REG - Gulf Keystone Petrol - 2021 Full Year Results Announcement
30/03/2022 07:00
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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
(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 (http://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
(http://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 31 December 2021 Year ended 31 December 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.
2021 2020
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 4.6 (5.9)
assets
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.
2021 2020
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.
2021 2020
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 2021 31 December 2020 1 January 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
Notes Share Cost of hedging reserve Exchange translation reserve Accumulated losses Total
Share premium Treasury equity
capital shares
$'000 $'000 $'000 $'000 $'000 $'000 $'000
229,430 871,675 (29,749) - (3,221) (548,216) 519,919
Balance at 1 January 2020
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 24 - - - - - 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 169,866 147,826
hand
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 28 (amendments) Sale or Contribution of Assets between an Investor and its Associate or Joint
Venture
Amendments to IAS 1 Classification of Liabilities as Current or Non-current
Amendments to IFRS 3 Reference to the Conceptual Framework
Amendments to IAS 16 Property, Plant and Equipment-Proceeds before Intended Use
Amendments to IAS 37 Onerous Contracts - Cost of Fulfilling a Contract
Annual Improvements Amendments to IFRS 1 first time adoption of IFRS, IFRS 9 financial instruments
IFRS 16 Leases and IAS 41 Agriculture.
Standards 2018-20
Amendments to IAS 1 and IFRS Practice Statement 2 Disclosure of Accounting Policies
Amendments to IAS 8 Definition of Accounting Estimates
Amendments to IAS 12 Deferred Tax related to Assets and Liabilities 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 financial 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 impairment 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 began
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 318 350(1)
accounts
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 £250,000 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
(#_4_Other_general) ).
11 Property, plant and equipment
Oil and gas Fixtures and Right of use assets Total
assets equipment
$'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 (#_3_Cost_of) ). 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 incorporation Proportion of ownership interest Principal
activity
Gulf Keystone Petroleum (UK) Limited United Kingdom 100% Management, support, geological, geophysical and engineering services
6th floor
New Fetter Place
8-10 New Fetter Lane
London EC4A 1AZ
Gulf Keystone Petroleum International Limited Bermuda 100% Exploration, evaluation, development and production activities in Kurdistan
Cedar House, 3rd Floor
41 Cedar Avenue
Hamilton HM12
Bermuda
Name of joint operation Location Proportion of ownership interest Principal
activity
Shaikan Kurdistan 80% Production and development activities
( )
13 Inventories
31 December 2021 31 December 2020 1 January
Restated 2020
$'000 $'000 Restated
$'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 price 2021 2020
$'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 tax depreciation Share-based payments Tax losses carried forward Total
$'000 $'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 (#_2_Revenue) ).
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 shares Amount capital premium
'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 55,111 84,119
(including the right of use assets)
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 £1.70 (2020: £1.43).
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)
Options ('000)
Expiry date
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 £1.69 (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 £2.26 £0.88
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 dividends equivalents received) Nil Nil
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 5,809 4,822
benefits
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 of inventory 1 January 2020
As previously reported Restated
$'000 $'000
$'000
Property, plant and equipment 407,602 24,905 432,507
Inventories 31,040 (24,905) 6,135
31 December 2020 Reclassification of inventory 31 December 2020
As previously reported Restated
$'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 2020 Reclassification of inventory 31 December 2020
As previously reported Restated
$'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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