TIDMGKP
RNS Number : 4715G
Gulf Keystone Petroleum Ltd.
30 March 2022
30 March 2022
Gulf Keystone Petroleum Ltd. (LSE: GKP)
("Gulf Keystone", "GKP", "the Group" or "the Company")
2021 Full Year Results Announcement
Gulf Keystone, a leading independent operator and producer in
the Kurdistan Region of Iraq, today announces its results for the
full year ended 31 December 2021.
Jon Harris, Gulf Keystone's Chief Executive Officer, said:
"I am pleased to report a year of strong operational and
financial delivery in 2021. With a 19% increase in gross average
production to 43,440 bopd, our leverage to the recovery in oil
prices and continued cost and capital discipline, we generated
substantial revenue and free cash flow.
We continued to deliver on our strategy of balancing investment
in sustainable growth and shareholder returns, as we resumed
drilling activities and submitted a draft Field Development Plan to
the Ministry of Natural Resources while also returning $100 million
of dividends to our shareholders in 2021. Following the $50 million
dividend that we paid in February 2022, we are pleased to announce
today the declaration of an additional $90 million of dividends.
This brings aggregate shareholder distributions declared since 2019
to $340 million.
Looking ahead to the remainder of 2022, we remain focused on
delivering gross annual production of 44,000-50,000 bopd by
bringing SH-15 online in Q2 2022 and optimising production with
well interventions and workovers. While constructive engagement
continues with the MNR on the FDP, timing of approval remains
uncertain and further progress is required before we fully execute
FDP activity.
Following my first year as GKP's CEO, I would like to personally
thank the Company's teams in Kurdistan and the UK for all of their
efforts. We are in a strong position and I am excited about safely
delivering the significant growth potential of the Shaikan Field to
drive sustainable value for all of our stakeholders."
Highlights to 31 December 2021 and post reporting period
Operational
-- Continued strong focus on safety in 2021 despite one
previously reported lost time incident ("LTI"); currently no LTIs
recorded for over 160 days
-- Third consecutive year of production growth with 2021 gross
average production of 43,440 bopd, towards the upper end of our
tightened guidance range of 42,000-44,000 bopd and a 19% increase
versus 2020
-- 2022 YTD gross average production of c.45,500 bopd, following
milestone achievement in February 2022 of 100 MMstb cumulative
production since inception
-- Successfully restarted drilling activities in June, resulting
in two new wells, SH-13 and SH-14, coming online towards the end of
the year
-- After acid stimulations, current SH-13 production in line
with expectations while we continue to explore options to further
increase SH-14 production
-- Following the early appearance of trace quantities of water,
SH-12 is currently shut-in while we investigate near-term
production options ahead of installation of planned water handling
facilities
-- Spudded SH-15, which is currently being hooked up ahead of targeted start-up in Q2 2022
Draft Shaikan Field Development Plan ("FDP")
-- Submitted draft FDP to Ministry of Natural Resources in
November 2021 comprising plan to increase Phase 1 gross production
plateau to between 85,000-95,000 bopd while eliminating routine
flaring and significantly reducing carbon intensity
-- While final timing of approval remains uncertain due to the
complexity of the project, we are providing today an interim update
on progress to date on Phase 1 of the draft FDP. As we continue to
review opportunities to further optimise the project, final details
and cost estimates may vary and we expect to provide an update upon
FDP approval
-- Expected components of Phase 1 of draft FDP:
o Expand Jurassic gross production plateau up to 85,000 bopd
o Test Triassic reservoir, targeting gross production plateau of
up to 10,000 bopd
o Concurrently, execute Gas Management Plan to eliminate routine
flaring through gas reinjection, underpinning target of more than
halving scope 1 and 2 emissions per barrel by 2025
-- From FDP approval, expected duration of Phase 1 Jurassic and
Triassic projects is 36 to 42 months and the Gas Management Plan is
18 to 24 months
-- Total Phase 1 gross Capex currently estimated to be $800-$925
million, up c.$160 million from previous FDP with the objective of
increasing production towards 95,000 bopd through project
optimisations
Financial
-- Strong free cash flow generation of $122.2 million (2020: $(22.9) million)
-- Total dividends of $100 million paid in 2021, including a
2020 annual dividend of $25 million, a special dividend of $25
million and an interim dividend for 2021 of $50 million. An
additional $50 million interim dividend was paid to shareholders in
February 2022
-- Revenue almost tripled to $301.4 million (2020: $108.4
million), contributing to a return to profit after tax of $164.6
million (2020: $47.3 million loss)
-- Adjusted EBITDA increased by almost four times to $222.7
million (2020: $56.7 million) driven by higher gross production,
leverage to the recovery in oil prices and the Company's continued
strict control of costs:
o Gross average production increased 19% to 43,440 bopd (2020:
36,625 bopd)
o Realised price more than doubled to $49.7/bbl (2020:
$20.9/bbl)
o Gross Opex per barrel of $2.7/bbl (2020: $2.6/bbl), in line
with 2021 guidance of $2.5-$2.9/bbl
-- Revenue receipts of $221.7 million in 2021 from the KRG for
crude oil sales related to the December 2020 to August 2021
invoices and partial repayment of arrears related to the
outstanding November 2019 to February 2020 invoices
-- Since the beginning of 2022, the Company has received a
further $106.4 million net to GKP for crude oil sales and arrears
related to the September 2021 to November 2021 invoices. As at 29
March 2022, the outstanding arrears balance is $21.9 million net to
GKP
-- Net Capex of $50.8 million (2020: $45.9 million), primarily
related to the completion of the SH-13 and SH-14 wells and
debottlenecking of PF-2
-- Robust cash balance of $182.7 million at 29 March 2022
Outlook
-- Remain focused on delivering 2022 gross average production of
44,000-50,000 bopd reflecting the anticipated production
contribution from SH-15 and the benefits of well intervention and
workover activities
-- 2022 net capital expenditure guidance of $85-$95 million:
o Includes completion of SH-15 drilling, well interventions and
workovers, and activity that enables us to expedite the FDP
following approval
o With progress on the FDP, the Company expects to resume
drilling and increase 2022 capital guidance
-- Gross Opex guidance of $2.9-$3.3/bbl, driven by increased
operational activity and the continued catch up of previously
scheduled work programmes deferred due to COVID-19
-- Today declaring $90 million of dividends, representing
further delivery against GKP's strategic commitment of balancing
investment in sustainable growth with shareholder returns:
o $25 million final 2021 ordinary dividend subject to approval
at AGM on 24 June 2022
o $65 million interim dividend, expected to be paid on 13 May
2022, based on a record date of 29 April 2022 and ex-dividend date
of 28 April 2022
o The Company will disclose the US dollar and pounds sterling
rate per share for both dividends prior to their ex-dividend
dates
-- Assuming timely payment of invoices and continuing strong oil
prices, we are expecting strong cash flow generation in 2022. This
would provide flexibility to fund a potential increase in capital
expenditure, with progress on the FDP, and the opportunity for
further distributions to shareholders, while preserving adequate
liquidity and maintaining a robust balance sheet
Investor & analyst presentation
Gulf Keystone's management team will be presenting the Company's
2021 Full Year Results at 10:00am (BST) today via live audio
webcast:
https://webcasting.brrmedia.co.uk/broadcast/6221e42cfa16d9059b846ad1
This announcement contains inside information for the purposes
of the UK Market Abuse Regime.
Enquiries:
Gulf Keystone: +44 (0) 20 7514 1400
Aaron Clark, Head of Investor Relations aclark@gulfkeystone.com
Celicourt Communications: + 44 (0) 20 8434 2754
Mark Antelme GKP@Celicourt.uk
Jimmy Lea
or visit: www.gulfkeystone.com
Notes to Editors:
Gulf Keystone Petroleum Ltd. (LSE: GKP) is a leading independent
operator and producer in the Kurdistan Region of Iraq. Further
information on Gulf Keystone is available on its website
www.gulfkeystone.com
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
2021 was characterised by both an improvement in the oil price
and operational environment. The price of Dated Brent averaged
$71/bbl in the year, up $29/bbl versus the 2020 average, driven by
the partial recovery of global demand and the continued regulation
by OPEC+ of supply. At the same time, COVID-19 restrictions
gradually loosened, with a return to more normal working patterns
in the Field. Having taken rapid action in 2020 to protect staff,
reduce costs and preserve liquidity, the Company was able to
capitalise on these better conditions.
Since the beginning of the year, the price of Brent Crude has
continued to increase, although it remains volatile. While the
improvement in oil price drives increased cash flow, I and the
Board are deeply concerned about the primary reason for the
increase, the invasion of Ukraine. Our thoughts are with the many
Ukrainian citizens who have had to flee their homes or have lost
their lives due to the conflict.
In 2021, Gulf Keystone generated significant cash flow due to
its strong leverage to the recovery in oil price, increased
production and continued cost and capital discipline. In line with
the Company's strategy of balancing investment in sustainable
growth with shareholder distributions, in March 2021 the Board
reinstated the Company's dividend policy of paying at least $25
million annually to shareholders. Total dividends of $100 million
were subsequently paid in 2021, given continuing strong oil prices
and cash generation.
Since the beginning of 2022, Gulf Keystone has paid a $50
million interim dividend and we are pleased to have declared $90
million of additional dividends, comprising a $25 million 2021
annual ordinary dividend for shareholder approval at the Company's
AGM on 24 June 2022 and a $65 million interim dividend payable in
May 2022. Including these, prior dividends and $50 million of share
buybacks, since 2019 the Company has distributed $340 million to
shareholders.
Capitalising on a strong balance sheet and improving operating
conditions, the Company also resumed investment in the Shaikan
Field, restarting drilling activities ahead of schedule in June and
bringing two new wells, SH-13 and SH-14, onstream by the end of the
year. The Company also resumed engagement with the MNR on Gulf
Keystone's vision to develop the Shaikan Field's almost 800 MMstb
of 2P reserves and 2C resources, resulting in the submission of a
draft Field Development Plan towards the end of 2021.
Phase 1 of the draft FDP is expected to enable Gulf Keystone to
increase gross production plateau to between 85,000-95,000 bopd
while reducing carbon intensity per barrel by over 50% through the
implementation of a Gas Management Plan. We are committed to
ensuring the FDP generates significant value for all of Gulf
Keystone's stakeholders. We continue to actively engage the MNR to
obtain approval of the draft FDP and in the meantime have focused
our capital expenditure programme for 2022 on production, safety
and preparatory activities.
Sustainability continues to be a strategic focus for the Board,
which is supported by Gulf Keystone's Safety and Sustainability
Committee. With the submission of the draft FDP, the Board was
pleased to see the Company's Gas Management Plan, and its
objectives of reducing carbon intensity and eliminating routine
flaring, move a step closer. The Company also continued to make
significant social and economic contributions to Kurdistan through
local employment and community engagement programmes, local supply
chain investment and generation of revenues from the field for our
host government, the KRG.
The Board continued to engage with Gulf Keystone's shareholders
in 2021, both at the Annual General Meeting and on a more frequent
basis with the Company's major shareholders. We welcome ongoing
engagement and feedback from all investors and encourage all GKP
shareholders to participate in our 2022 AGM. This year, the
Company's remuneration policy will be subject to a binding
shareholder vote at the AGM. The Board has made minor changes to
the current policy, which was approved at the 2019 AGM with support
in excess of 98%.
The only change to the Board over the last year was the
appointment of Jon Harris as Gulf Keystone's new CEO in January
2021. Jon has been instrumental in successfully resuming investment
in the Shaikan Field and advancing negotiations with the MNR as we
seek approval of the FDP.
On behalf of the Board, I would like to thank Jon, the rest of
the leadership team and all of Gulf Keystone's employees for
another strong year of operational and financial delivery. In
addition, I would like to thank all of our stakeholders for their
ongoing support. We are excited about the future and we look
forward to further progress in driving sustainable growth and value
from the Shaikan Field for the benefit of all of Gulf Keystone's
stakeholders.
Jaap Huijskes
Non-Executive Chairman
CEO review
I am pleased to report strong operational and financial delivery
for Gulf Keystone in 2021. By growing production from the Shaikan
Field and maintaining our rigorous focus on cost and capital
discipline, we were able to capitalise on our leverage to an
improving oil price and generate revenue of $301 million and
adjusted EBITDA of $223 million. We delivered on our strategy of
balancing investment in sustainable growth and shareholder returns,
as we resumed drilling activities and submitted a draft Field
Development Plan to the Ministry of Natural Resources while also
returning $100 million of dividends to our shareholders.
The foundation of our performance is a rigorous focus on safety,
which is one of Gulf Keystone's core values. Despite carefully
managing the resumption of drilling activities, we were
disappointed to record an LTI in October. We are committed to
continuous learning and carried out detailed investigations and
implemented remedial actions to safeguard against future
incidents.
Gross average production in 2021 was 43,440 bopd, at the top end
of our tightened guidance range of 42,000-44,000 bopd. This
represented a 19% increase versus the prior year and the third
consecutive year of production growth. Higher production was driven
by the contribution from well workovers taking place in 2020 and
2021 and the contribution of two new wells, SH-13 and SH-14, at the
end of the year.
We were pleased to successfully restart drilling activities in
June ahead of schedule. Despite a promising start, the need for an
acid stimulation programme on SH-13 and equipment failures and
wellbore issues in the subsequent side-track on SH-14 created
delays. Nonetheless, we were able to surmount these challenges to
bring SH-13 and SH-14 onstream towards the end of the year and spud
SH-15 in early 2022.
We also continued to progress development of the full potential
of the Shaikan Field's significant reserves and resources with the
submission of a draft Field Development Plan to the Ministry of
Natural Resources towards the end of 2021. This was the result of
several months of constructive engagement with the MNR and our
partner MOL following the resumption of discussions in 2021.
The draft FDP comprises a plan to increase Phase 1 gross
production plateau to between 85,000-95,000 bopd while
significantly reducing our carbon intensity. We plan to achieve
this by expanding Jurassic gross production plateau up to 85,000
bopd and testing the Triassic reservoir, targeting gross production
plateau of up to 10,000 bopd. At the same time, we will implement a
Gas Management Plan to eliminate routine flaring through the
reinjection of natural gas into the reservoir, underpinning our
target to more than halve our scope 1 and 2 emissions per barrel by
2025. The Gas Management Plan is critical to our licence to operate
in Kurdistan and responds to both GKP's and the KRG's desire to
eliminate routine flaring and reduce the emissions intensity of the
region's production.
In keeping with our commitment to eliminate routine flaring, we
have applied to endorse the World Bank's "Zero Routine Flaring by
2030" initiative. Beyond the Gas Management Plan, we are exploring
the viability of several other projects to reduce our scope 1 and 2
emissions intensity further beyond the 2025 target.
Our focus on climate risk is just one part of our ESG agenda and
sustainability strategy. Our other priorities include working
safely, minimising our impact on the local environment, supporting
and developing our people, generating economic value in Kurdistan
and maintaining strong governance and compliance. We are
particularly proud of our social and economic contribution to
Kurdistan, our home for over 15 years, and see significant
opportunities from the FDP for further local job creation,
workforce development and investment in our local supply chain and
communities as we generate increasing revenues for the KRG and the
region from the Shaikan Field. In 2021, $356 million was generated
for the KRG, primarily from production entitlements, royalties and
capacity building payments.
While we continued to invest in growth in 2021, we also
delivered against our strategic commitment to balance growth with
shareholder returns. We understand the importance of cash returns
to our shareholders and we were pleased to reinstate our dividend
policy of distributing at least $25 million annually, subsequently
distributing total dividends in the year of $100 million. Since the
beginning of 2022, we have distributed a further $50 million and we
are delighted to declare $90million of additional dividends
comprising a $25 million 2021 ordinary annual dividend for
shareholder approval at the Company's AGM on 24 June 2022 and a $65
million interim dividend payable in May 2022.
We have entered 2022 with momentum and hit the milestone in
February of 100 MMstb cumulative gross production from the Field
since inception. Gross average production year to date has been
around c.45,500 bopd, and we remain focused on delivering our 2022
gross average production guidance of 44,000-50,000 bopd.
As a Company, we are deeply saddened and concerned about the
invasion of Ukraine and the resulting humanitarian crisis. Our
thoughts are with the people of Ukraine and we are all hoping for a
swift and peaceful end to the conflict.
While there has been no impact on our operations to date, we are
closely monitoring the developing situation in Ukraine. This
includes potential sanctions being imposed on Russian entities,
which could adversely impact our business.
We also continue to monitor the broader political and regulatory
environment in the Kurdistan Region and Federal Iraq following the
recent ruling by the Iraqi Federal Supreme Court regarding the
Kurdistan Region Oil & Gas Law. We have noted the KRG's strong
opposition to the ruling and agreement by both the KRG and the
Federal Government to engage on what has been a longstanding issue.
To date, we have seen no impact from the ruling on our
business.
While the timing of approval of the FDP is uncertain given the
scale of the project, constructive engagement continues with the
MNR, and further progress is required before we fully execute FDP
activity including drilling beyond SH-15. For the remainder of
2022, we are focused on executing activity that enables us to
expedite the FDP following approval. This includes activities to
prepare for expansion of our production facilities to include water
handling and preparation of well pads and installation of flowlines
to enable a continuous drilling programme. We are also focused on
well interventions and workovers. Net capital expenditure guidance
for 2022 is $85-$95 million.
We are targeting gross Opex of $2.9-$3.3/bbl, with the increase
versus 2021 primarily due to increased operational activity and the
continued catch up of previously scheduled work programmes deferred
due to COVID-19.
Assuming timely payment of invoices and continuing strong oil
prices, we are expecting strong cash flow generation in 2022. This
would provide flexibility to fund a potential increase in capital
expenditure, with progress on the FDP, and the opportunity for
further distributions to shareholders, while preserving adequate
liquidity and maintaining a robust balance sheet.
I would like to thank the teams in Kurdistan and the UK for
their hard work and contributions to a strong year of performance.
I would also like to give my thanks to our Chief Operating Officer,
Stuart Catterall, who has retired from Gulf Keystone after five
years with the Company. Stuart has helped us steer the Company
through a volatile oil price cycle and the COVID-19 pandemic,
enabling us to emerge stronger and more focused on driving
sustainable value from the Shaikan Field.
Stuart will be succeeded by John Hulme who joins us end April
from Noreco where he was their COO. John brings a wealth of
experience from more than 30 years in the industry, previously
working at Exxon, Anadarko, Santos and Newfield. I look forward to
welcoming John to GKP.
Jon Harris
Chief Executive Officer
Operational review
Gulf Keystone's operational performance was solid in 2021, with
a continued increase in production, the successful resumption of
drilling activities and the submission of a draft Field Development
Plan to the MNR.
As ever, a rigorous focus on safety underpinned all our
activity. As drilling restarted, we took extra precautions to
ensure all drilling and operational staff on site were prepared.
Unfortunately, we were disappointed to incur one LTI during
drilling operations after over 660 LTI-free days.
Following a challenging year in 2020 from the COVID-19 pandemic,
the rollout of vaccinations in 2021 facilitated a gradual
improvement in operating conditions. We were pleased to see 97% of
our staff get double vaccinated in the year following a successful
awareness campaign. This enabled us to ease health protocols on
site, including a move from three shifts back to two, although
access to our offices in Erbil and London remained restricted with
employees encouraged to work from home.
We achieved gross average production of 43,440 bopd in 2021,
towards the upper end of our tightened guidance range of
42,000-44,000 bopd and a 19% increase versus 2020. Higher
production was driven by a full year of production from SH-9, the
successful workover of SH-12 towards the end of 2020 and enhanced
production from the installation in 2021 of a multiphase pump on
SH-5 and a jet pump in SH-10. We also completed two new wells,
SH-13 and SH-14, towards the end of 2021. Both plant and pipeline
uptime remained high at above 99%.
Following an extended hiatus in 2020 due to the COVID-19
pandemic, we successfully restarted drilling activities in June
2021 ahead of schedule. Rapid mobilisation was made possible by a
cohesive effort across the whole organisation and our excellent
relationships with our suppliers. Despite the early completion of
SH-13, progress subsequently slowed as an acid stimulation
programme was required on the well to access the broader fracture
network. During the drilling of SH-14, equipment failures and
wellbore issues in the subsequent side-track led to delays, in turn
resulting in a deferral of spudding SH-15 to January 2022.
Nonetheless, despite these issues, SH-13 and SH-14 were brought on
stream towards the end of the year. We also completed the
debottlenecking of PF-2, increasing total field capacity to
c.57,500 bopd.
Draft Shaikan Field Development Plan
With the submission of the draft Field Development Plan to the
MNR in November 2021, we took an important step towards unlocking
the full potential of the Shaikan Field. Constructive discussions
continue with the MNR and, while final timing of approval remains
uncertain due to the complexity of the project, we are pleased to
provide an interim update on the progress that we have made to date
on Phase 1 of the draft FDP. Final details and cost estimates may
vary and we expect to provide an update upon FDP approval.
As a result of a series of optimisations, we are now targeting
to increase Phase 1 gross plateau production to between
85,000-95,000 bopd, including up to 85,000 bopd from the Jurassic
reservoir and up to 10,000 bopd from the Triassic reservoir.
In addition, we have updated the Gas Management Plan from
processing and export of gas with recovery of elemental sulphur, to
reinjection of gas into the reservoir, underpinning our target to
eliminate routine flaring and more than halve our scope 1 and 2
emissions per barrel by 2025. The project is expected to be
executed in parallel with the Phase 1 increase in oil
production.
From FDP approval, the expected duration of the Phase 1 Jurassic
and Triassic projects is 36 to 42 months and the Gas Management
Plan is 18 to 24 months. Total Phase 1 gross Capex is currently
estimated to be $800-$925 million, up around $160 million from the
previous FDP with the objective of increasing production towards
95,000 bopd through project optimisations. We continue to review
opportunities to further optimise the project.
While the focus remains on delivering Phase 1 of the FDP, we are
committed to exploiting the further potential of the field with a
vision of increasing production beyond 85,000-95,000 bopd through
the expansion of the Triassic reservoir and a Cretaceous reservoir
pilot.
Current operational activity and 2022 outlook
Gross average production since the beginning of the year has
been around c.45,500 bopd. After acid stimulations, current SH-13
production is in line with expectations, while we continue to
explore options to further increase SH-14 production. Following the
early appearance of trace quantities of water, SH-12 is currently
shut-in while we investigate near-term production options ahead of
the installation of planned water handling facilities.
Looking ahead to the rest of the year, we remain focused on
delivering gross average production of 44,000-50,000 bopd,
reflecting the anticipated production contribution from SH-15,
which is currently being hooked up ahead of targeted start-up in Q2
2022, and the benefits of an intervention and workover campaign
with our existing wells with the primary focus of production
assurance and enhancement, where possible..
We remain confident in Shaikan Field gross 2P reserves of 489
MMstb and gross 2C resources of 293 MMstb, based on the 31 December
2020 Competent Person's Report adjusted for 2021 production from 2P
reserves of around 16 MMstb.
Constructive engagement continues with the MNR on the FDP, and
further progress is required before we fully execute FDP activity
including drilling beyond SH-15. In 2022, we are focused on
executing activity that enables us to expedite the FDP following
approval. This includes activities to prepare for expansion of our
production facilities to include water handling and a continuous
drilling programme. Net capital expenditure guidance for 2022 is
$85-$95 million.
Sustainability
We continue to work hard on enhancing the sustainability of our
business, with Board approval of our sustainability strategy and
roadmap in 2021. We remain focused on a number of core priorities.
First, we continue to target zero harm across our operations,
particularly as operational activity continues to increase. Second,
the Gas Management Plan will enable us to reduce our carbon
intensity by more than 50% by 2025 and we are also exploring the
viability of other projects that could enable us to reduce our
scope 1 and 2 emissions further. Third, we continue to develop our
people and identify opportunities to enhance diversity and
inclusion across our business. Lastly, we remain intensely focused
on amplifying the broader social and economic value of the Shaikan
Field and our operations for Kurdistan. We look forward to updating
you on our progress.
Jon Harris
Chief Executive Officer
Financial review
Key financial highlights
Year ended
Year ended 31 31 December
December 2021 2020
------------------------------------------ ------ -------------- ------------
Gross average production(1) bopd 43,440 36,625
Dated Brent(1) $/bbl 70.8 42.0
Realised price(1) $/bbl 49.7 20.9
Revenue $m 301.4 108.4
Operating costs $m 34.4 27.4
Gross operating costs per barrel(1) $/bbl 2.7 2.6
Other general and administrative expenses $m 13.6 12.3
Incurred in relation to Shaikan Field $m 4.1 5.0
Corporate G&A $m 9.5 7.3
Share option expense $m 8.5 1.2
Adjusted EBITDA(1) $m 222.7 56.7
Profit/(loss) after tax $m 164.6 (47.3)
Basic earnings/(loss) per share cents 77.14 (22.45)
Revenue and arrears receipts(1) $m 221.7 101.1
Net capital expenditure(1) $m 50.8 45.9
Free cash flow(1) $m 122.2 (22.9)
Dividends $m 100.0 -
Cash and cash equivalents $m 169.9 147.8
Face amount of the Notes $m 100.0 100.0
Net cash(1) $m 69.9 47.8
------------------------------------------ ------ -------------- ------------
(1) Gross average production, dated Brent, realised price, gross
operating costs per barrel, Adjusted EBITDA, revenue and arrears
receipts being actual cash received during the year, net capital
expenditure, free cash flow and net cash are either non --
financial or non-IFRS measures and, where necessary, are explained
in the summary of non-IFRS measures.
Strategically, Gulf Keystone is committed to a disciplined
approach to capital allocation and cost control, and maintaining a
prudent level of liquidity and robust financial position. By taking
decisive action in 2020 to reduce capital expenditures, operating
costs and general & administrative expenses, the Company
entered 2021 with a strong balance sheet and well positioned to
capitalise on improving macroeconomic fundamentals. In 2021, the
Company restarted its development programme, generated a
significant increase in adjusted EBITDA and paid dividends of $100
million, while further strengthening the balance sheet.
Adjusted EBITDA
Adjusted EBITDA grew almost four-fold in 2021 to $222.7 million
(2020: $56.7 million), driven by a strong increase in the oil price
and higher production, partly offset by higher operating costs,
share option expense and capacity building payments.
Gross average production was 43,440 bopd in 2021, up 19% from
36,625 bopd in 2020 and towards the upper end of the Company's
tightened 2021 guidance range of 42,000-44,000 bopd. With Gulf
Keystone's leverage to the strengthening of the Dated Brent price
from an average of $42.0/bbl in 2020 to $70.8/bbl in 2021, the
realised price per barrel more than doubled to $49.7/bbl, resulting
in an almost tripling in revenue from $108.4 million in 2020 to
$301.4 million in 2021. Revenue was partially offset by a
corresponding $15.2 million increase in capacity building payments
to $23.5 million (2020: $8.4 million), which is a component of the
KRG's entitlement from the Shaikan Field.
Gulf Keystone continues to maintain strict control over its cost
base. Gross operating costs per barrel increased 4% to $2.7/bbl in
2021 (2020: $2.6/bbl), in the middle of the Company's 2021 guidance
range of $2.5-$2.9/bbl. The increase in operating costs in 2021 to
$34.4 million (2020: $27.4 million), primarily due to increased
production, maintenance and well services activity that were
deferred from 2020, was substantially offset by higher
production.
Other general and administrative expenses (G&A), comprising
Shaikan Field and corporate support costs, were slightly higher in
2021 at $13.6 million (2020: $12.3 million), reflecting increasing
activity levels. Share option expense in the period increased by
$7.3 million, principally due to tax settlements related to the
exercise of former Directors' contractual Value Creation Plan share
option entitlements being made in cash and an increase in accrued
national insurance contributions resulting from the increased share
price.
Cash flows
Cash increased in 2021 from $147.8 million to $169.9 million.
The Group has notes outstanding with a principal balance of $100.0
million (2020: $100.0 million) that do not mature until July 2023,
resulting in net cash of $69.9 million at 31 December 2021. The
cash balance has consistently exceeded the $100.0 million notes
outstanding since issue in 2018 and the Company continues to retain
significant covenant headroom.
The Company generated cash from operating activities of $178.6
million in 2021, up from $42.6 million in 2020 due principally to
the increase in Adjusted EBITDA.
In 2021, the Company received revenue receipts of $221.7 million
from the KRG for crude oil sales related to the December 2020 to
August 2021 invoices and partial repayment of arrears related to
the outstanding November 2019 to February 2020 invoices. Of the
original outstanding arrears of $73.3 million net to GKP, a total
of $32.4 million was repaid in 2021, based on an arrangement with
the KRG and IOCs operating in Kurdistan(1) . Despite continued
collection of arrears, the delays to payments from the KRG have
contributed to a working capital increase of $38.5 million (2020:
$9.0 million increase).
Since the beginning of 2022, the Company has received a further
$106.4 million net to GKP for crude oil sales and arrears related
to the September 2021 to November 2021 invoices. As at 29 March
2022, the outstanding arrears balance was $21.9 million net to
GKP.
With the improvement in oil prices and continuous payments from
the KRG, Gulf Keystone restarted its investment programme in the
Shaikan Field and resumed drilling activities in June. During the
year, the Company invested net capital expenditure of $50.8 million
(2020: $45.9 million), primarily on the completion of the SH-13 and
SH-14 wells, related civil and flowline works and the
debottlenecking of PF-2. Net capital expenditure was slightly lower
than final 2021 guidance of approximately $55 million.
As at 31 December 2021, there were $401 million gross of
unrecovered costs, subject to potential cost audit by the KRG. The
R-factor, calculated as cumulative gross revenue receipts of $1,478
million divided by cumulative gross costs of $1,543 million, was
0.96. The unrecovered cost pool and R-factor are used to calculate
monthly cost oil and profit oil entitlements, respectively, owed to
the Company from crude oil sales.
Free cash flow generation was $122.2 million in 2021, an
increase of $145.1 million versus the prior year (2020: ($22.9)
million), enabling the Company to continue to deliver against its
commitment of balancing investment in growth with returns to
shareholders. In March 2021, Gulf Keystone reinstated its dividend
policy of paying at least $25 million annually. Given continuing
strong oil prices and cash generation in the year, the Company paid
total dividends of $100 million. Since the beginning of 2022, Gulf
Keystone has paid an additional dividend of $50 million to
shareholders.
The Group performed a cash flow and liquidity analysis based on
which the Directors have a reasonable expectation that the Group
has adequate resources to continue to operate for the foreseeable
future. Therefore, the going concern basis of accounting is used to
prepare the financial statements.
Outlook
The Company has a strong balance sheet with cash and cash
equivalents of $182.7 million at 29 March 2022.
Looking ahead to 2022, we are currently planning to invest net
capital expenditure of $85-95 million. This includes the drilling
of SH-15, well interventions and workovers and activity that
enables us to expedite the FDP following approval, including
preparatory work for the continued expansion of our production
facilities to include water handling and for a continuous drilling
programme. Constructive engagement continues with the MNR on the
FDP, and further progress is required before we fully execute FDP
activity including drilling beyond SH-15. With progress on the FDP,
we expect to resume drilling and increase 2022 capital
guidance.
We are targeting gross Opex of $2.9-$3.3/bbl, driven by
increased operational activity and the continued catch up of
previously scheduled work programmes deferred due to COVID-19. 2022
annual gross average production is expected to be 44,000 -- 50,000
bopd.
Given the strong oil price outlook and our flexible spending
programme, we currently have no hedging programme in place. We
consider hedging on an ongoing basis, taking into account
macro-economic and corporate considerations.
In line with our commitment to balancing investment in growth
with returns to shareholders, we are pleased to declare $90 million
of dividends, comprising a $25 million 2021 ordinary annual
dividend for shareholder approval at the Company's AGM on 24 June
2022 and a $65 million interim dividend payable in May 2022.
Assuming timely payment of invoices and continuing strong oil
prices, we are expecting strong cash flow generation in 2022. This
would provide flexibility to fund a potential increase in capital
expenditure, with progress on the FDP, and the opportunity for
further distributions to shareholders, while preserving adequate
liquidity and maintaining a robust balance sheet
Ian Weatherdon
Chief Financial Officer
(1) The repayment of arrears related to January 2021 and
February 2021 were calculated based on 50% of the difference
between average monthly dated Brent price and $50/bbl multiplied by
the gross Shaikan crude sold in a month. The KRG advised IOCs that
since the dated Brent price had remained consistently well above
$50/bbl, the 50% difference would be changed to 20% from March 2021
and onwards.
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.
Gross operating costs per barrel (unaudited)
Gross operating costs are divided by gross production to arrive
at operating costs per bbl.
2021 2020
------------------------------------- ---- ----
Gross production (MMbbls) 15.9 13.4
Gross operating costs ($ million)(1) 43.0 34.2
Gross operating costs per barrel
($ per bbl) 2.7 2.6
(1) Gross operating costs equate to operating costs (see note 3
) adjusted for the Group's 80% working interest in the Shaikan
Field.
Adjusted EBITDA
Adjusted EBITDA is a useful indicator of the Group's
profitability, which excludes the impact of costs attributable to
tax (expense)/credit, finance costs, finance revenue, depreciation,
amortisation and impairment of receivables.
2021 2020
$ million $ million
----------------------------------- --------- ---------
Profit/(loss) after tax 164.6 (47.3)
Finance costs 11.4 14.1
Finance revenue (0.4) (1.3)
Tax (credit)/expense (0.9) 0.3
Depreciation of oil and gas assets 54.1 82.8
Depreciation of other PPE assets
and amortisation of intangibles 1.0 1.3
Impairment of receivables (7.1) 6.8
--------- ---------
Adjusted EBITDA 222.7 56.7
========= =========
Net capital expenditure
Net capital expenditure is the value of the Group's additions to
oil and gas assets excluding the change in value of the
decommissioning asset and movements in drilling and other
equipment.
2020
2021 Restated
$ million $ million
-------------------------------------- --------- ---------
Additions to oil and gas assets (note
11 ) 46.2 51.7
(Increase)/decrease of drilling and
other equipment classified as oil
and gas assets 4.6 (5.9)
--------- ---------
Net capital expenditure 50.8 45.8
========= =========
Net Cash
Net Cash is a useful indicator of the Group's indebtedness and
financial flexibility because it indicates the level of cash and
cash equivalents less cash borrowings within the Group's business.
Net cash is defined as cash and cash equivalents, less current and
non-current borrowings and non-cash adjustments. Non-cash
adjustments include unamortised arrangement fees and other
adjustments.
2020
2021 Restated
$ million $ million
--------------------------------- --------- ---------
Outstanding Notes (99.1) (98.6)
Unamortised issue costs (note 16
) (0.9) (1.4)
Cash and cash equivalents 169.9 147.8
Net cash 69.9 47.8
========= =========
Free cash flow
Free cash flow represents the Group's cash flows, before any
dividends or share buy-backs.
2020
2021 Restated
$ million $ million
-------------------------------------- --------- ---------
Net cash generated from operating
activities 178.6 42.6
Net cash used in investing activities (55.7) (64.2)
Payment of leases (0.7) (1.3)
Free cash flow 122.2 (22.9)
========= =========
Consolidated income statement
For the year ended 31 December 2021
Notes 2021 2020
$'000 $'000
----- --------- ---------
Revenue 2 301,389 108,449
Cost of sales 3 (111,721) (121,507)
Decrease/(increase) of impairment
provision on trade receivables 14 7,065 (6,776)
--------- ---------
Gross profit/(loss) 196,733 (19,834)
Other general and administrative
expenses 4 (13,643) (12,312)
Share option related expenses 5 (8,490) (1,235)
Profit/(loss) from operations 174,600 (33,381)
Finance revenue 7 419 1,278
Finance costs 7 (11,353) (14,087)
Foreign exchange gains/(losses) 57 (841)
--------- ---------
Profit/(loss) before tax 163,723 (47,031)
Tax credit/(expense) 8 874 (311)
--------- ---------
Profit/(loss) after tax for the year 164,597 (47,342)
--------- ---------
Profit/(loss) per share (cents)
Basic 9 77.14 (22.45)
Diluted 9 73.04 (22.45)
Consolidated statement of comprehensive income
For the year ended 31 December 2021
2021 2020
$'000 $'000
------- --------
Profit/(loss) after tax for the year 164,597 (47,342)
Items that may be reclassified to
the income statement in subsequent
periods:
Fair value losses arising in the
period (2,021) (1,732)
Cumulative losses arising on hedging
instruments reclassified to revenue 3,753 -
Exchange differences on translation
of foreign operations (254) 707
------- --------
Total comprehensive income/(expense)
for the year 166,075 (48,367)
======= ========
Consolidated balance sheet
Notes 31 December 31 December 1 January
2021 2020 2020
Restated(1) Restated(1)
$'000 $'000 $'000
----- ----------- ------------ ------------
Non-current assets
Intangible assets 10 3,583 933 454
Property, plant and equipment 11 404,205 405,469 (1) 432,507 (1)
Trade receivables 14 - 59,096 -
Deferred tax asset 18 1,385 617 849
409,173 466,115 433,810
----------- ------------ ------------
Current assets
Inventories 13 6,018 5,760 (1) 6,135 (1)
Trade and other receivables 14 179,200 37,832 103,181
Derivative financial instruments 19 - 977 -
Cash and cash equivalents 169,866 147,826 190,762
----------- ------------ ------------
355,084 192,395 300,078
----------- ------------ ------------
Total assets 764,257 658,510 733,888
=========== ============ ============
Current liabilities
Trade and other payables 15 (98,800) (69,123) (83,981)
Non-current liabilities
Trade and other payables 15 (789) (1,058) (1,989)
Borrowings 16 (99,123) (98,633) (98,192)
Provisions 17 (43,841) (35,671) (29,807)
----------- ------------ ------------
(143,753) (135,362) (129,988)
----------- ------------ ------------
Total liabilities (242,553) (204,485) (213,969)
----------- ------------ ------------
Net assets 521,704 454,025 519,919
=========== ============ ============
Equity
Share capital 20 213,731 211,371 229,430
Share premium 20 742,914 842,914 871,675
Treasury shares 20 - (2,592) (29,749)
Cost of hedging reserve - (1,732) -
Exchange translation reserve (2,768) (2,514) (3,221)
Accumulated losses (432,173) (593,422) (548,216)
Total equity 521,704 454,025 519,919
=========== ============ ============
(1) The comparative consolidated balance sheet has been restated
to reflect a reclassification of inventory items that are to be
used in the development of the Shaikan field to property, plant and
equipment. See note 28 for details regarding the restatement.
The financial statements were approved by the Board of Directors
and authorised for issue on 29 March 2022 and signed on its behalf
by:
Jon Harris
Chief Executive Officer
Ian Weatherdon
Chief Financial Officer
Consolidated statement of changes in equity
For the year ended 31 December 2021
Attributable to equity holders of the Company
Cost of Exchange
Share Share Treasury hedging translation Accumulated Total
Notes capital premium shares reserve reserve losses equity
$'000 $'000 $'000 $'000 $'000 $'000 $'000
Balance at 1 January
2020 229,430 871,675 (29,749) - (3,221) (548,216) 519,919
--------- --------- ---------- -------- ------------ ------------- ------------
Net loss for the year - - - - - (47,342) (47,342)
Cash flow hedge -
fair value movements - - - (1,732) - - (1,732)
Exchange difference
on translation of
foreign operations - - - - 707 - 707
--------- --------- ---------- -------- ------------ ------------- ------------
Total comprehensive
(expense)/income for
the year - - - (1,732) 707 (47,342) (48,367)
--------- --------- ---------- -------- ------------ ------------- ------------
Employee share schemes 24 - - - - - 2,637 2,637
Share buy-back 20 - - (20,164) - - - (20,164)
Share options exercised - - 501 - - (501) -
Share cancellation 20 (18,059) (28,761) 46,820 - - - -
Balance at 31 December
2020 211,371 842,914 (2,592) (1,732) (2,514) (593,422) 454,025
--------- --------- ---------- -------- ------------ ------------- ------------
Net profit for the
year - - - - - 164,597 164,597
Cash flow hedge -
fair value movements - - - 1,732 - - 1,732
Exchange difference
on translation of
foreign operations - - - - (254) - (254)
--------- --------- ---------- -------- ------------ ------------- ------------
Total comprehensive
income/(expense) for
the year - - - 1,732 (254) 164,597 166,075
--------- --------- ---------- -------- ------------ ------------- ------------
Dividends paid 25 - (100,000) - - - - (100,000)
Employee share schemes 2 4 - - - - - 1,604 1,604
Share options exercised - - 2,592 - - (2,592) -
Share issues 20 2,360 - - - - (2,360) -
Balance at 31 December
2021 213,731 742,914 - - (2,768) (432,173) 521,704
========= ========= ========== ======== ============ ============= ============
Consolidated cash flow statement
For the year ended 31 December 2021
Notes 2021 2020
Restated
$'000 $'000
--------- --------------
Operating activities
Cash generated from operations 21 189,155 56,734
Interest received 7 419 1,278
Interest paid 7 (10,000) (10,000)
Payment of put option premium (1,043) (5,371)
Net cash generated from operating
activities 178,531 42,641
--------- --------------
Investing activities
Purchase of intangible assets (2,725) (458)
Purchase of property, plant and
equipment 21 (52,959) (63,760)
Net cash used in investing activities (55,684) (64,218)
--------- --------------
Financing activities
Payment of dividends 25 (100,000) -
Share buy-back - (20,164)
Payment of leases (688) (1,317)
Net cash used in financing activities (100,688) (21,481)
--------- --------------
Net increase/(decrease) in cash
and cash equivalents 22,159 (43,058)
Cash and cash equivalents at
beginning of year 147,826 190,762
Effect of foreign exchange rate
changes (119) 122
Cash and cash equivalents at
end of the year being bank balances
and cash on hand 169,866 147,826
========= ==============
Summary of significant accounting policies
General information
The Company is incorporated in Bermuda (registered address:
Cedar House, 3(rd) Floor, 41 Cedar Avenue, Hamilton, HM12,
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, 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, development and production, operating in the Kurdistan
Region of Iraq.
The financial information set out in this Results Announcement
does not constitute the Company's annual report and accounts for
the years ended 31 December 2021 or 2020 but is derived from those
accounts. The auditors have reported on those accounts; their
reports were unqualified and did not draw attention to any matters
by way of emphasis without qualifying their report.
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 2021.
The following new accounting standards, amendments to existing
standards and interpretations are effective on 1 January 2021:
Amendments to IFRS 4 Insurance Contracts - deferral of IFRS19,
Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 Interest
Rate Benchmark Reform - Phase 2, Amendments to IFRS 16 Leases:
Covid-19-related rent concessions beyond 30 June 2021. These
standards do not and are not expected to have a material impact on
the Company's results or financials statement disclosures in the
current or future reporting periods.
New and revised IFRSs issued but not yet effective
At the date of approval of these financial statements, the Group
has not applied the following new and revised IFRSs that have been
issued but are not yet effective by United Kingdom adopted
International Accounting Standards:
IFRS 17 Insurance Contracts
IFRS 10 and IAS Sale or Contribution of Assets between an
28 (amendments) Investor and its Associate or Joint Venture
Amendments to IAS Classification of Liabilities as Current
1 or Non-current
Amendments to IFRS Reference to the Conceptual Framework
3
Amendments to IAS Property, Plant and Equipment-Proceeds before
16 Intended Use
Amendments to IAS Onerous Contracts - Cost of Fulfilling a
37 Contract
Annual Improvements Amendments to IFRS 1 first time adoption
Standards 2018-20 of IFRS, IFRS 9 financial instruments IFRS
16 Leases and IAS 41 Agriculture.
Amendments to IAS Disclosure of Accounting Policies
1 and IFRS Practice
Statement 2
Amendments to IAS Definition of Accounting Estimates
8
Amendments to IAS Deferred Tax related to Assets and Liabilities
12 arising from a Single Transaction
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 .
Statement of compliance
The financial statements have been prepared in accordance with
United Kingdom adopted International Accounting Standards .
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 recognised at fair value at
the date of grant, 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 Chief Executive
Officer's Review, the Operational Review and the Management of
Principal Risks and Uncertainties. The financial position of the
Group at the year end and its cash flows and liquidity position are
included in the Financial Review.
As at 29 March 2022, the Group had $182.7 million of cash. The
Group continues to closely monitor and manage its liquidity. Cash
forecasts are regularly produced and sensitivities run for
different scenarios including, but not limited to change in
commodity prices, different production rates from the Shaikan
block, cost contingencies, disruptions to revenue receipts, impact
of climate change and geopolitical risks on the Group's operations,
etc. In the current year, these have included both the Iraqi
Supreme Court ruling on 15 February 2022 and export route
availability as a result of the evolving sanctions situation due to
the Russian invasion of Ukraine as further described in note 29.
The Group's forecasts, taking into account the applicable risks,
stress test scenarios and potential mitigating actions, show that
it has sufficient financial resources for the 12 months from the
date of approval of the 2021 Annual Report and Accounts.
Based on the analysis performed, the directors have a reasonable
expectation that the Group has adequate resources to continue to
operate for the foreseeable future. Thus, the going concern basis
of accounting is used to prepare the annual consolidated 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.
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 by the Shaikan Contractor (the Company and
Kalegran BV, a subsidiary of MOL Hungarian Oil & Gas Plc,
("MOL")) to the Kurdistan Regional Government ("KRG"), who in turn
resell the oil. The selling price is determined in accordance with
the principles of the crude oil export sales agreement ("Crude Oil
Sales Agreement"), based on the average monthly dated Brent crude
price less a quality discount and a pipeline tariff. The sales
agreement also specifies the delivery point and the 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 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:
-- All crude oil sales were made via the Kurdistan Export
Pipeline. The point of sale is the point that the crude oil is
injected into the Kurdistan Export Pipeline; and
-- 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.
During past PSC negotiations with the Ministry of Natural
Resources ("MNR"), it was tentatively agreed that the Shaikan
Contractor would provide the KRG a 20% carried working interest in
the PSC. This would result in a reduction of GKP's working interest
from 80% to 61.5%. To compensate for such decrease, capacity
building payments expense would be reduced from 40% to 20% of
profit petroleum. While the PSC has not been formally amended, it
was agreed that GKP would invoice the KRG for oil sales based on
the proposed revised terms from October 2017. Since revenue is
recognised on a cash assured basis, the financial statements
reflect the proposed revised working interest of 61.5%. Relative to
the PSC terms, the proposed revised invoicing terms result in a
decrease in both revenue and cost of sales and on a net basis are
slightly positive for the Company.
As part of earlier PSC negotiations, on 16 March 2016, GKP
signed a bilateral agreement with the MNR (the "Bilateral
Agreement"). The Bilateral Agreement included a reduction in the
Group's capacity building payment from 40% to 30% of profit
petroleum. Subsequent to signing the Bilateral Agreement, further
negotiations resulted in the capacity building payment rate being
reduced from 30% to 20%, which has formed the basis for all oil
sales invoices to date as noted above. Since PSC negotiations have
not been finalised, GKP has included a non-cash payable for the
difference between the capacity building rate of 20% and 30%, which
is recognised in cost of sales and other payables.
The Company is in constructive dialogue with the MNR to confirm
whether to proceed with a formal amendment to the PSC to reflect
current invoice terms or to revert to the original PSC terms.
Income tax arising from the Company's activities under its PSC
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.
Finance 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.
Intangible assets
Intangible assets include computer software and are measured at
cost and amortised over their expected useful economic lives of
three years.
Property, plant and equipment ("PPE")
Oil and gas assets
Development and production assets
Development and production assets are accumulated on a
field-by-field basis and represent the costs of acquisition and
developing the commercial reserves discovered and bringing them
into production, together with the exploration and evaluation
expenditure incurred in finding commercial reserves, directly
attributable overheads and costs for future restoration and
decommissioning. These costs are capitalised as part of PPE and
depreciated based on the Group's depreciation of oil and gas assets
policy.
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 depreciation, depletion and amortisation
("DD&A") calculation. Costs used in the calculation comprise
the net book value of the field, and any 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 reserves estimate used in 2021 is based on values as at 31
December 2020 included in the Competent Persons Reports ("CPR")
prepared by ERC Equipoise.
Other property, plant and equipment
Other property, plant and equipment are principally equipment
used in the field which are separately identifiable to development
and production assets, and typically have a shorter useful economic
life. Assets are carried at cost, less any accumulated depreciation
and accumulated impairment losses. Costs include purchase price,
construction and installation costs.
These assets are expensed on a straight-line basis over their
estimated useful lives of 3 years from the date they are put in
use.
Fixtures and equipment
Fixtures and equipment assets are stated at cost less
accumulated depreciation and any accumulated impairment losses.
These assets are expensed on a straight-line basis over their
estimated useful lives of 5 years from the date they are available
for use.
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 i mpairment identified is immediately recognised as an
expense.
Borrowing costs
Borrowing costs directly relating to the acquisition or
construction 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
Tax expense or credit represents the sum of tax currently
payable or recoverable and deferred tax.
Tax currently payable or recoverable is based on taxable profit
or loss 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 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
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 stated at
the lower of cost and net realisable value. Cost comprises direct
materials and, where applicable, direct labour costs and those
overheads that have been incurred in bringing the inventories to
their present location and condition. Cost is calculated using the
weighted average cost method. Hydrocarbon inventories are recorded
at net realisable value with changes in the value of 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.
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 as 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 utilise derivative financial instruments to manage
its exposure to oil price 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.
Hedge accounting
The Group uses hedge accounting for certain derivative
instruments. The Group uses cash flow hedge accounting when hedging
the exposure to variability in cash flows that is either
attributable to a particular risk associated with a recognised
asset or liability or a highly probable forecast transaction or the
foreign currency risk in an unrecognised firm commitment.
At the inception of the hedge relationship, the Group formally
designates and documents the relationship between the hedging
instrument and the hedged item, along with its risk management
objectives and its strategy for undertaking the hedge transaction.
Furthermore, at the inception of the hedge and on an ongoing basis,
the Group documents whether the hedging instrument is highly
effective in offsetting changes in fair values or cash flows of the
hedged item attributable to the hedged risk, which is when the
hedging relationship meets all of the following hedge effectiveness
requirements:
- there is an economic relationship between the hedged item and the hedging instrument;
- the effect of credit risk does not dominate the value changes
that result from the economic relationship; and
- the hedge ratio of the hedging relationship is the same as
that resulting from the quantity of the hedged item that the Group
actually hedges and the quantity of the hedging instrument that the
Group uses to hedge that quantity of hedged item.
If a hedging relationship ceases to meet the hedge effectiveness
requirement relating to the hedge ratio but the risk management
objective for that designated hedging relationship remains the
same, the Group adjusts the hedge ratio of the hedging relationship
(i.e. rebalances the hedge) so that it meets the qualifying
criteria again.
The Group designates only the intrinsic value of option
contracts as a hedged item, i.e. excluding the time value of the
option. The changes in the fair value of the time value of the
option are recognised in other comprehensive income and accumulated
in the cost of hedging reserve. If the hedged item is
transaction-related, the time value is reclassified to profit or
loss when the hedged item affects profit or loss. If the hedged
item is time-period related, then the amount accumulated in the
cost of hedging reserve is reclassified to profit or loss on a
rational basis - the Group applies straight-line amortisation.
Those reclassified amounts are recognised in profit or loss. If the
hedged item is a non-financial item, then the amount accumulated in
the cost of hedging reserve is removed directly from equity and
included in the initial carrying amount of the recognised
non-financial item. Furthermore, if the Group expects that some or
all of the profit or loss accumulated in cost of hedging reserve
will not be recovered in the future, that amount is immediately
reclassified to profit or loss.
Cash flow hedge
The effective portion of changes in the fair value of
derivatives and other qualifying hedging instruments that are
designated and qualify as cash flow hedges is recognised in other
comprehensive income and accumulated under the heading of cash flow
hedging reserve, limited to the cumulative change in fair value of
the hedged item from inception of the hedge. The gain or loss
relating to the ineffective portion is recognised immediately in
profit or loss and is included in the revenue line item.
The Group discontinues hedge accounting only when the hedging
relationship (or a part thereof) ceases to meet the qualifying
criteria (after rebalancing, if applicable). This includes
instances when the hedging instrument expires or is sold,
terminated or exercised. The discontinuation is accounted for
prospectively. Any gain or loss recognised in other comprehensive
income and accumulated in cash flow hedge reserve at that time
remains in equity and is reclassified to profit or loss when the
forecast transaction occurs. When a forecast transaction is no
longer expected to occur, the gain or loss accumulated in the cash
flow hedge reserve is reclassified immediately to profit or
loss.
Impairment of financial assets
The Group recognises a loss allowance for expected credit losses
("ECL") on trade receivables and contract assets, as well as on
financial guarantee contracts. The amount of expected credit losses
is updated at each reporting date to reflect changes in credit risk
since initial recognition of the respective financial
instrument.
The Group always recognises lifetime expected credit losses for
trade receivables, contract assets and lease receivables. The
expected credit losses on these financial assets are estimated
based on observed market data and convention, existing market
conditions and forward-looking estimates at the end of each
reporting period, including time value of money where
appropriate.
For all other financial instruments, the Group recognises
lifetime ECL when there has been a significant increase in credit
risk since initial recognition. However, if the credit risk on the
financial instrument has not increased significantly since initial
recognition, the Group measures the loss allowance for that
financial instrument at an amount equal to 12-month ECL.
Lifetime ECL represents the expected credit losses that will
result from all possible default events over the expected life of a
financial instrument. In contrast, 12-month ECL represents the
portion of lifetime ECL that is expected to result from default
events on a financial instrument that are possible within 12 months
after the reporting date.
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 there
is an obligation to restore the site to its original condition. 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
instruments at the grant date. Details regarding the determination
of the fair value of equity-settled share-based transactions are
set out in note 24 . 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 24 .
Leases
The Group assesses whether a contract contains a lease at
inception of the contract. The Group recognises a right-of-use
asset and corresponding lease liability in the consolidated balance
sheet for all lease arrangements longer than twelve months, where
it is the lessee and has control of the asset. For all other
leases, the Group recognises the lease payments as an operating
expense on a straight-line basis over the term of the lease.
The lease liability is initially measured at the present value
of the future lease payments from the commencement date of the
lease. The lease payments are discounted using the interest rate
implicit in the lease or, if not readily determinable, the company
specific incremental borrowing rate.
The lease liability is subsequently measured by increasing the
carrying amount to reflect interest on the lease liability (using
the effective interest method) and by reducing the carrying amount
to reflect the lease payments made. The lease liability is
recognised in creditors as current or non current liabilities
depending on underlying lease terms.
The right-of-use assets are initially recognised on the balance
sheet at cost, which comprises the amount of the initial
measurement of the corresponding lease liability, adjusted for any
lease payments made at or prior to the commencement date of the
lease and any lease incentive received.
For short-term leases (periods less than 12 months) and leases
of low value, the Group has opted to recognise lease expense on a
straight line basis.
Critical accounting judgements and key sources of estimation
uncertainty
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.
Critical judgements in applying the Group's accounting
policies
The following are the critical judgements, apart from those
involving estimations (which are presented separately below), that
the directors have made in the process of applying the Group's
accounting policies and that have the most significant effect on
the amounts recognised in financial statements.
Revenue
The recognition of revenue, particularly the recognition of
revenue from exports, is considered to be a key accounting
judgement. The Group be gan commercial production from the Shaikan
Field in July 2013 and historically made sales to both the domestic
and export markets. The Group considers that revenue can be only
reliably measured when the cash receipt is assured. The assessment
of whether cash receipts are 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 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,
even though the Group may be 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.
Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources
of estimation uncertainty at the reporting period that may have a
significant risk of causing a material adjustment to the carrying
amounts of assets and liabilities within the next financial year,
are discussed below.
Carrying value of producing assets
In line with the Group's accounting policy on impairment,
management performs an impairment review of the Group's oil and gas
assets at least annually with reference to indicators as set out in
IAS 36. The Group assesses its group of assets, called a
cash-generating unit ("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 estimates such as
future oil prices, estimated production volumes, the cost of
development and production, pre-tax discount rates that reflect the
current market assessment of the time value of money and risks
specific to the asset, commercial reserves and inflation. The key
assumptions are subject to change based on market trends and
economic conditions. 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 2021 was the Shaikan Field
with a carrying value of $402.1 million. The Group performed a full
impairment indicator evaluation considering the impact of climate
change, oil prices, field productivity, potential changes to future
development plans, impacts of local and global geopolitical
factors, including the potential inability to access export
pipeline due to sanctions (see note 29), and liquidity. The
potential impact of such factors together with other possible
changes to key assumptions and available mitigating actions, showed
that no impairment indicators arose.
The key areas of estimation in the impairment assessment are as
follows:
- Commodity prices are based on latest internal forecasts,
benchmarked with external sources of information to ensure they are
within the range of available market and analyst forecasts.
Scenario 2022 2023 onwards
$/bbl - Real $/bbl - Real
-------------------- ------------- -------------
31 December 2021 -
base case $81 $55
------------- -------------
31 December 2021 -
stress case $80 $50
------------- -------------
31 December 2020 -
base case $55 $55
------------- -------------
31 December 2020 -
stress case $40 $40
------------- -------------
- The Group continues to develop its assessment of the potential
impacts of climate change and the associated risks, the transition
to a low-carbon future and our ambition to reduce scope one and two
per barrel CO(2) emissions by at least 50% by 2025. The potential
effects of climate change and the Paris Agreement were considered.
It was concluded, based on benchmarking, that the stress case price
deck used in the impairment assessment is reasonable to reflect the
potential impact of meeting the Paris Agreement targets. The stress
case also includes an estimated cost of the introduction of a
carbon tax in Kurdistan;
- Discount rates that are adjusted to reflect risks specific to
the Shaikan Field and the KRI. The impairment analysis was based on
a post-tax nominal 15% discount rate (2020: 15%). The impact of an
increase in the discount rate to 20% was considered to reflect
potential increased geopolitical risks and no impairment was
identified;
- Operating costs and capital expenditure that are based on
financial budgets and internal management forecasts. Costs
assumptions incorporate management experience and expectations, as
well as the nature and location of the operation and the risks
associated therewith. Base case costs assumptions used in the
assessment are consistent with the November 2021 draft FDP
submitted to the MNR, which includes the estimated cost of
implementing a Gas Management Plan, as part of our ambition to
reduce scope one and two emissions as outlined above;
- Commercial reserves and production profiles used in the
assessment are consistent with the November 2021 draft FDP
submitted to the MNR
- Timing of revenue receipts.
In February 2022, a majority decision of the Iraqi Supreme Court
ruled that the Kurdistan Region of Iraq Oil and Gas Law ("KROGL")
was unconstitutional and provides that the Iraqi Ministry of Oil
may pursue annulment of Production Sharing Contracts issued by the
Kurdish Regional Government (KRG). The KRG responded that "it will
take all constitutional, legal, and judicial measures to protect
and preserve all contracts made in the oil and gas sector". While
the Iraqi government has disputed the validity of the PSCs and the
ruling has not to date impacted our business, it is not possible to
determine potential future implications. The Group will continue to
engage with Ministry officials on this matter and will react as any
implications of the ruling become clearer.
Notes to the consolidated financial statements
1 Geographical information
The Group's non-current assets, excluding deferred tax assets
and other financial assets, by geographical location are detailed
below:
2021 2020
Restated
$'000 $'000
--------------- ------- ---------
Kurdistan 402,787 404,492
United Kingdom 5,001 1,910
------- ---------
407,788 406,402
======= =========
The Chief Operating Decision Maker, as per the definition in
IFRS 8, is considered to be the Board of Directors. The Group
operates in a single segment, that of oil and gas exploration,
development and production, in a single geographical location, the
Kurdistan Region of Iraq. As a result, the financial information of
the single segment is the same as set out in the consolidated
statement of comprehensive income, the consolidated balance sheet,
the consolidated statement of changes in equity, the consolidated
cash flow statement and the related notes.
Information about major customers
Included in revenues are $305.1 million, which arose from sales
to the KRG (2020: $108.4 million).
2 Revenue
2021 2020
$'000 $'000
--------------------------------------- ------- -------
Oil sales 305,142 108,449
Hedging losses reclassified to revenue (3,753) -
------- -------
301,389 108,449
======= =======
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 2021, the cash-assured values recognised as oil sales
were the invoiced revenue for the year amounting to $305.1 million
(2020: $108.4 million). The oil sales price was calculated using
the monthly average Dated Brent price, which was $70.8/bbl on
average during the year (2020: $42.0/bbl) less an average discount
of $21.20 (2020: $21.10) per barrel for quality and pipeline tariff
costs.
Hedging losses were incurred on put options which were purchased
to protect against a decline in Dated Brent prices below certain
levels. Put options were purchased for 1H 2021 and Q3 2021,
effectively establishing a floor price of $35/bbl and $40/bbl,
respectively, over approximately 60% of net entitlement production.
The put options were designated as cash flow hedges. All the put
options expired during the year and the associated hedging losses
that had previously been deferred within the hedging reserve were
reclassified to revenue.
3 Cost of sales
2021 2020
$'000 $'000
----------------------------------- ------- -------
Operating costs 34,372 27,401
Capacity building payments 23,529 8,362
Changes in inventory valuation (348) 2,923
Depreciation of oil and gas assets 54,120 82,797
Depreciation of operational assets 48 24
111,721 121,507
======= =======
3 Cost of sales continued
Further details on the depreciation of oil and gas assets and
operational assets is set out in the Summary of significant
accounting policies section.
During the year, the Group received a Competent Person's Report
from ERC Equipoise Limited regarding the Shaikan Field's reserves
and resources as at 31 December 2020. The use of the future capital
expenditure and 2P reserves estimates from the report resulted in a
lower depreciation, depletion and amortisation (DD&A) per
barrel rate. The new DD&A rate constitutes a change in
accounting estimate and is reflected in the financial statements
effective 1 January 2021.
4 Other general and administrative expenses
2021 2020
$'000 $'000
--------------------------------------- ------- ------
Depreciation and amortisation 940 1,325
Auditor's remuneration (see below) 583 574
Other general and administrative costs 12,120 10,413
13,643 12,312
======= ======
Of the $13.6 million of general and administrative expenses,
$4.1 million (2020: $5.0 million) were incurred in relation to the
Shaikan Field.
2021 2020
$'000 $'000
-------------------------------------------------------- ------- -------
Fees payable to the Company's auditor for
the audit of the Company's annual accounts 318 350(1)
Fees payable to the Company's auditor for
other services to the Group
* audit of the Company's subsidiaries pursuant to
legislation 28 28
------- -------
Total audit fees 346 378
Advisory services 107 45
Other assurance services (including a half
year review) 130 151
Total fees 583 574
======= =======
(1) The fees payable to the Company's auditor in 2020 included
$43,000 in respect of the 2019 audit.
5 Share option related expense
2021 2020
$'000 $'000
-------------------------------------------- ----- -------
Share-based payment expense 2,255 2,440
Payments related to share options exercised 4,142 -
Share-based payment related provision
for taxes 2,093 (1,205)
8,490 1,235
===== =======
On the exercise of the Value Creation Plan ("VCP") share options
by former Directors, tax settlements were made in cash instead of
using the proceeds from selling additional shares. This and the
payment of dividends accumulated during the VCP vesting period are
the main components of the payments related to share options
exercised. As applicable, the future exercise of outstanding VCP
share options is expected to be equity settled although the Company
may consider settling any related tax in cash.
6 Staff costs
The average number of employees and contractors (including
Executive directors) employed by the Group was 349 (2020: 354). The
headcount numbers are not adjusted for part-time, shift-work and
rotational working arrangements.
Staff costs were as follows:
2021 2020
$'000 $'000
Wages and salaries 36,835 31,753
Social security costs 1,880 1,334
Share-based payment (see note 24 ) 3,009 2,637
41,724 35,724
====== ======
Staff costs include costs relating to contractors who are
long-term workers in key positions, and are included in PPE
additions, cost of sales and other general and administrative
expenditure depending on the nature of such costs.
7 Finance costs and finance revenue
2021 2020
$'000 $'000
------------------------------------------ -------- -----------------
Notes interest paid during the year (see
note 16 ) (10,000) (10,000)
Unwinding of finance and arrangement fees
(see note 16 ) (489) (440)
Finance lease interest (123) (221)
Put option premium - (2,662)
Unwinding of discount on provisions (see
note 17 ) (741) (764)
-------- -----------------
Total finance costs (11,353) (14,087)
-------- -----------------
Finance revenue 419 1,278
-------- -----------------
Net finance costs (10,934) (12,809)
======== =================
8 Income tax
2021 2020
$'000 $'000
----------------------------------------------- -------- --------
Current year credit/(expense) 75 (90)
Prior year adjustment 28 -
Deferred UK corporation tax credit/(expense)
(see note 18 ) 771 (221)
-------- --------
Tax credit/(expense) attributable to the
Company and its subsidiaries 874 (311)
======== ========
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 PSC. 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.
The annual UK corporation tax rate for the year ended 31
December 2021 was 19.0% (2020: 19.0%).
8 Income tax continued
At the Budget 2021 on 3 March 2021, the UK Government announced
that the corporation tax rate in the UK will increase to 25% for
companies with profits above GBP250,000 with effect from 1 April
2023, as well as announcing a number of other changes to allowances
and treatment of losses. These changes were substantively enacted
as 31 December 2021. Deferred tax is provided for due to the
temporary differences, which give rise to such a balance in
jurisdictions subject to income tax. All deferred tax arises in the
UK.
9 Profit/(loss) per share
The calculation of the basic and diluted profit per share is
based on the following data:
2021 2020
$'000 $'000
------- --------
Profit/(loss) after tax for basic and
diluted per share calculations 164,597 (47,342)
------- --------
Number of shares ('000s):
------- --------
Basic weighted average number of ordinary
shares 213,384 210,893
Basic EPS (cents) 77.14 (22.45)
------- --------
The Group followed the steps specified by IAS 33 in determining
whether potential common shares are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
2021 2020
$'000 $'000
---------------------------------------------- ------- -------
Number of shares ('000s):
Basic weighted average number of ordinary
shares outstanding 213,384 210,893
Effect of dilutive potential ordinary
shares 11,962 -
------- -------
Diluted number of ordinary shares outstanding 225,346 210,893
Diluted EPS (cents) 73.04 (22.45)
------- -------
The weighted 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.
As the company reported a loss for the year ended 2020, the
exercise of the outstanding share options would have reduced the
reported loss per share and, therefore, the share options were
anti-dilutive.
10 Intangible assets
Computer
software
$'000
----------------------------------------- ---------
Year ended 31 December 2020
Opening net book value 454
Additions 458
Amortisation charge (3)
Foreign currency translation differences 24
---------
Closing net book value 933
---------
At 31 December 2020
Cost 1,980
Accumulated amortisation (1,047)
---------
Net book value 933
---------
Year ended 31 December 2021
Opening net book value 933
Additions 2,742
Amortisation charge (25)
Foreign currency translation differences (67)
Closing net book value 3,583
=======
At 31 December 2021
Cost 4,722
Accumulated amortisation (1,139)
-------
Net book value 3,583
=======
The amortisation charge of $25,000 (2020: $3,000) for computer
software has been included in other general and administrative
expenses (see note 4 ).
11 Property, plant and equipment
Oil and Fixtures Right Total
gas and of use
assets equipment assets
$'000 $'000
$'000 $'000
------------------------------------ --------- --------------- ------- ---------
Year ended 31 December 2020
Opening net book value - restated 428,601 1,310 2,596 432,507
Additions 51,716 155 1,721 53,592
Lease modification - - (1,623) (1,623)
Revision to decommissioning
asset 5,100 - - 5,100
Depreciation charge (82,797) (278) (1,044) (84,119)
Foreign currency translation
differences - - 12 12
Closing net book value - restated 402,620 1,187 1,662 405,469
========= =============== ======= =========
At 31 December 2020
Cost 778,329 7,160 3,602 789,091
Accumulated depreciation (375,709) (5,973) (1,940) (383,622)
--------- --------------- ------- ---------
Net book value - restated 402,620 1,187 1,662 405,469
========= =============== ======= =========
Year ended 31 December 2021
Opening net book value 402,620 1,187 1,662 405,469
Additions 46,165 203 76 46,444
Disposals - - (1,432) (1,432)
Revision to decommissioning
asset 7,429 - - 7,429
Depreciation charge (54,120) (351) (612) (55,083)
Accumulated depreciation eliminated
on disposal - - 1,405 1,405
Foreign currency translation
differences (1) (6) (21) (28)
Closing net book value 402,094 1,033 1,078 404,205
========= =============== ======= =========
At 31 December 2021
Cost 831,924 7,363 2,246 841,533
Accumulated depreciation (429,830) (6,330) (1,168) (437,328)
--------- --------------- ------- ---------
Net book value 402,094 1,033 1,078 404,205
========= =============== ======= =========
The net book value of oil and gas assets at 31 December 2021 is
comprised of property, plant and equipment relating to the Shaikan
block with a carrying value of $402.1 million (2020 restated:
$402.6 million).
The additions to the Shaikan asset during the year include the
costs relating to the drilling and completion of SH-14 and SH-13,
well flowlines construction, PF-1 and PF-2 debottlenecking
activities and subsurface studies. The increase in the
decommissioning asset represents further decommissioning
obligations that arose on capital projects completed during the
year and revisions to decommissioning cost estimates.
The DD&A charge of $54.1 million (2020: $82.8 million) on
oil and gas assets has been included within cost of sales (note 3
). The depreciation charge of $0.4 million (2020: $0.3 million) on
fixtures and equipment and $0.6 million (2020: $1.0 million) on
right of use assets has been included in general and administrative
expenses (note 4 ).
Right of use assets at 31 December 2021 of $1.1 million (2020:
$1.7 million) consisted principally of buildings.
For details of the key assumptions and judgements underlying the
impairment assessment, refer to the "Critical accounting estimates
and judgements" section of the Summary of significant accounting
policies.
See note 28 for further information on restated balances.
12 Group companies
Details of the Company's subsidiaries and joint operations at 31
December 2021 is as follows:
Name of subsidiary Place of Proportion Principal
incorporation of ownership activity
interest
------------------------ --------------- -------------- -------------------------
Gulf Keystone Petroleum United Kingdom 100% Management, support,
(UK) Limited geological, geophysical
6th floor and engineering
New Fetter Place services
8-10 New Fetter Lane
London EC4A 1AZ
------------------------ --------------- -------------- -------------------------
Gulf Keystone Petroleum Bermuda 100% Exploration, evaluation,
International Limited development and
Cedar House, 3rd Floor production activities
41 Cedar Avenue in Kurdistan
Hamilton HM12
Bermuda
------------------------ --------------- -------------- -------------------------
Name of joint operation Location Proportion Principal
of ownership activity
interest
------------------------ ---------- -------------- ------------------------
Shaikan Kurdistan 80% Production and
development activities
------------------------ ---------- -------------- ------------------------
13 Inventories
31 December 31 December 1 January
2021 2020 2020
Restated Restated
$'000 $'000 $'000
------------------------------- ----------- ----------- ---------
Warehouse stocks and materials 5,318 5,405 5,230
Crude oil 700 355 905
----------- ----------- ---------
6,018 5,760 6,135
=========== =========== =========
Warehouse stock and materials at 31 December 2021 contain write
downs to net realisable value of nil (2020: $2.5 million) included
in cost of sales.
The comparative inventory balances have been restated as items
of inventory have been reclassified to property, plant and
equipment. See note 28 for further information.
14 Trade and other receivables
Non-current receivables
2021 2020
$'000 $'000
------------------- -------- -------
Trade receivables - 59,096
14 Trade and other receivables continued
Current receivables
2021 2020
$'000 $'000
-------------------------------- -------- -------
Trade receivables 174,634 34,021
Other receivables 3,622 2,963
Prepayments and accrued income 944 848
-------- -------
179,200 37,832
======== =======
Reconciliation of Trade Receivables
2021 2020
$'000 $'000
------------------------------- -------- --------
Gross carrying amount 175,754 101,302
Less: Impairment allowance (1,120) (8,185)
Carrying value at 31 December 174,634 93,117
======== ========
Gross trade receivables of $175.8 million (2020: $101.3 million)
are comprised of invoiced amounts due from the KRG for crude oil
sales totalling $163.6 million (2020: $92.2 million) and a share of
Shaikan revenue arrears the Group purchased from MOL amounting to
$12.2 million (2020: $9.1 million). The amount due for crude oil
sales includes past due trade receivables of $43.1 million(1)
(2020: $77.3 million) related to November 2019 to February 2020
invoices.
While the Group expects to recover the full value of the
outstanding invoices and purchased revenue arrears, the ECL on the
overdue receivable balance of $1.1 million (2020: $8.2 million) was
provided against the receivables balance in line with the
requirements of IFRS 9. During the year, a $7.1 million gain was
recognised due to the reduction of the ECL provision (2020: a loss
of $6.8 million due to the increase of the ECL provision), driven
by a lower arrears balance.
The Group continues to receive payments in relation to the
arrears from the outstanding invoices in line with the KRG's
proposal to pay 20% of the difference between the monthly average
dated Brent price and $50/bbl multiplied by the gross Shaikan crude
oil volumes sold in the month.
(1) The past due invoiced trade receivables amount excludes the
associated capacity building payments due to the KRG which reduce
the amount due to GKP to $41.0 million (2020: $73.3 million).
ECL sensitivities
The Group's profit before tax was not sensitive to movements of
+/-10% in production level, Brent price, loss given default or
probability of default.
Other receivables
Included within Other receivables is an amount of $0.4 million
(2020: $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 2021 (2020: nil). No impairments of other
receivables have been recognised during the year (2020: nil).
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.
15 Trade and other payables continued
Current liabilities
2021 2020
$'000 $'000
--------------------------------------- ------------ ------------
Trade payables 6,494 2,212
Accrued expenditures 25,961 14,481
Other payables 65,927 51,612
Current lease liabilities (see note 22
) 419 718
Tax liabilities - 100
98,800 69,123
============ ============
Accrued expenditures include $4.4 million interest payable as at
31 December 2021 (2020: $4.4 million), see note 16 .
Other payables include $56.4 million (2020: $46.5 million) of
amounts payable to the KRG that are not expected to be paid, but
rather offset against revenue due from the KRG related to
pre-October 2017 oil sales, which have not yet been recognised in
the financial statements. Within this amount, $22.6 million (2020:
$14.8 million) relates to a non-cash payable for the difference
between the capacity building rate of 20% and 30% (see Summary of
significant accounting policies, Sales revenue).
Non-current liabilities
2021 2020
$'000 $'000
-------------------------------------- ------ ------
Non-current lease liability (see note
22 ) 789 1,058
16 Long term borrowings
2021 2020
$'000 $'000
-------------------------------------- -------- --------
Liability component at 1 January 102,993 102,553
Interest expense, including unwinding
of finance and arrangement fees 10,489 10,440
Interest paid during the year (10,000) (10,000)
Liability component at 31 December 103,482 102,993
======== ========
Liability component reported in:
2021 2020
$'000 $'000
------------------------------------ -------- --------
Current liabilities (see note 15 ) 4,359 4,360
Non-current liabilities 99,123 98,633
103,482 102,993
======== ========
In July 2018, the Group completed the private placement of a
5-year senior unsecured $100 million bond issue (the "Notes"). The
unsecured Notes are guaranteed by Gulf Keystone Petroleum
International Limited and Gulf Keystone Petroleum (UK) Limited, two
of the Company's subsidiaries, and the key terms are summarised as
follows:
- maturity date is 25 July 2023;
- at any time prior to maturity, the Notes are redeemable by GKP
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, subject to certain requirements.
During the year, the Group was not in breach of any terms of the
Notes.
16 Long term borrowings continued
The 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 2021 2020
price
$'000 $'000
------- -------- -------- --------
Notes $103.75 103,750 102,500
As at 31 December 2021, the Group's remaining contractual
liability comprising principal and interest based on undiscounted
cash flows is as follows:
2021 2020
$'000 $'000
----------------- ------- -------
Within one year 10,000 10,000
Within two years 105,639 115,639
-------
115,639 125,639
======= =======
17 Provisions
Decommissioning provision 2021 2020
$'000 $'000
---------------------------------------- ------ ------
At 1 January 35,671 29,807
New provisions and changes in estimates 7,429 5,100
Unwinding of discount 741 764
At 31 December 43,841 35,671
====== ======
The provision for decommissioning is based on the net present
value of the Group's estimated share of expenditure, inflated at
2.0% (2020: 2.0%) and discounted at 2.0% (2020: 2.0%), which may be
incurred for the removal and decommissioning of the wells and
facilities currently in place and restoration of the sites to their
original state. Most expenditures are expected to take place
towards the end of the PSC term in 2043.
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 forward
$'000 $'000 $'000
-------------------------- ----------------- ----------- ---------- ------
At 1 January 2020 (27) 801 75 849
(Charge)/credit to income
statement (85) (66) (70) (221)
Exchange differences (3) (3) (5) (11)
----------------- ----------- ---------- ------
At 31 December 2020 (115) 732 - 617
(Charge)/credit to income
statement (381) 321 831 771
Exchange differences 1 (4) - (3)
----------------- ----------- ---------- ------
At 31 December 2021 (495) 1,049 831 1,385
================= =========== ========== ======
19 Financial instruments
2021 2020
$'000 $'000
--------------------------------- ------- -------
Financial assets
Cash and cash equivalents 169,866 147,826
Receivables 178,258 97,776
------- -------
348,124 245,602
Derivative financial instruments
Put options used for hedging - 977
348,124 246,579
======= =======
Financial liabilities
Trade and other payables 99,589 70,081
Borrowings 99,123 98,633
198,712 168,714
======= =======
All financial liabilities, except for Borrowings (see note 16 )
and non-current lease liabilities (see note 15 ), are due to be
settled within one year and are classified as current liabilities.
All financial liabilities are recognised at amortised cost.
The maturity profile and fair values of the 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 Notes, and the receivables from the
KRG which the Group expects to recover in full (see note 14 ), 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 Notes, as determined using market values at 31
December 2021, was $103.8 million (2020: $102.5 million) compared
to the carrying value of $99.1 million (2020: $98.6 million).
In making the above assessment, consideration has been given to
the fair value hierarchy set out in IFRS 13. Fair value hierarchy
levels 1 to 3 are based on the degree to which the fair value is
observable:
-- Level 1 fair value measurements are those derived from quoted
prices (unadjusted) in active markets for identical assets or
liabilities;
-- Level 2 fair value measurements are those derived from inputs
other than quoted prices included with Level 1 that are observable
for the asset or liability, either directly (i.e. as prices) or
indirectly (i.e. derived from prices); and
-- Level 3 fair value measurements are those derived from
valuation techniques that include inputs for the asset or liability
that are not based on observable market date (unobservable
inputs).
The fair value of the Notes disclosed above is based on Level 1
in the hierarchy.
The financial assets balance includes an $1.1 million provision
against trade receivables (2020: $8.2 million) (see note 14 ). All
financial assets, except derivatives designated as a hedge, 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 structure. The capital structure of the Group
consists of cash, cash equivalents, Notes and equity attributable
to equity holders of the parent. Equity comprises issued capital,
reserves and accumulated losses as disclosed in note 20 and the
Consolidated Statement of Changes in Equity.
19 Financial instruments continued
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 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.
As at year end, the Group did not hold any derivative assets to
hedge against commodity price declines or any other financial
risks. The Group does not use derivative financial instruments for
speculative purposes.
The risks are closely reviewed by the Board on a regular basis
and, where appropriate, steps are taken to ensure these risks are
minimised.
Market risk
The Group's activities expose it primarily to the financial
risks of changes in, oil prices, foreign currency exchange rates
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. 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 2021, 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 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 Notes
semi-annually in cash at 10% per annum.
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.
19 Financial instruments continued
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 2021, the maximum exposure to credit risk
from a trade receivable outstanding from one customer is $175.8
million (2020: $101.3 million). Although the Group is confident in
the recovery of the trade receivables balance, a provision of $1.1
million (2020: $8.2 million) was recognised against the trade
receivables balance.
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 investment
grade 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. The Group seeks to raise further funding as and
when required.
Fair value of derivative instruments
All derivatives are used to hedge against commodity price risk
and are recognised at fair value on the balance sheet with
valuation changes recognised immediately in the income statement
unless the derivatives have been designated as a cash flow hedge.
Fair value is the amount for which the asset or liability could be
exchanged in an arm's length transaction at the relevant date.
Where available, fair values are determined using quoted prices in
active markets. To the extent that market prices are not available,
fair values are estimated by reference to market-based transactions
or using standard calculation techniques for the applicable
instruments and commodities involved.
For derivatives designated as a cash flow hedge, the movements
in the fair value of the derivatives are recognised in other
comprehensive income. Derivatives' maturity and the timing of their
recycling into income or expense coincide.
The Group's derivative instruments' value was as following:
2021 2020
$'000 $'000
----------------------------------------------- ------ ------
Derivatives that are designated and effective
as hedging instruments carried at fair value:
Put option - 977
- 977
====== ======
To manage the Group's oil price risk, put options were entered
into during the year. The first tranche related to H1 2021 and was
entered into at a cost of $2.7 million hedging 1.6 Mbbl with a
floor price of $35/bbl. A second tranche related to Q3 2021 was
entered into at a cost of $1.0 million hedging 0.8 Mbbl with a
floor price of $40/bbl. Costs relating to the put options have been
recognised in revenue (see Note 2 ).
20 Share capital
2021 2020
$'000 $'000
----------------------------------------- ------- -------
Authorised
Common shares of $1 each (2020: $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 Amount capital premium
shares
'000 $'000 $'000 $'000
------------------------- -------- --------- ------------------ ---------
Balance 1 January 2020 229,430 1,101,105 229,430 871,675
Shares cancelled (18,059) (46,820) (18,059) (28,761)
Balance 31 December 2020 211,371 1,054,285 211,371 842,914
Dividends paid - (100,000) - (100,000)
Shares issued 2,360 2,360 2,360 -
Balance 31 December 2021 213,731 956,645 213,731 742,914
======== ========= ================== =========
At 31 December 2021, a total of nil (2020: 1,000,000) common
shares were held in treasury with a value of nil (2020: $2.6
million)
At 31 December 2021, a total of 0.1 million common shares at $1
each were held by the EBT and Exit Event Trustee (2020: 0.1 million
at $1 each). These common shares were included within reserves.
In 2019 and 2020, the company carried out two buy-back
programmes. Following the buy-back programmes completion, the
Company held 19,059,064 shares in treasury of which 18,059,064 were
cancelled in late 2020.
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.
21 Cash flow reconciliation
Notes 2021 2020
Restated(1)
$'000 $'000
----- --------- ------------
Cash flows from operating activities
Profit/(loss) from operations 174,600 (33,381)
Adjustments for:
Depreciation, depletion and amortisation
of property, plant and equipment (including
the right of use assets) 55,111 84,119
Amortisation of intangible assets 25 3
(Decrease)/increase of provision for
impairment of trade receivables 14 (7,065) 6,776
Put option hedging losses reclassified
to revenue 3,752 -
Share-based payment expense 24 1,197 2,440
Lease modification - (97)
Operating cash flows before movements
in working capital 227,620 59,860
Increase in inventories (258) 374(1)
Increase in trade and other receivables (75,259) (523)
Increase / (decrease) in trade and other
payables 36,977 (2,977)
Income taxes received 75 -
--------- ------------
Cash generated from operations 189,155 56,734(1)
--------- ------------
Reconciliation of property, plant and equipment additions to
cash flows from purchase of property, plant and equipment:
2021 2020
Restated
$'000 $'000
-------------------------------------------- ------- ----------
Associated cash flows
Additions to property, plant and equipment 46,417 53,592(1)
Movement in working capital 6,927 12,087
Non-cash movements
Finance lease additions - (1,721)
Capitalised share option charges (409) (197)
Foreign exchange differences 24 (1)(1)
------- ----------
Purchase of property, plant and equipment 52,959 63,760
------- ----------
(1) The comparative cash flow reconciliation has been restated.
For further details, see the Statement of cash flows.
Movement in financing related liabilities
The Group's financing related liabilities are comprised of
borrowings and lease liabilities. The movements in borrowings are
shown in note 16 and the movements in lease liabilities in the year
were primarily cash payments of $0.7 million.
22 Lease Liabilities
2021 2020
$'000 $'000
------------------------------------------------------------------------------------------------- ------- -------
Analysed as:
Current liabilities (note 15 ) 419 718
Non-current liabilities (note 15 ) 789 1,058
------- -------
1,208 1,776
======= =======
Lease liability maturity analysis
Year 1 419 209
Year 2 789 48
Year 3 - -
Year 4 - 1,519
Amounts payable under leases
Within one year 509 720
In the second to fifth year inclusive 868 1,396
------- -------
1,377 2,116
Less future interest charges (169) (340)
Net present value of lease obligations 1,208 1,776
------- -------
23 Commitments
Exploration and development commitments
Additions to property, plant and equipment are generally funded
with the cash flow generated from the Shaikan Field. As at 31
December 2021, gross capital commitments in relation to the Shaikan
Field were estimated to be $20.6 million (2020: $0.6 million).
24 Share-based payments
2021 2020
$'000 $'000
----------------------------------------- ------ ------
Total share options charge 2,664 2,637
Capitalised share options charge (409) (197)
------ ------
Share options charge in Income Statement 2,255 2,440
====== ======
Value Creation Plan ("VCP")
The VCP was approved by shareholders in December 2016. As at 31
December 2021, 3.5 million nil-cost share options were outstanding
under the VCP. There will be no further awards under the plan.
Outstanding awards will vest subject to the Company achieving a
Total Shareholder Return ("TSR") of at least 8% compound annual
growth, in accordance with the VCP rules. Subject to achieving the
requisite TSR, all the outstanding share options will vest
following the Measurement Date for the financial year ending on
31 December 2021.
The requisite TSR was achieved following the Measurement date
for the financial year ended 31 December 2020. The measurement date
for the financial year ended 31 December 2021 has not yet passed as
at the date of this report.
24 Share-based payments continued
2021 2020
Number of Number of
share options share options
'000 '000
--------------------------- -------------- -----------------------
Outstanding at 1 January 7,017 7,017
Exercised during the year (3,509) -
Outstanding at 31 December 3,508 7,017
Exercisable at 31 December 3,508 -
============== =======================
The options outstanding at 31 December 2021 had a weighted
average remaining contractual life of less than one year.
A charge of $0.1 million (2020: $0.8 million) in relation to the
VCP is included in the total share options charge.
Staff Retention Plan
At the 2016 Annual General Meeting ("AGM"), 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 nil-cost 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.
2021 2020
Number of Number of
share options share options
'000 '000
--------------------------- -------------- --------------
Outstanding at 1 January 973 1,129
Exercised during the year (908) (156)
Outstanding at 31 December 65 973
Exercisable at 31 December 65 973
============== ==============
The weighted average share price at the date of exercise for
share options exercised during the year was GBP1.70 (2020:
GBP1.43).
During the year no options (2020: nil) were granted to employees
under the Group's SRP.
A charge of nil (2020: $0.1 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
exercise price of nil and the following expiry dates:
24 Share-based payments continued
Staff Retention Plan (continued)
Expiry date Options ('000)
2021 2020
------------------ -------- -------
11 December 2026 12 516
9 January 2027 - 250
30 June 2027 53 207
65 973
======== =======
The options outstanding at 31 December 2021 had a weighted
average remaining contractual life of 5 years.
Long Term Incentive Plan
The Gulf Keystone Petroleum 2014 Long Term Incentive Plan
("LTIP") is designed to reward members of staff through the grant
of share options at a zero exercise price, that vest three years
after grant, subject to the fulfilment of specified performance
conditions. These performance conditions are 50% TSR over the
vesting period and 50% the Group's TSR relative to a bespoke group
of comparators.
2021 2020
Number of Number of
share options share options
'000 '000
--------------------------- -------------- -----------------------
Outstanding at 1 January 7,254 2,629
Granted during the year 2,747 4,752
Exercised during the year (1,014) -
Forfeited during the year (712) (127)
Outstanding at 31 December 8,275 7,254
Exercisable at 31 December - -
============== =======================
The weighted average share price at the date of exercise for
share options exercised during the year was GBP1.69 (2020:
n/a).
The inputs into the calculation of fair values of the shares
granted during the year are as follows:
2021 2020
--------------------------------------- --------- --------
Weighted average share price GBP2.26 GBP0.88
Weighted average exercise price Nil Nil
Expected volatility 58.7% 54.6%
Expected life 3 years 3 years
Risk-free rate 0.14% 0.08%
Expected dividend yield (on the basis Nil Nil
dividends equivalents received)
========= ========
The options outstanding at 31 December 2021 had a weighted
average remaining contractual life of 2 years.
The aggregate of the estimated fair value of options granted in
2021 is $4.3 million (2020 $2.6 million).
A charge of $2.5 million (2020: $1.7 million) in relation to the
LTIP is included in the total share options charge.
25 Dividend
During 2021, an ordinary dividend of $25 million (11.697 US
cents per Common Share) was paid, followed by a special dividend of
$25 million (11.697 US cents per Common Share) and an interim
dividend for 2021 of $50 million (23.394 US cents per Common Share)
(2020: no dividends were paid). To date in 2022, an interim
dividend of $50 million has been paid. A further $65 million
interim dividend is expected to be paid on 13 May 2022, based on a
record date of 29 April 2022 and ex-dividend date of 28 April 2022.
An ordinary dividend of $25 million is subject to approval at the
AGM on 24 June 2022 and will be paid to shareholders on 15 July
2022 based on a record date of 1 July 2022.
26 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 Directors and Officers
The remuneration of the Directors and Officers who are
considered to be key management personnel is set out below in
aggregate for each of the categories specified in IAS 24 Related
Party Disclosures. The Directors and Officers who served during the
year ended 31 December 2021 were as follows:
J Huijskes - Non-Executive Chairman
M Angle - Deputy Chairman
G Soden - Non-Executive Director
D Thomas - Non-Executive Director
K Wood - Non-Executive Director
J Harris - Chief Executive Officer - (appointed 4 January
2021)
I Weatherdon - Chief Financial Officer
S Catterall - Chief Operations Officer (resigned 18 February
2022)
G Papineau-Legris - Chief Commercial Officer
J Barker - HR Director (resigned 10 September 2021)
C Kinahan - Chief Human Resources Officer (appointed 2 August
2021)
A Robinson - Chief Legal Officer and Company Secretary
The values below are calculated in accordance with IAS 19 and
IFRS 2.
2021 2020
$'000 $'000
------------------------------ ------ ------
Short-term employee benefits 5,809 4,822
Share-based payment - options 1,012 1,273
6,821 6,095
====== ======
Further information about the remuneration of individual
Directors is provided in the Directors' Emoluments section of the
Remuneration Committee Report.
27 Contingent liabilities
The Group has a contingent liability of $27.3 million (2020:
$27.3 million) in relation to the proceeds from the sale of test
production in the period prior to the approval of the original
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. 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, 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 continues to maintain
that pre-FDP petroleum receipts are for the account of the
Contractor. 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.
28 Prior year restatement
The Group has identified that prior year inventory balances
contained certain equipment to be used in the development of the
Shaikan Field, which will be consumed over a period in excess of
one year. The Group determined that this equipment met the
definition of property, plant and equipment as defined by "IAS 16 -
Property, plant and equipment" and has restated the prior year
financial statements to reflect this reclassification.
Comparative figures for the reclassification have been presented
in the balance sheet and statement of cash flows, as detailed
below. There is no impact to the income statement.
Consolidated balance sheet
1 January 2020 Reclassification 1 January 2020
As previously of inventory Restated
reported
$'000 $'000 $'000
------------------------------ -------------- ---------------- --------------
Property, plant and equipment 407,602 24,905 432,507
Inventories 31,040 (24,905) 6,135
31 December Reclassification 31 December
2020 of inventory 2020
As previously Restated
reported $'000
$'000 $'000
------------------------------ -------------- ---------------- -----------
Property, plant and equipment 374,702 30,767 405,469
Inventories 36,527 (30,767) 5,760
Statement of cash flows
31 December Reclassification 31 December
2020 of inventory 2020
As previously Restated
reported $'000
$'000 $'000
------------------------------- -------------- ---------------- -----------
Cash generated from operations 50,873 5,862 56,734
Purchase of property, plant
and equipment (57,899) (5,862) (63,760)
29 Subsequent events
Iraqi Supreme Court ruling
In February 2022, the Iraqi Supreme Court ruled that the
Kurdistan Region of Iraq Oil and Gas Law is unconstitutional. The
ruling also provides that the Iraqi Ministry of Oil may pursue
annulment of Production Sharing Contracts issued by the KRG. The
KRG responded that "it will take all constitutional, legal, and
judicial measures to protect and preserve all contracts made in the
oil and gas sector". The ruling has not impacted the Company's
operations and the Company is continuing to monitor the situation
closely.
Export route availability
The Company currently exports all of its crude oil through the
Kurdistan Export Pipeline, which is 60% owned by Rosneft. As a
result of Russia's invasion of Ukraine on 24 February 2022, the
Company is monitoring the evolving sanctions situation as certain
specific sanctions on Rosneft could impact the Company's ability to
access this pipeline.
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END
FR DGGDXLDDDGDC
(END) Dow Jones Newswires
March 30, 2022 02:00 ET (06:00 GMT)
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