crude
Oil Sales Agreement"), based on the Brent crude price less a
quality discount and transportation costs. The sales agreement also
specifies the delivery point, KRG's contribution to transportation
costs and payment terms relating to export sales of crude oil. The
Crude Oil Sales Agreement has been governing Shaikan crude oil
sales from 1 October 2017 onwards.
As the payment mechanism for sales is developing within the
Kurdistan Region of Iraq, the Group currently considers that
revenue can best be reliably measured when the cash receipt is
assured. The assessment of whether cash receipt is reasonably
assured is based on management's evaluation of the reliability of
the KRG's payments to the international oil companies operating in
the Kurdistan Region of Iraq.
The value of sales revenue is determined after taking account of
the following:
-- For the crude oil sales via Fishkhabour route, the point of
sale is the point that the crude oil is unloaded into the export
pipeline at Fishkhabour;
-- For the crude oil sales via Atrush feeder line, the point of
sale is the point that the crude oil in injected into the Atrush
feeder line;
-- The point of sale for domestic sales is at the Shaikan facility;
-- GKP recognises revenue for its share of the revenue on a
cash-assured basis and these amounts of recognised revenue may be
lower than the Company's entitlement under the Shaikan PSC, giving
rise to unrecognised revenue amounts;
-- From 15 November 2017 onwards, the Group has performed
transportation services in respect of the KRG's share of export oil
sales. It recharges all of these transportation costs at nil
mark-up to the KRG and these recharged transportation costs are
recognised as revenue; and
-- Under the Shaikan PSC and the bilateral agreement between
GKPI and the MNR signed on 16 March 2016 ("Bilateral Agreement"),
the Group is entitled to offset certain costs (including capacity
building payments and production bonuses) against amounts owed by
the KRG to GKPI. In these instances, the Group recognises revenue
and a reduction in the liability to the KRG.
To the extent that revenue arises from test production during an
evaluation programme, an amount is charged from exploration and
evaluation costs to cost of sales so as to reflect a zero net
margin.
Income tax arising from the Company's activities under its
production sharing contract is settled by the KRG on behalf of the
Company. However, the Company is not able to measure the amount of
income tax that has been paid on its behalf and, therefore, the
notional income tax amounts have not been included in revenue or in
the tax charge.
Interest Revenue
Interest revenue is accrued on a time basis, by reference to the
principal outstanding and at the effective rate of interest
applicable, which is the rate that exactly discounts estimated
future cash receipts through the expected life of the nancial asset
to that asset's net carrying amount on initial recognition.
Property, plant and equipment other than oil and gas assets
Property, plant and equipment ("PPE") are stated at cost less
accumulated depreciation and any accumulated impairment losses.
Depreciation is provided at rates calculated to write each asset
down to its estimated residual value over its expected useful life
as follows:
Fixtures and equipment - 20% straight-line
Intangible assets other than oil and gas assets
Intangible assets, other than oil and gas assets, have finite
useful lives and are measured at cost and amortised over their
expected useful economic lives as follows:
Computer software - 33% straight-line
Oil and gas assets
Pre-licence costs
Costs incurred prior to having obtained the legal rights to
explore an area are expensed directly to the income statement as
they are incurred.
Exploration and evaluation costs
The Group follows the successful efforts method of accounting
for exploration and evaluations ("E&E") costs. Expenditures
directly associated with evaluation or appraisal activities are
initially capitalised as intangible asset in cost pools by well,
field or exploration area, as appropriate. Such costs include
licence acquisition, technical services and studies, seismic
acquisition, exploration and appraisal well drilling, payments to
contractors, interest payable and directly attributable
administration and overhead costs.
These costs are then written off as exploration costs in the
income statement unless the existence of economically recoverable
reserves has been established and there are no indicators of
impairment.
E&E costs are transferred to development and production
assets within property, plant and equipment upon the approval of a
development programme by the relevant authorities and the
determination of commercial reserves existence.
Development and production assets
Development and production assets are accumulated on a
field-by-field basis and represent the cost of developing the
commercial reserves discovered and bringing them into production,
together with the E&E expenditures incurred in finding
commercial reserves transferred from intangible E&E assets as
outlined above.
The cost of development and production assets includes the cost
of acquisition and purchases of such assets, directly attributable
overheads, and costs for future restoration and decommissioning.
These costs are capitalised as part of the property, plant and
equipment and depreciated based on the Group's depreciation of oil
and gas assets policy.
Depreciation of oil and gas assets
The net book values of producing assets are depreciated
generally on a field-by-field basis using the unit of production
("UOP") basis which uses the ratio of oil and gas production in the
period to the remaining commercial reserves plus the production in
the period. Production associated with unrecognised export sales
revenue is included in the DD&A calculation. Costs used in the
calculation comprise the net book value of the field, and any
further anticipated costs to develop such reserves.
Commercial reserves are proven and probable ("2P") reserves
together with, where considered appropriate, a risked portion of 2C
contingent resources, which are estimated using standard recognised
evaluation techniques. The estimate is regularly reviewed by
independent consultants.
Impairment of PPE and intangible non-current assets
At each balance sheet date, the Group reviews the carrying
amounts of its tangible and intangible assets to determine whether
there is any indication that those assets have suffered an
impairment loss. If any such indication exists, the recoverable
amount of the asset, or group of assets, is estimated in order to
determine the extent of the impairment loss (if any).
For assets which do not generate cash flows that are independent
from other assets, the Group estimates the recoverable amount of
the cash-generating unit to which the asset belongs.
Recoverable amount is the higher of fair value less costs to
sell and value in use. In assessing value in use, the estimated
future cash flows are discounted to their present value using a
pre-tax discount rate that reflects current market assessments of
the time value of money and the risks specific to the asset for
which the estimates of future cash flows have not been
adjusted.
Any impairment identified is immediately recognised as an
expense.
Borrowing costs
Borrowing costs directly relating to the acquisition,
construction or production of qualifying assets, which are assets
that necessarily take a substantial period of time to get ready for
their intended use or sale, are capitalised and added to the cost
of those assets, until such time as the assets are substantially
ready for their intended use or sale.
Investment income earned on the temporary investment of specific
borrowings pending their expenditure on qualifying assets is
deducted from the borrowing costs eligible for capitalisation.
All other borrowing costs are recognised in the income statement
in the period in which they are incurred.
Taxation
The tax expense represents the sum of the tax currently payable
and deferred tax.
The tax currently payable is based on taxable profit for the
year. Current tax assets and liabilities are measured at the amount
expected to be recovered from or paid to the taxation authorities,
based on tax rates and laws that are enacted or substantively
enacted by the balance sheet date.
As described in the revenue accounting policy section above, it
is not possible to calculate the amount of notional tax to be shown
in relation to any tax liabilities settled on behalf of the Group
by the KRG.
Deferred tax is the tax expected to be payable or recoverable on
differences between the carrying amounts of assets and liabilities
in the financial statements and the corresponding tax bases used in
the computation of taxable profit,and is accounted for using the
balance sheet liability method. 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 the initial recognition of goodwill or from the initial
recognition of other assets and liabilities in a transaction that
affects neither the taxable profit nor the accounting profit.
The carrying amount of deferred tax assets is reviewed at each
balance sheet date and reduced to the extent that it is no longer
probable that sufficient taxable profits will be available to allow
all or part assets to be recovered.
Deferred tax is calculated at the tax rates that are expected to
apply in the period when the liability is settled or the asset is
realised based on tax laws and rates that have been enacted or
substantively enacted by the balance sheet date. Deferred tax is
charged or credited in the income statement, except when it relates
to items charged or credited directly to equity, in which case the
deferred tax is also recognised in equity.
Foreign currencies
The individual financial statements of each company are
presented in the currency of the primary economic environment in
which it operates (its functional currency). For the purpose of the
consolidated financial statements, the results and the financial
position of the Group are expressed in US dollars, which is the
functional currency of the Group, and the presentation currency for
the consolidated financial statements.
In preparing the financial statements of the individual
companies, transactions in currencies other than the entity's
functional currency are recorded at the rates of exchange
prevailing on the dates of the transactions. At each balance sheet
date, monetary assets and liabilities that are denominated in
foreign currencies are retranslated at the rates prevailing on the
balance sheet date. Non-monetary assets and liabilities carried at
fair value that are denominated in foreign currencies are
translated at the rates prevailing at the date when the fair value
was determined. Gains and losses arising on retranslation are
included in the income statement for the year.
On consolidation, the assets and liabilities of the Group's
foreign operations which use functional currencies other than US
dollars are translated at exchange rates prevailing on the balance
sheet date. Income and expense items are translated at the average
exchange rates for the period. Exchange differences arising, if
any, are recognised in other comprehensive income and accumulated
in equity in the Group's translation reserve. On the disposal of a
foreign operation, such translation differences are reclassified to
profit or loss.
Inventories
Inventories, except for hydrocarbon inventories, are valued at
the lower of cost and net realisable value. Hydrocarbon inventories
are recorded at net realisable value with changes in hydrocarbon
inventories being adjusted through cost of sales.
Financial instruments
Financial assets and financial liabilities are recognised on the
Group's balance sheet when the Group has become a party to the
contractual provisions of the instrument.
Trade receivables
Trade receivables are measured at amortised cost using the
effective interest method less any impairment.
Cash and cash equivalents
Cash and cash equivalents comprise cash on hand and demand
deposits and other short-term highly liquid investments that are
readily convertible to a known amount of cash and are subject to an
insignificant risk of changes in value.
Liquid investments
Liquid investments comprise short-term liquid investments with
maturities of three to twelve months.
Financial assets at fair value through profit and loss
Financial assets are held at fair value through profit and loss
("FVTPL") when the financial asset is either held for trading or it
is designated at FVTPL. Financial assets at FVTPL are stated at
fair value, with any gains or losses arising on re-measurement
recognised in profit or loss. The net gain or loss recognised in
profit or loss incorporates any dividend or interest earned on the
financial asset and is included in the other gains and losses line
in the income statement.
Derivative financial instruments
The Group may enter into derivative financial instruments
including foreign exchange forward contracts to manage its exposure
to foreign exchange rate risk.
Derivatives are initially recognised at fair value at the date a
derivative contract is entered into and are subsequently
re-measured to their fair value at each balance sheet date. The
resulting gain or loss is recognised in the profit or loss
immediately unless the derivative is designated and effective as a
hedging instrument, in which event the timing of the recognition in
profit or loss depends on the nature of the hedge relationship.
A derivative with a positive fair value is recognised as a
financial asset whereas a derivative with a negative fair value is
recognised as a liability. A derivative is presented as a
non-current asset or a non-current liability if the remaining
maturity of the instrument is more than twelve months and it is not
expected to be realised or settled within twelve months. Other
derivatives are presented as current assets or current
liabilities.
Impairment of financial assets
Financial assets, other than those valued at FVTPL, are assessed
for indicators of impairment at each balance sheet date. Financial
assets are impaired where there is objective evidence that, as a
result of one or more events that occurred after the initial
recognition of the financial asset, the estimated future cash flows
of the investment have been impacted.
For certain categories of financial asset, such as trade
receivables, assets that are assessed not to be impaired
individually are subsequently assessed for impairment on a
collective basis. Objective evidence of impairment for a portfolio
of receivables could include the Group's past experience of
collecting payments, an increase in the number of delayed payments
in the portfolio past the average credit period, as well as
observable changes in local or national economic conditions that
correlate with default on receivables.
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
Equity instruments issued by the Company are recorded at the
proceeds received, net of direct issue costs, which are charged to
share premium.
Borrowings
Interest-bearing loans and overdrafts are recorded at the fair
value of proceeds received, net of transaction costs. Finance
charges, including premiums payable on settlement or redemption,
are accounted for on an accrual basis and are added to the carrying
amount of the instrument to the extent that they are not settled in
the year in which they arise. The liability is carried at amortised
cost using the effective interest rate method until maturity.
Trade payables
Trade payables are stated at amortised cost. The average
maturity for trade and other payables is one to three months.
Provisions
Provisions are recognised when the Group has a present
obligation as a result of a past event which it is probable will
result in an outflow of economic benefits that can be reliably
estimated.
Decommissioning provision
Provision for decommissioning is recognised in full when damage
is done to the site and an obligation to restore the site to its
original condition exists. The amount recognised is the present
value of the estimated future expenditure for restoring the sites
of drilled wells and related facilities to their original status. A
corresponding amount equivalent to the provision is also recognised
as part of the cost of the related oil and gas asset. The amount
recognised is reassessed each year in accordance with local
conditions and requirements. Any change in the present value of the
estimated expenditure is dealt with prospectively. The unwinding of
the discount is included as a finance cost.
Share-based payments
Equity-settled share-based payments to employees and others
providing similar services are measured at the fair value of the
entity instruments at the grant date. Details regarding the
determination of the fair value of equity-settled share-based
transactions are set out in Note 22. The fair value determined at
the grant date of the equity-settled share-based payments is
expensed on a straight- line basis over the vesting period, based
on the Group's estimate of equity instruments that will eventually
vest. At each balance sheet date, the Group revises its estimate of
the number of equity instruments expected to vest as a result of
the effect of non-market based vesting conditions. The impact of
the revision of the original estimates, if any, is recognised in
profit or loss such that the cumulative expense reflects the
revised estimate, with a corresponding adjustment to equity
reserve.
For cash-settled share-based payments, a liability is recognised
for the goods or services acquired, measured initially at the fair
value of the liability. At each balance sheet date until the
liability is settled, and at the date of settlement, the fair value
of the liability is re-measured, with any changes in fair value
recognised in profit or loss for the period. Details regarding the
determination of the fair value of cash-settled share-based
transactions are set out in Note 22.
Leasing
Rentals payable under operating leases are charged to the income
statement on a straight-line basis over the term of the relevant
lease.
Critical accounting estimates and judgements
In the application of the Group's accounting policies, which are
described above, the directors are required to make judgements,
estimates and assumptions about the carrying amounts of assets and
liabilities that are not readily apparent from other sources. The
estimates and associated assumptions are based on historical
experience and other factors that are considered to be relevant.
Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an
ongoing basis. Revisions to accounting estimates are recognised in
the period in which the estimate is revised if the revision affects
only that period or in the period of revision and future periods if
the revision affects both current and future periods.
Key estimates
Reserves estimates
Commercial reserves are determined using estimates of
oil-in-place, recovery factors and future oil prices. Future
development costs are estimated using assumptions as to numbers of
wells required to produce the commercial reserves, the cost of such
wells and associated production facilities and other capital and
operating costs. Reserves estimates principally affect the
depreciation, depletion and amortisation charges, as well as
impairment assessments.
Carrying value of producing assets
Oil and gas assets within property, plant and equipment are held
at historical cost value, less accumulated depreciation and
impairments.
Producing assets are tested for impairment whenever indicators
of impairment exist. Management assesses whether such indicators
exist, with reference to the criteria specified in IAS 36
Impairment of Assets, at least annually.
As at 31 December 2017, an internal valuation of the Shaikan
field was performed, providing further support in relation to the
conclusion that no indicators of impairment existed.
The assumptions and estimates in the valuation model
include:
- Commodity prices that are based on latest internal forecasts,
benchmarked with external sources of information, to ensure they
are within the range of available analyst forecasts and the
long-term corporate economic assumptions thereafter;
- Discount rates that are adjusted to reflect risks specific to
individual assets and the region;
- Commercial reserves and the related production and payment profiles; and
- Timing of revenue receipts.
Operating costs and capital expenditure are based on financial
budgets and internal management forecasts. Cost assumptions
incorporate management experience and expectations, as well as the
nature and location of the operation and the risks associated
therewith. Underlying input cost assumptions are consistent with
related output price assumptions.
In line with the Group's accounting policy on impairment,
management performs an impairment review of the Group's oil and gas
assets annually with reference to indicators as set out in IAS 36.
The Group assesses its group of assets called cash generating units
(CGU) for impairment if events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. Where
indicators are present, management calculates the recoverable
amount using key assumptions such as future oil and gas prices,
estimated production volume, pre-tax discount rates that reflect
the current market assessment of the time value of money and risks
specific to the asset, commercial reserves, inflation and
transportation fees. The key assumptions are subject to change
based on the current market trends and economic conditions. The
CGU's recoverable amount is the higher of the fair value less cost
of disposal and value in use. Where the CGU's recoverable amount is
lower than the carrying amount, the CGU is considered impaired and
is written down to its recoverable amount. The Group's sole CGU at
31 December 2018 was Shaikan with a carrying value of $379.7
million. No impairment indicator was identified as at 31 December
2018.
Reserves estimates
Commercial reserves are determined using estimates of
oil-in-place, recovery factors and future oil prices. Future
development costs are estimated using assumptions as to numbers of
wells required to produce the commercial reserves, the cost of such
wells and associated production facilities, and other capital and
operating costs. Reserves estimates principally affect the
depreciation, depletion and amortisation charges, as well as
impairment assessments.
Significant accounting judgement
Revenue
The recognition of revenue, particularly the recognition of
revenue from exports, is considered to be a key accounting
judgement. The Group began commercial production from the Shaikan
field in July 2013 and historically made sales to both the domestic
and export markets. However, as the payment mechanism for sales to
the export market continues to develop within the Kurdistan Region
of Iraq, the Group considers that revenue can be only reliably
measured when the cash receipt is assured. The assessment of
whether cash receipts are reasonably assured is based on
management's evaluation of the reliability of the MNR's payments to
the international oil companies operating in the Kurdistan Region
of Iraq. The Group also recognised payables to the MNR that were
offset against amounts receivable from the MNR for previously
unrecognised revenue in line with the terms of the Shaikan PSC.
The judgement is not to recognise revenue in excess of the sum
of the cash receipt that is assured and the amount of payables to
the MNR that can be offset against amounts due for previously
unrecognised revenue in line with the terms of the Shaikan PSC,
despite the Group being entitled to additional revenue under the
terms of the Shaikan PSC. Any future agreements between the Company
and the KRG might change the amounts of revenue recognised.
Notes to the Consolidated Financial Statements
1. Segment information
For the purposes of resource allocation and assessment of
segment performance, the Group is organised into three regional
business units - Algeria, Kurdistan and the Corporate. These
geographical segments are the basis on which the Group reports its
segmental information. The chief operating decision maker is the
Chief Executive Officer. He is assisted by the Chief Financial
Officer and senior management team.
The accounting policies of the reportable segments are
consistent with the Group's accounting policies.
Each segment is described in more detail below:
- Kurdistan Region of Iraq: the Kurdistan segment consists of
the Shaikan asset and the Erbil office, which provides support to
the operations in Kurdistan;
- Algeria: the Algerian segment consists of the Algiers office
and the Group's operations in Algeria. This activity has now been
exited in January 2019.
- Corporate: the corporate segment consists of the Group's UK
and Bermuda offices. It represents all overhead and administration
costs incurred that are of a corporate nature and elimination of
intercompany income and charges which cannot be directly linked to
one of the above segments.
31 December 2018 Algeria Kurdistan Corporate Total
$'000 $'000 $'000 $'000
--------------------------------- -------- ---------- ---------- ---------
Revenue
Oil sales - 243,711 - 243,711
Transportation revenue - 6,843 - 6,843
Inter-segment sales - - - -
-------- ---------- ---------- ---------
Total revenue 250,554 - 250,554
Cost of sales
Production costs - (69,479) - (69,479)
Oil and gas assets depreciation
expense - (70,744) - (70,744)
Transportation costs - (14,311) - (14,311)
-------- ---------- ---------- ---------
Gross profit - 96,020 - 96,020
General and administrative
expenses
Allocated general and
administrative expenses (153) (7,776) (9,500) (17,429)
Depreciation and amortisation
expense - (105) (279) (384)
Profit / (loss) from
operations (153) 88,139 (9,779) 78,207
Interest revenue - 3,713 728 4,441
Finance costs - (723) (13,150) (13,873)
Other gains and losses 10,205 39 681 10,925
-------- ---------- ---------- ---------
Profit / (loss) before
tax 10,052 91,168 (21,520) 79,700
Tax benefit - - 189 189
Profit / (loss) after
tax 10,052 91,168 (21,331) 79,889
======== ========== ========== =========
Capital expenditure - 36,316 109 36,425
Total assets - 686,636 72,209 758,845
======== ========== ========== =========
During 2018, the allocated general and administrative expenses
of $17.4 million (2017: $20.6 million) included costs that are
recoverable under the terms of the Shaikan PSC amounting to $7.3
million (2017: $5.4 million).
31 December 2017 Algeria Kurdistan Corporate Total
$'000 $'000 $'000 $'000
Revenue
Oil sales - 171,203 - 171,203
Transport revenue - 1,169 - 1,169
-------- ---------- ---------- ---------
Total revenue 172,372 - 172,372
Cost of sales
Production costs - (44,765) - (44,765)
Oil and gas assets
depreciation
expense - (79,785) - (79,785)
Transportation costs - (2,446) - (2,446)
Gross profit - 45,376 - 45,376
General and administrative
expenses
Allocated general and
administrative expenses (63) (5,387) (15,157) (20,607)
Depreciation and amortisation
expense - (145) (280) (425)
Profit / (loss) from
operations (63) 39,844 (15,437) 24,344
Interest revenue - 432 270 702
Finance income/ (costs) - (714) (10,309) (11,023)
Other gains - 323 (281) 42
-------- ---------- ---------- ---------
Profit / (loss) before
tax (63) 39,885 (25,757) 14,065
Tax expense - - 61 61
Profit / (Loss) after
tax (63) 39,885 (25,696) 14,126
======== ========== ========== =========
Capital expenditure - 43,578 - 43,578
Total assets 31 582,192 75,072 657,295
-------- ---------- ---------- ---------
The 2017 segemental analysis has been restated to combine
corporate activities under one heading
Geographical information
The Group's information about its segment assets (non-current
assets excluding deferred tax assets and other financial assets) by
geographical location is detailed below:
2018 2017
$'000 $'000
--------------- ------- -------
Kurdistan 380,339 417,024
United Kingdom 282 512
------- -------
380,621 417,536
======= =======
Information about major customers
Included in revenues arising from the Kurdistan segment are
revenues of approximately $250.6 million which arose from sales to
the Group's largest customer (2017: $172.4 million).
2. Revenue
2018 2017
$'000 $'000
----------------------- ------- -------
Oil sales 243,711 171,203
Transportation revenue 6,843 1,169
------- -------
250,554 172,372
======= =======
The Group accounting policy for revenue recognition is set out
in the Summary of Significant Accounting Policies, with revenue
recognised on a cash-assured basis.
During 2018, the cash-assured values recognised as oil sales
were the invoiced revenue for the year amounting to $227.5 million
(2017: $156.3 million). The MNR liability offset revenue recognised
was $16.2 million (2017: $14.9 million). The oil sales price was
calculated using the monthly Brent price less an average discount
of $22.3 (2017: $20.3) per barrel for quality, pipeline tariff and
transportation costs.
From 15 November 2017 onwards, the Group has performed
transportation services in respect of the KRG's share of export oil
sales. It recharges all of these transportation costs at nil
mark-up to the KRG.
Interest revenue has been presented as part of net finance costs
(note 7).
3. Cost of Sales
2018 2017
$'000 $'000
----------------------------------- ------- -------
Oil production costs 69,479 44,765
Depreciation of oil and gas assets 70,744 79,785
Transportation costs 14,311 2,446
154,534 126,996
======= =======
Oil production costs represent the Group's share of gross
production expenditure for the Shaikan field for the year and
include capacity building charges of $17.0 million (2017: $17.2
million) and Shaikan PSC production bonus of $16.0 million (2017:
nil). All costs are included with no deferral of costs associated
with unrecognised sales in accordance with the Group's revenue
policy. Production and depreciation, depletion and amortisation
("DD&A") costs related to revenue arrears recognised in 2018
and 2017 have been charged to the income statement in prior periods
when the oil was lifted.
A unit-of-production method has been used to calculate the
DD&A charge for the year. This is based on full entitlement
production, commercial reserves and costs for Shaikan. Commercial
reserves are proven and probable ("2P") reserves, estimated using
standard recognised evaluation techniques. Production and reserves
entitlement associated with unrecognised sales in accordance with
the Group's revenue policy have been included in the full year
DD&A calculation.
The breakdown of the 2017 comparative has been restated by $1.3
million to accurately show the full transportation costs, as part
of this had previously been shown in oil production costs.
4. General and Administration costs
2018 2017
$'000 $'000
------------------------------------------- ------- ------
Depreciation and amortisation 383 425
Auditor's remuneration for audit fees (see
below) 252 219
Operating lease rentals 2,044 2,924
Other general and admin costs (including
staff costs) 15,134 17,736
------- ------
17,813 21,304
======= ======
2018 2017
$'000 $'000
-------------------------------------------------------- ------- -------
Fees payable to the Company's auditor for
the audit of the Company's annual accounts 224 192
Fees payable to the Company's auditor for
other services to the Group
* audit of the Company's subsidiaries pursuant to
legislation 28 27
------- -------
Total audit fees 252 219
Corporate finance services - 5
Other assurance services (half year review) 70 67
Total fees 322 291
======= =======
5. Staff costs
The average number of employees and contractors (including
Executive directors) employed by the Group was as follows:
2018 2017
Number Number
------------------------------------------ ------- -------
Office and management 76 76
Technical and operational 295 277
371 353
======= =======
Staff costs in respect of those employees
were as follows:
2018 2017
$'000 $'000
Wages and salaries 25,582 22,444
Social security costs 2,263 1,672
Share-based payment (see note 22) 1,842 2,712
29,687 26,828
======= =======
The Group have restated the staff costs note to include the
costs relating to contractors. These staff members are long term
workers in key positions and therefore this presentation is a more
accurate statement of the Group's staff costs.
A proportion of these costs is allocated to operating costs and
a proportion is capitalised as Oil and gas assets under the Group's
accounting policy for Property, plant and equipment, with the
remainder classified as an administrative overhead costs in the
income statement. The net staff cost recognised in the income
statement is $25.6m (2017: $23.1m)
6. Other gains
2018 2017
$'000 $'000
--------------- ------ ------
Other gains 10,215 272
Exchange gains 710 42
10,925 314
====== ======
The Company has received final clearance from Sonatrach in
relation to the Ferkane Permit (Block 126). This officially marks
Gulf Keystone's exit from its Algerian operations, which resulted
in a $10.2 million release of past liabilities recognised in other
gains in 2018.
In 2017, other gains consisted of the release of the
decommissioning liability relating to the Ber Bahr block of $0.3
million.
7. Finance costs and finance revenue
2018 2017
$'000 $'000
-------------------------------------------- -------- --------
Notes interest charged during the year (see
note 16) (13,150) (10,309)
Unwinding of discount on provisions (see
note 17) (723) (714)
-------- --------
Total finance costs (13,873) (11,023)
Finance revenue 4,441 702
-------- --------
Net finance costs (9,432) (10,321)
======== ========
8. Tax
2018 2017
$'000 $'000
-------------------------------------------- ------- -------
Current year charged - -
Adjustment in respect of prior year - -
Deferred UK corporation tax credit (see
note 18) 189 61
------- -------
Tax credit attributable to the Company and
its subsidiaries 189 61
======= =======
Under current Bermudian laws, the Group is not required to pay
taxes in Bermuda on either income or capital gains. The Group has
received an undertaking from the Minister of Finance in Bermuda
exempting it from any such taxes at least until the year 2035.
In the Kurdistan Region of Iraq, the Group is subject to
corporate income tax on its income from petroleum operations under
the Kurdistan PSCs. The rate of corporate income tax is currently
15% on total income. Under the Shaikan PSC, any corporate income
tax arising from petroleum operations will be paid from the KRG's
share of petroleum profits. Due to the uncertainty over the payment
mechanism for oil sales in Kurdistan, it has not been possible to
measure reliably the taxation due that has been paid on behalf of
the Group by the KRG and therefore the notional tax amounts have
not been included in revenue or in the tax charge. This is an
accounting presentational issue and there is no taxation to be
paid.
UK corporation tax is calculated at 19.00% (2017: 19.25%) of the
estimated assessable profit for the year of the UK subsidiary.
Deferred tax is provided for due to the temporary differences,
which give rise to such a balance in jurisdictions subject to
income tax. During the current period no taxable profits were made
in respect of the Group's Kurdistan PSC, nor were there any
temporary differences on which deferred tax is required to be
provided. As a result, no corporate income tax or deferred tax has
been provided for Kurdistan in the period.
All deferred tax arises in the UK.
The income / (expense) for the year can be reconciled to the
profit / (loss) per the income statement as follows:
2018 2017
$'000 $'000
----------------------------------------------- -------------------- -------
Profit before tax 79,700 14,065
==================== =======
Tax at the Bermudian tax rate of 0% (2017:0%) - -
Effect of different tax rates of subsidiaries
operating in other jurisdictions 189 61
-------------------- -------
Tax credit for the year 189 61
==================== =======
9. Profit per share
The calculation of the basic and diluted profit/(loss) per share
is based on the following data:
2018 2017
$'000 $'000
------- ---------
Profit
Profit after tax for the purposes of basic
and diluted profit per share 79,889 14,126
======= =========
2018 2017
Number Number
(000s) (000s)
------------------------------------------- ------- -------
Number of shares
Basic weighted average number of shares 229,317 229,317
The Group followed the steps specified by IAS 33 in determining
whether potential common shares are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
2018 2017
Number Number
(000s) (000's)
---------------------------------------------- ------- --------
Number of shares
Basic number of ordinary shares outstanding 229,317 229,317
Effect of dilutive potential ordinary shares 6,528 1,595
Diluted number of ordinary shares outstanding 235,845 230,912
------- --------
The average number of ordinary shares in issue excludes shares
held by Employee Benefit Trustee ("EBT") and the Exit Event
Trustee.
The diluted number of ordinary shares outstanding including
share options is calculated on the assumption of conversion of all
potentially dilutive ordinary shares. During the year ended 31
December 2018, there were 0.3 million (2017: 0.5m) share options
that were excluded from the calculation of diluted earnings because
they were anti-dilutive.
10. Intangible assets
Computer
software Total
$'000 $'000
----------------------------- --------- -------
Year ended 31 December 2017
Opening net book value 99 99
Amortisation charge (47) (47)
Foreign currency translation
differences 11 11
--------- -------
Closing net book value 63 63
At 31 December 2017
Cost 1,064 1,064
Accumulated amortisation (1,001) (1,001)
--------- -------
Net book value 63 63
--------- -------
Year ended 31 December 2018
Opening net book value 63 63
Additions 66 66
Disposals at cost (29) (29)
Amortisation charge (46) (46)
Amortisation of disposals 29 29
Foreign currency translation
differences 1 1
Closing net book value 84 84
======= =======
At 31 December 2018
Cost 1,102 1,102
Accumulated amortisation (1,018) (1,018)
------- -------
Net book value 84 84
======= =======
The amortisation charge of $46,000 (2017: $47,000) for computer
software has been included in general and administrative expenses
(note 4).
11. Property, plant and equipment
Oil and Gas Fixtures Total
Assets and $'000
$'000 Equipment
$'000
----------------------------------------- ----------- ---------- ---------
Year ended 31 December 2017
Opening net book value 488,634 745 489,379
Additions 8,059 114 8,173
Depreciation charge (79,785) (378) (80,163)
Foreign currency translation differences - 84 84
Closing net book value 416,908 565 417,473
=========== ========== =========
At 31 December 2017
Cost 693,146 5,941 699,087
Accumulated depreciation (276,238) (5,376) (281,614)
----------- ---------- ---------
Net book value 416,908 565 417,473
=========== ========== =========
Year ended 31 December 2018
Opening net book value 416,908 565 417,473
Additions 35,715 644 36,359
Disposals at cost (126,584) (399) (126,983)
Revision to decommissioning charge (2,229) - (2,229)
Depreciation charge (70,744) (337) (71,081)
Depreciation on disposals 126,584 399 126,983
Foreign currency translation differences - 15 15
Closing net book value 379,650 887 380,537
========= ======= =========
At 31 December 2018
Cost 600,048 6,201 606,249
Accumulated depreciation (220,398) (5,314) (225,712)
--------- ------- ---------
Net book value 379,650 887 380,537
========= ======= =========
The net book value of oil and gas assets at 31 December 2018 is
comprised of property, plant and equipment relating to the Shaikan
block and has a carrying value of $379.7 million (2017: $416.9
million).
The additions to the Shaikan asset during the year include costs
for the work on the export pipelines from both production
facilities to the main export pipeline, SH-1 workover, work in
preparation to the upcoming drilling campaign, production
facilities improvement work and various studies and reservoir
engineering.
The DD&A charge of $70.7 million on oil and gas assets
(2017: $79.8 million) has been included within cost of sales (note
3). The depreciation charge of $0.3 million on fixtures and
equipment (2017: $0.4 million) has been included in general and
administrative expenses (note 4).
Additions during the year include capitalised staff costs of
$4.0m (2017: $1.6m).
For details of the key assumptions and judgements underlying the
impairment assessment and the depreciation, depletion and
amortisation charge, refer to the "Critical accounting estimates
and judgments" section of the Summary of Significant Accounting
Policies.
12. Group companies
Details of the Company's subsidiaries and joint operations at 31
December 2018 is as follows:
Name of subsidiary Place of Proportion Principal
incorporation of ownership activity
interest
------------------------ --------------- -------------- -----------------
Gulf Keystone Petroleum United Kingdom 100% Management
(UK) Limited services,
6th floor including
New Fetter Place geological,
8-10 New Fetter Lane geophysical
London EC4A 1AZ and engineering
services
------------------------ --------------- -------------- -----------------
Gulf Keystone Petroleum Bermuda 100% Exploration
International Limited and evaluation
Cumberland House activities
9th floor, 1 Victoria in Kurdistan
Street
PO Box 1561
Hamilton HMFX
Bermuda
------------------------ --------------- -------------- -----------------
Name of joint operation Place of Proportion Principal
incorporation of ownership activity
interest
------------------------ --------------- -------------- -----------------
Shaikan Kurdistan 80%(1) Production
and development
activities
------------------------ --------------- -------------- -----------------
(1) 75% is held directly by Gulf Keystone Petroleum
International Limited, with 5% held in trust for Texas Keystone,
Inc. ("TKI") until formal transfer of the share is completed.
During the year the following subsidiaries were dissolved:
Gulf Keystone Petroleum Numidia Limited
Gulf Keystone Petroleum HBH Limited
Shaikan Petroleum Limited
13. Inventories
2018 2017
$'000 $'000
-------------------------------- ------- -------
Warehouse stocks and materials 13,534 14,569
Crude oil 656 2,621
------- -------
14,190 17,190
======= =======
Inventories at 31 December 2018 include write downs to net
realisable value of $0.6 million (2017: $0.4 million).
14. Trade and other receivables
2018 2017
$'000 $'000
-------------------------------- ------- -------
Trade receivables 61,251 57,887
Other receivables 5,405 3,260
Prepayments and accrued income 1,253 563
------- -------
67,909 61,710
======= =======
Trade receivables comprise invoiced amounts due from the MNR for
crude oil sales totalling $53.2 million as at 31 December 2018
(2017: $57.9 million), which have all been received subsequent to
the year end. This included past due trade receivables of $40.9
million (2017: $42.6 million). During 2018, the Group purchased a
share of Shaikan revenue arrears from MOL amounting to $9.1
million. In line with the requirements of IFRS 9, the fair value of
this receivable stood at $8.0 million as at 31 December 2018. The
adjustment to the fair value is recognised in Cost of sales (note
3).
Included within Other receivables for 2018 is an amount of $0.4
million (2017: $0.4 million) being the deposits for leased assets
which are receivable after more than one year. There are no
receivables from related parties as at 31 December 2018 (2017:
$nil) (see note 23). No impairments of other receivables have been
recognised during the year (2017: $nil).
The directors consider that the carrying amount of trade and
other receivables approximates to their fair value and no amounts
are provided against them.
15. Trade and other payables
Trade and other payables principally comprise amounts
outstanding for trade purchases and ongoing costs.
The directors consider that the carrying amount of trade
payables approximates their fair value.
2018 2017
$'000 $'000
----------------- ------ ------
Trade payables 11,857 2,687
Other payables 19,552 26,168
Accrued expenses 50,069 28,183
81,478 57,038
====== ======
There is $4.4 million interest payable included in Accrued
expenses as at 31 December 2018 (2017: $2.0m) (see note 16).
In 2018, Other payables included $10 million (2017: $10 million)
in relation to the Sheikh Adi PSC bonus that was payable on the
declaration of commerciality. It is likely that this liability will
be offset against unrecognised Shaikan revenue arrears, in
accordance with the principles agreed under the Bilateral Agreement
between the Group and the MNR. In 2017, the other payables balance
also included $16.2 million of payments received in excess of the
Group's revenue entitlements from the MNR under the Bilateral
Agreement. In 2018, this amount was transferred to revenue as an
offset of past revenue arrears.
16. Long term borrowings and warrants
2018 2017
$'000 $'000
------------------------------------------- --------- --------
Liability component at 1 January 99,084 98,886
Interest charged during the year 13,150 10,309
Interest paid during the year (7,713) (10,111)
Exchange or redemption of Reinstated Notes (100,000) -
Issue of New Notes at fair value 97,635 -
Liability component at 31 December 102,156 99,084
========= ========
Liability component reported in:
2018 2017
$'000 $'000
------------------------------------ -------- -------
Current liabilities: (see note 15) 4,361 2,017
Non-current liabilities 97,795 97,067
102,156 99,084
======== =======
On 14 October 2016, the Company issued $100 million of
guaranteed notes ("Reinstated Notes"). The unsecured Reinstated
Notes were guaranteed by Gulf Keystone Petroleum International
Limited, one of the Company's subsidiaries, and their key terms are
summarised as follows:
- maturity date was 18 October 2021. At any time prior to
maturity, the Reinstated Notes were redeemable in part or full at
par and could therefore be refinanced without any prepayment
penalty;
- the Company had the option to defer its interest payments
until the maturity of the Reinstated Notes in payment in kind at
13% or pay in cash at 10% until 18 October 2018. From 19 October
2018, the Company would be mandatorily liable to pay interest in
cash at 10%; and
- the Company was permitted to raise up to $45 million of
additional indebtedness at any time on market terms to fund capital
and operating expenditure.
In July 2018, the Group redeemed all of the $100 million
Reinstated Notes at a price equal to 100 per cent of the principal,
plus accrued and unpaid interest on the Notes up to and including
the Redemption Date. The Group also successfully completed the
private placement of a 5-year senior unsecured $100 million bond
issue (the "New Notes"). The unsecured New Notes are guaranteed by
Gulf Keystone Petroleum International Limited and Gulf Keystone
Petroleum (UK) Limited, two of the Company's subsidiaries, and
their key terms are summarised as follows:
- maturity date is 25 July 2023;
- at any time prior to maturity, the New Notes are redeemable in
part or full with a prepayment penalty;
- the interest rate is 10% per annum with semi-annual payment dates; and
- the Company is permitted to raise up to $200 million of
additional indebtedness at any time on market terms to fund capital
and operating expenditure.
The New Notes are traded on the Norwegian Stock Exchange and the
fair value at the prevailing market price as at the balance sheet
date was:
Market 2018 2017
price
$'000 $'000
------------------ --------- -------- -------
New Notes $102.75 102,750 -
Reinstated Notes $0.98241 - 98,241
102,750 98,241
======== =======
As of 31 December 2018, the Group's remaining contractual
liability comprising principal and interest based on undiscounted
cash flows at the maturity date of the New Notes is as follows:
2018 2017
$'000 $'000
------------------------- ------- -------
Within one year 10,000 10,000
Within two to five years 135,639 130,000
-------
145,639 140,000
======= =======
17. Provisions
2018 2017
$'000 $'000
----------------------- ------ ------
Current provisions 4,155 7,197
Non-current provisions 22,600 24,107
26,755 31,304
====== ======
Current Non-current
Provisions Provisions
(Algeria) (Kurdistan) Total
Decommissioning provision $'000 $'000 $'000
---------------------------------------- ----------- ------------ -------
At 1 January 2018 7,197 24,107 31,304
New provisions and changes in estimates - (2,230) (2,230)
Unwinding of discount - 723 723
Release of provisions (3,042) - (3,042)
At 31 December 2018 4,155 22,600 26,755
=========== ============ =======
The provision for decommissioning is based on the net present
value of the Group's share of expenditure which may be incurred in
the removal and decommissioning of the wells and facilities
currently in place and restoration of the sites to their original
state. The expenditure on the Shaikan block in Kurdistan is
expected to take place over the next 25 years.
In January 2019, the Group made a payment of $4.2 million in
final settlement of all Algerian decommissioning liabilities.
18. Deferred tax asset
The following are the major deferred tax liabilities and assets
recognised by the Group and movements thereon during the current
and prior reporting periods. The deferred tax assets arise in the
United Kingdom.
Accelerated Share-based Tax losses Total
tax depreciation payments carried $'000
$'000 $'000 forward
$'000
-------------------------- ----------------- ----------- ---------- ------
At 1 January 2017 (82) 36 356 310
(Charge)/credit to income
statement 21 92 (52) 61
Exchange differences (7) 8 31 32
----------------- ----------- ---------- ------
At 31 December 2017 (68) 136 335 403
(Charge)/credit to income
statement 37 202 (50) 189
Exchange differences 1 (18) (16) (33)
----------------- ----------- ---------- ------
At 31 December 2018 (30) 320 269 559
================= =========== ========== ======
19. Share capital
2018 2017
$'000 $'000
----------------------------------------- ------- -------
Authorised
Common shares of $1 each (2017: $1 each) 231,605 231,605
Non-voting shares of $0.01 each 500 500
Preferred shares of $1,000 each 20,000 20,000
Series A Preferred shares of $1,000 each 40,000 40,000
------- -------
292,105 292,105
======= =======
Common shares
-------------------------------------------------------
Share Share
No. of shares Amount capital premium
000 $'000 $'000 $'000
------------------------- ------------- ---------- ------------------- -------
Balance 31 December 2016 229,430 1,150,158 229,430 920,728
Balance 31 December 2017 229,430 1,150,158 229,430 920,728
Balance 31 December 2018 229,430 1,150,158 229,430 920,728
============= ========== =================== =======
At 31 December 2018, a total of 0.1 million common shares at
$1.0 each were held by the EBT (2017: 0.1 million at $1.0 each) and
0.1 million shares at $1.0 each were held by the Exit Event Trustee
(2017: 0.1 million at $1.0 each). All 0.2 million common shares
were included within reserves (2017: 0.2 million).
Rights attached to share capital
The holders of the common shares have the following rights
(subject to the other provisions of the Byelaws):
(i) entitled to one vote per common share;
(ii) entitled to receive notice of, and attend and vote at,
general meetings of the Company;
(iii) entitled to dividends or other distributions; and
(iv) in the event of a winding-up or dissolution of the Company,
whether voluntary or involuntary or for a reorganisation
or otherwise or upon a distribution of capital, entitled
to receive the amount of capital paid up on their common
shares and to participate further in the surplus assets
of the Company only after payment of the Series A Liquidation
Value (as defined in the Byelaws) on the Series A Preferred
Shares.
20. Reconciliation of Profit from operations to Cash generated
from operations
2018 2017
$'000 $'000
------------------------------------------ -------------------- ---------
Profit from operations 78,207 24,072
Adjustments for:
Depreciation, depletion and amortisation
of property, plant and equipment 71,081 80,163
Amortisation of intangible assets 46 47
Other gains or losses - (11)
Share-based payment expense 1,785 2,710
(Increase)/ decrease in inventories 3,000 (1,219)
(Increase) in receivables (4,330) (20,125)
Increase/ (decrease) in payables 11,695 (337)
-------------------- ---------
Cash generated from operations 161,483 85,300
==================== =========
The increase in receivable includes $8.0m relating to the
purchase of a share of Shaikan revenue arrears from MOL
21. Commitments
Operating lease commitments - the Group as a lessee
2018 2017
$'000 $'000
---------------------------------------------- ------ ------
Minimum lease payments under operating leases
recognised as expense for the year 2,019 2,924
====== ======
At the balance sheet date, the Group had outstanding total
commitments under non-cancellable operating leases, which fall due
as follows:
2018 2017
$'000 $'000
------------------------- --------- ---------------------
Within one year 2,264 1,144
Within two to five years 1,608 1,519
3,872 2,663
========= =====================
Operating lease payments represent rentals payable by the Group
for certain of its office and residence properties, facilities and
vehicle rentals in the United Kingdom and the Kurdistan Region of
Iraq. The non-cancellable operating leases within Kurdistan are up
to one year in duration.
Exploration and development commitments
Due to the nature of the Group's operations in exploring and
evaluating areas of interest and development of assets, it is
difficult to accurately forecast the nature or amount of future
expenditure.
Expenditure commitments on current permits for the Group could
be reduced by selective relinquishment of exploration tenure, by
the sale of assets or by the renegotiation of expenditure
commitments. Capital commitments of $29.9 million are expected in
the year ending 31 December 2019 for the Group (2018: $nil).
22. Share-based payments
2018 2017
$'000 $'000
--------------------- ------ ------
Share options charge 1,842 2,710
1,842 2,710
====== ======
Value Creation Plan
The VCP was approved by shareholders in December 2016 and, as of
31 December 2018, one award of Performance Units has been made to
the CEO and CFO. No further awards of Performance Units are
envisaged. Any outstanding awards under the VCP will be allowed to
run-off and vest subject to the Company achieving the performance
criteria of 8% compound annual growth in TSR on each of five annual
Measurement Dates and the plan limits in place, in accordance with
the VCP rules. As such, it may be possible that additional
conversions of the Performance Units into nil-cost options may
occur in future (up to but not later than 2022).
Following the first measurement date on 15 May 2018, nil-cost
options over 1,681,839 shares were granted to each of the CEO and
CFO. The Executive Directors are not eligible to participate in any
other long-term incentive scheme until the VCP has ended
2018 2017
Number of Weighted Number of Weighted
share options average share options average
'000 exercise '000 exercise price
price (in pence)
(in pence)
--------------------------- ---------------------- ----------- --------------- ---------------
Outstanding at 1 January - - - -
Granted during the
year 3,364 - - -
Outstanding at 31 December 3,364 - - -
Exercisable at 31 December - - - -
====================== =========== =============== ===============
Depending on the achievement of the performance criteria, the
nil-cost options will vest as follows: 50% in May 2020, 25% in May
2021, and 25% in May 2022.
A charge of $0.6 million (2017: $1.1 million) in relation to the
VCP is included in the total share options charge.
Staff Retention Plan
At the 2016 Annual General Meeting, shareholders approved the
adoption of the Gulf Keystone Petroleum 2016 Staff Retention Plan
("SRP"), which is designed to reward members of staff through the
grant of share options at a zero exercise price.
The exercise of the awarded options is not subject to any
performance conditions and can be exercised at any time after the
three year vesting period but within ten years after the date of
grant. If options are not exercised within ten years, the options
will lapse and will not be exercisable. If an employee leaves the
company during the three years from the date of grant, the options
will lapse on the date notice to leave is given to the company.
Should an employee be regarded as a good leaver, the options may be
exercised at any time within a period of six months from departure
date.
2018 2017
Number of Weighted Number of Weighted
share options average share options average
'000 exercise '000 exercise price
price (in pence)
(in pence)
--------------------------- ---------------------- ----------- --------------- ---------------
Outstanding at 1 January 1,595 - 1,402 -
Granted during the
year - - 611 -
Exercised during the
year - - (325) -
Forfeited during the
year (155) - (93) -
Outstanding at 31 December 1,440 - 1,595 -
Exercisable at 31 December - - - -
====================== =========== =============== ===============
The options outstanding at 31 December 2018 had a weighted
average remaining contractual life of 8 years.
During 2018 no options (2017: 611,000) were granted to employees
under the Group's SRP.
The inputs into the stochastic (binomial) valuation model were
as follows:
2018 2017
--------------------------------------------- ------------------ ------
Weighted average opening share price on date
of grant (in pence) n/a 119.47
The expected volatility was calculated as 97.2% for the January
2017 awards, 94.0% for the early July 2017 awards, 94.1% for the
July 2017 awards and has been based on the Company's share price
volatility averaged for the three years prior to grant date.
The expected weighted average term of the SRP options is 3
years. The risk free rate for the options awarded was 0.26% for
January 2017 awards, 0.43% for early July 2017 and 0.32% for late
July 2017.
The weighted average fair value of the options granted in 2017
was GBP1.19.
The Company has not made a dividend payment to date and, as
there was no expectation of making payments in the immediate future
following grants of the SRP options in 2016 and 2017 the dividend
yield variable has been set at zero for all grants.
A charge of $0.8 million (2017: $0.9 million) in relation to the
SRP is included in the total share options charge.
Share options outstanding at the end of the year have the
following expiry date and exercise prices:
Expiry date Exercise price
(pence) Options ('000)
2018 2017 2018 2017
11 December 2026 - - 939 994
09 January 2027 - - 250 350
30 June 2027 - - 206 206
30 July 2027 - - 45 45
1,440 1,595
======== =======
Long Term Incentive option plan
At the 2016 Annual General Meeting, shareholders approved the
adoption of the Gulf Keystone Petroleum 2016 Long Term Incentive
Plan ("LTIP"), which is designed to reward members of staff through
the grant of share options at a zero exercise price, that vests
three years after grant, subject to the fulfilment of specified
performance conditions. These performance conditions attached to
the 2018 LTIP grant are 50% Group's Total Shareholder Return
("TSR") over the vesting period and 50% the Group's TSR relative to
a bespoke group of comparators.
2018 2017
Number of Weighted Number of Weighted
share options average share options average
'000 exercise '000 exercise price
price (in pence)
(in pence)
--------------------------- ---------------------- ----------- --------------- ---------------
Outstanding at 1 January - - - -
Granted during the
year 1,786 - - -
Forfeited during the
year (172) - - -
Outstanding at 31 December 1,614 - - -
Exercisable at 31 December - - - -
====================== =========== =============== ===============
A charge of $0.5 million (2017: nil million) in relation to the
LTIP is included in the total share options charge.
Equity-settled share option plan
The Group's share option plan provides for an exercise price at
least equal to the closing market price of the Group shares on the
date prior to grant. Awards made under the Group's share option
plan have a vesting period of at least three years except for
awards made under the legacy Long Term Incentive Plan, which vest
in equal tranches over a minimum of three years subsequent to the
achievement of a number of operational and market-based performance
conditions. Options expire if they remain unexercised after a
period of 10 years from the date of grant. The options granted in
2015 were made under the recruitment remuneration policy, vest in
three equal tranches over two years, and expire if they remain
unexercised after a period of 7 years from the date of grant.
Options are forfeited if the employee leaves the Group before the
options vest. The company has not made any awards during 2018 under
this scheme.
2018 2017
Number of Weighted Number of Weighted
share options average share options average
'000 exercise '000 exercise price
price (in pence)
(in pence)
Outstanding at 1 January 360 10,149.7 360 10,190.0
Expired during the
year (34) - - -
Outstanding at 31 December 326 11,492.6 360 10,149.7
Exercisable at 31 December 326 11,492.6 360 10,149.7
=============== =========== =============== ===============
No options were exercised, granted or cancelled in 2018 (2017:
nil).
The options outstanding at 31 December 2018 had a weighted
average exercise price of GBP115 (2017: GBP102) and a weighted
average remaining contractual life of 2 years (2017: 3 years).
A charge of nil (2017: $0.69 million) in relation to the
equity-settled share option plan is included in the total share
options charge.
Share options outstanding at the end of the year have the
following expiry date and exercise prices:
Expiry date Exercise price (pence) Options ('000)
2018 2017 2018 2017
13 February 2018 3,000 3,000 - 11.0
24 September 2018 3,000 3,000 - 20.1
15 March 2019 3,000 3,000 15.9 15.9
30 July 2019 3,000 3,000 10.0 10.0
24 Jun 2020 7,500 7,500 156.3 156.3
22 September 2020 14,750 14,750 2.5 2.5
10 October 2020 17,500 17,500 - 2.5
6 February 2021 17,500 17,500 94.4 94.4
19 June 2021 14,625 14,625 5.5 5.5
7 July 2021 14,625 14,625 2.5 2.5
14 July 2021 14,625 14,625 2.5 2.5
21 July 2021 14,625 14,625 5.0 5.0
19 September 2021 15,250 15,250 2.5 2.5
26 October 2021 14,625 14,625 2.5 2.5
21 January 2022 5,500 5,500 15.0 15.0
20 March 2022 19,450 19,450 4.0 4.0
20 March 2022 25,000 25,000 2.5 2.5
8 July 2023 15,875 15,875 2.5 2.5
24 April 2024 9,975 9,975 2.5 2.5
326.1 359.7
======== =======
Exit Event Awards
In March 2012, the Remuneration Committee recommended that the
Company make cash settled awards to certain Executive Directors and
employees conditional on the occurrence of an Exit Event (as
defined below) up to a maximum amount equivalent to the value of
0.1 million common shares (adjusted for consolidation on 100:1
basis) at the time of an Exit Event. A trustee (the "Exit Event
Trustee") was appointed to hold and, subject to the occurrence of
an Exit Event, to sell sufficient common shares to satisfy the Exit
Event Awards.
As at 31 December 2018, the Exit Event Trustee held 0.1 million
common shares to satisfy any future Exit Event Awards to full-time
employees of the Company and subsidiary companies, subject to the
occurrence of an Exit Event, with such beneficiaries to be
determined in due course. Any Exit Event awards previously made to
the Directors and employees of the Group have expired.
An Exit Event envisages a sale of either the Company or a
substantial proportion (i.e. more than 50%) of its assets.
23. Related party transactions
The Group has a related party relationship with its
subsidiaries. The Company and its subsidiaries, in the ordinary
course of business, enter into various sales, purchase and service
transactions with joint operations in which the Group has a
material interest. These transactions are under terms that are no
less favourable to the Group than those arranged with third
parties.
Remuneration of key management personnel
The remuneration of the Directors and Officers, the key
management personnel of the Group, is set out below in aggregate
for each of the categories specified in IAS 24 Related Party
Disclosures. Those identified as key management personnel include
the Directors of the Company and the following key personnel:
J Barker - HR Director
S Catterall - Chief Operations Officer
B Demont - Development Manager - Kurdistan Region of Iraq
N Kernoha - Head of Finance
W McAvock - Financial Controller
G Papineau-Legris - Commercial Director
A Robinson - Legal Director & Company Secretary
The values below are calculated in accordance with IAS 19 and
IFRS 2.
2018 2017
$'000 $'000
------------------------------ ------ ------
Short-term employee benefits 5,444 6,514
Share-based payment - options 1,132 1,630
6,576 8,144
====== ======
Further information about the remuneration of individual
Directors is provided in the Directors' Emoluments section of the
Remuneration Committee Report.
24. Financial instruments
2018 2017
$'000 $'000
-------------------------- ------- -------
Financial assets
Cash and cash equivalents 295,566 160,456
Loans and receivables 66,656 61,148
362,222 221,604
======= =======
Financial liabilities
Trade and other payables 81,478 57,038
Borrowings 97,795 97,067
179,273 154,105
======= =======
All loans and payables, except for the New Notes, are due to be
settled within one year and are classified as current
liabilities.
The maturity profile and fair values of the New Notes are
disclosed in note 16. The maturity profile of all other financial
liabilities is indicated by their classification in the balance
sheet as "Current" or "Non-current". Further information relevant
to the Group's liquidity position is disclosed in the Directors'
Report under "Going Concern".
Fair values of financial assets and liabilities
With the exception of the New Notes, the Group considers the
carrying value of all its financial assets and liabilities to be
materially the same as their fair value. The fair value of the New
Notes, as determined using market values at 31 December 2018, was
$102.8 million (2017: Reinstated Notes $98.2 million) compared to
the carrying value of $97.8 million (2017: Reinstated Notes $97.1
million).
No material financial assets are impaired at the balance sheet
date. All financial assets and liabilities, with the exception of
derivatives, are measured at amortised cost.
Capital Risk Management
The Group manages its capital to ensure that the entities within
the Group will be able to continue as going concerns while
maximising the return to stakeholders through the optimisation of
the debt and equity balance. The capital structure of the Group
consists of cash, cash equivalents, New Notes and equity
attributable to equity holders of the parent. Equity comprises
issued capital, reserves and accumulated losses as disclosed in
Note 19, the Consolidated Statement of Comprehensive Income and the
Consolidated Statement of Changes in Equity.
Capital Structure
The Group's Board of Directors reviews the capital structure on
a regular basis and will make adjustments in light of changes in
economic conditions. As part of this review, the Board considers
the cost of capital and the risks associated with each class of
capital.
Significant Accounting Policies
Details of the significant accounting policies and methods
adopted, including the criteria for recognition, the basis of
measurement and the basis on which income and expenses are
recognised, in respect of each class of financial asset, financial
liability and equity instrument, as well as the impact of adoption
of IFRS 9, are disclosed in the Summary of Significant Accounting
Policies.
Financial Risk Management Objectives
The Group's management monitors and manages the financial risks
relating to the operations of the Group. These financial risks
include market risk (including commodity price, currency and fair
value interest rate risk), credit risk, liquidity risk and cash
flow interest rate risk.
The Group currently has no currency risk or other hedges against
financial risks as the benefit of entering into such agreements is
not considered to be significant enough to outweigh the significant
cost and administrative burden associated with such hedging
contracts. The Group does not use derivative financial instruments
for speculative purposes.
The risks are closely reviewed by the Board on a regular basis
and steps are taken where necessary to ensure these risks are
minimised.
Market risk
The Group's activities expose it primarily to the financial
risks of changes in foreign currency exchange rates, oil prices and
changes in interest rates in relation to the Group's cash
balances.
There have been no changes to the Group's exposure to other
market risks or any changes to the manner in which the Group
manages and measures the risk. The Group does not hedge against the
effects of movement in oil prices or foreign currency rates. The
risks are monitored by the Board on a regular basis.
The Group conducts and manages its business predominantly in US
dollars, the operating currency of the industry in which it
operates. The Group also purchases the operating currencies of the
countries in which it operates routinely on the spot market. Cash
balances are held in other currencies to meet immediate operating
and administrative expenses or to comply with local currency
regulations.
At 31 December 2018, a 10% weakening or strengthening of the US
dollar against the other currencies in which the Group's monetary
assets and monetary liabilities are denominated would not have a
material effect on the Group's net current assets or profit before
tax.
Interest rate risk management
The Group's policy on interest rate management is agreed at the
Board level and is reviewed on an ongoing basis. The current policy
is to maintain a certain amount of funds in the form of cash for
short-term liabilities and have the rest on relatively short-term
deposits, usually between one and three months, to maximise returns
and accessibility. The Group must pay interest on its New Notes
semi-annually in cash at 10%.
Based on the exposure to the interest rates for cash and cash
equivalents at the balance sheet date, a 0.5% increase or decrease
in interest rates would not have a material impact on the Group's
profit for the year or the previous year. A rate of 0.5% is used as
it represents management's assessment of a reasonable change in
interest rates.
Credit risk management
Credit risk refers to the risk that a counterparty will default
on its contractual obligations resulting in financial loss to the
Group. As at 31 December 2018, the maximum exposure to credit risk
from a trade receivable outstanding from one customer is $61
million (2017: $60 million).
The credit risk on liquid funds is limited because the
counterparties for a significant portion of the cash and cash
equivalents at the balance sheet date are banks with good credit
ratings assigned by international credit-rating agencies.
Liquidity risk management
Ultimate responsibility for liquidity risk management rests with
the Board of Directors. It is the Group's policy to finance its
business by means of internally generated funds, external share
capital and debt. In common with many exploration companies, the
Group raises finance for its exploration and appraisal activities
in discrete tranches to finance its activities for limited periods.
The Group seeks to raise further funding as and when required.
25. Contingent liabilities
The Group has a contingent liability of $27 million (2017: $27
million) in relation to the proceeds from the sale of test
production in the period prior to the approval of the Shaikan Field
Development Plan ("FDP") in July 2013. The Shaikan PSC does not
appear to address expressly any party's rights to this pre-FDP
petroleum. This suggests that there must have been some other
agreement, understanding or arrangement between GKP and the KRG as
to how this pre-FDP petroleum would be lifted and sold. The sales
were made based on sales contracts with domestic offtakers which
were approved by the KRG. The Group believes that the receipts from
these sales of pre-FDP petroleum are for the account of the
Contractor (GKP and MOL), rather than the KRG and accordingly
recorded them as test revenue in prior years. However, the KRG has
requested a repayment of these amounts and the Group is currently
involved in negotiations to resolve this matter. The Group has
received external legal advice and does not consider that a
probable material payment is payable to the KRG. This contingent
liability forms part of the ongoing Shaikan PSC amendment
negotiations and it is likely that it will be settled as part of
those negotiations.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
END
FR CKODDBBKBBNB
(END) Dow Jones Newswires
March 28, 2019 03:02 ET (07:02 GMT)
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