TIDMGKP
RNS Number : 9311T
Gulf Keystone Petroleum Ltd.
23 March 2023
23 March 2023
Gulf Keystone Petroleum Ltd. (LSE: GKP)
("Gulf Keystone", "GKP", "the Group" or "the Company")
2022 Full Year Results Announcement and Competent Person's
Report Update
Strong 2023 production, recently exceeding 55,000 bopd
2022 CPR confirms 817 MMstb of gross 2P reserves + 2C resources,
with 100% replacement of production
Record 2022 free cash flow and profitability drove sector
leading dividend yield
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 2022 and the 2022 Competent Person's
Report.
Jon Harris, Gulf Keystone's Chief Executive Officer, said:
"We delivered strong operational and financial performance in
2022 in line with our clear strategy of balancing investment in
profitable production growth with sustainable shareholder returns,
while maintaining a robust balance sheet and prudent liquidity
levels. Higher oil prices and production, combined with continued
capital discipline and cost control, enabled us to generate record
profitability and cash flow, funding increased investment in future
production growth, record dividends of $215 million and the
repayment of our $100 million bond resulting in a debt-free balance
sheet.
The benefits of our 2022 investment programme and progress on
executing the Jurassic scope of the Shaikan Field Development Plan
contributed to a material increase in gross average production to
around 53,500 bopd in March 2023, hitting a new record of over
55,000 bopd in the last few days, an important milestone for GKP.
In addition, we are pleased that the 2022 CPR has confirmed the
Shaikan Field's significant growth potential and gross 2P + 2C
reserves and resources of 817 MMstb, with 100% reserves replacement
since the 2020 CPR.
Looking ahead we are reviewing our forward capital programme in
light of continued delays to KRG payments to ensure that we
maintain a prudent financial position as we continue to develop the
Jurassic reservoir and advance towards approval of the FDP. As
ever, we remain committed to balancing growth with shareholder
returns and financial strength, confirmed by our declaration today
of a final 2022 ordinary annual dividend of $25 million, increasing
total dividends declared in 2023 to $50 million."
Highlights to 31 December 2022 and post reporting period
Operational
-- Zero Lost Time Incidents ("LTIs") in 2022, despite
significant increase in operational activity
o Following an LTI in January 2023 during drilling operations,
remedial actions have been implemented
-- Gross average production for 2022 of 44,202 bopd (2021:
43,440 bopd), in line with annual guidance
-- Executing the Jurassic scope of the Field Development Plan
("FDP") with the agreement of the Ministry of Natural Resources
("MNR"), with 2022 activity laying the foundation for higher future
production
o Drilled and brought online SH-15 and SH-16, the first two
Jurassic wells in the FDP sequence, on schedule and on budget, and
partially drilled SH-17
o Prepared well pads and flowlines to enable a continuous
drilling programme
o Completed initial engineering and construction works and
procurement of long lead items for production facility expansion
and installation of water handling
-- Realising benefits of 2022 investments with recent material
increase in production to record highs
o 2023 year to date gross average production of c.48,900 bopd,
with gross average production in March to date of c.53,500 bopd and
production of c.55,000 bopd in the last few days
o Production growth driven by continued ramp up of SH-16
following start-up in December 2022, start-up of SH-17 in February
2023, and our well workover programme
o Minor impact from temporary suspension of pipeline exports in
February 2023 following the tragic earthquakes in Turkey and
Syria
-- Continuous drilling programme delivering improvements in drilling performance
o SH-17 drilled, completed and brought onstream in February
2023, under budget and ahead of schedule
o Drilling of SH-18 progressing well with expected start up in
Q2 2023, in line with prior guidance
Financial
-- Record profitability and cash generation in 2022, driven by a
strong increase in the oil price, higher production and our
continued focus on cost control
o Adjusted EBITDA increased by 61% to $358.5 million (2021:
$222.7 million)
o Profit after tax increased 62% to $266.1 million (2021: $164.6
million)
o Gross Opex per barrel of $3.2/bbl (2021: $2.7/bbl), in line
with the Company's 2022 guidance range of $2.9-$3.3/bbl and
reflecting higher operational activity
o Realised price per barrel increased by 49% to $74.1/bbl (2021:
$49.7/bbl)
o While the Company has not accepted the MNR's proposed change
to the pricing mechanism for Shaikan oil sales, changing the
reference price from Dated Brent to the Kurdistan Blend ("KBT")
effective 1 September 2022, revenue from September 2022 to December
2022 has been recognised on this basis, resulting in an average
reduction in the realised sales price versus the previous pricing
mechanism over the period of approximately $12/bbl or $23.4
million
o The KBT discount to Dated Brent has tightened since November
2022, with the impact on Shaikan realised prices versus the
previous pricing mechanism decreasing to $6/bbl in February
2023
-- Increased investment in the Shaikan Field while maintaining
capital discipline to drive future profitable production growth
o Net capital expenditure of $114.9 million (2021: $46.2
million), in line with final 2022 guidance of $110-$120 million
-- $63.4 million: Drilling of SH-15, SH-16 and partial drilling
of SH-17 that was completed in early 2023
-- $35.8 million: Early work for the expansion of the production
facilities with water handling capacity, as well as future well pad
preparation including flowlines
-- $15.7 million: Well workover and interventions to optimise
production
-- Strong free cash flow generation funded continued delivery of
our strategy to balance growth with shareholder returns while
maintaining a robust balance sheet and prudent liquidity levels
o Free cash flow generation of $266.5 million, more than double
the prior year (2021: $122.2 million)
o Record dividends of $215 million, representing a
sector-leading dividend yield of 41% based on the closing share
price on 31 December 2022. Since the beginning of 2023, GKP has
paid an additional interim dividend of $25 million
o Redeemed $100 million outstanding bond in August 2022, leaving
the Company debt free with significant financial flexibility
o Cash balance of $118.8 million at 22 March 2023
-- Revenue receipts of $450.4 million net to GKP received from
the Kurdistan Regional Government ("KRG") in 2022 for crude oil
sales and repayment of historical revenue arrears
o While the Company has received $65.7 million net from the KRG
in 2023 for August and September 2022 oil sales, overdue
receivables for the months of October to December 2022 total $76.0
million net on the basis of the KBT pricing mechanism
2022 Competent Person's Report
-- GKP announces today the 2022 Competent Person's Report ("2022
CPR"), an updated independent third-party evaluation of the Shaikan
Field's reserves and resources prepared by ERC Equipoise
("ERCE")
-- 2022 CPR incorporates significant incremental information,
including an updated field development plan, new wells, production
data and further technical analysis, since the previous 2020 CPR
also prepared by ERCE
-- Gross 2P+2C reserves and resources of 817 MMstb as at 31
December 2022, 52 MMstb higher than the previous 2020 CPR after
adjusting for production in 2021 and 2022
o Gross 2P reserves of 506 MMstb increased 34 MMstb or 7%
relative to 2020 CPR volumes adjusted for production, resulting in
100% reserves replacement over the two-year period
o Increase driven by higher plateau rate of 85,000 bopd from the
Jurassic reservoir
o Gross 1P reserves of 199 MMstb decreased 8 MMstb or 4%
relative to 2020 CPR volumes adjusted for production due to prudent
management of production rates to avoid traces of water ahead of
water handling installation
o Gross 2C resources of 311 MMstb increased 18 MMstb or 6%
relative to 2020 CPR volumes due to higher planned production
processing capacity
-- 2022 CPR highlights the significant growth potential of the Shaikan Field, with a gross 2P reserves-to-production ratio of 31 years based on 2022 gross average production, and reaffirms our deep understanding and prudent management of the reservoir, which has produced over 117 MMstb to date
Gross reserves and resources(1) based on the 2022 CPR compared
to the 2020 CPR are as follows:
Reserves Resources
---------- -----------------
Formation (MMstb) 1P 2P 2C(2) 2P+2C(2,3)
------------------ ---- ---- ----- ----------
31 December 2022
Jurassic 199 506 101 607
Triassic - - 157 157
Cretaceous - - 53 53
------------------ ---- ---- ----- ----------
Total (gross) 199 506 311 817
------------------ ---- ---- ----- ----------
31 December 2020
Jurassic 240 505 80 585
Triassic - - 157 157
Cretaceous - - 56 56
------------------ ---- ---- ----- ----------
Total (gross) 240 505 293 798
------------------ ---- ---- ----- ----------
The reconciliation of changes in reserves and resources between
the 2020 CPR and the 2022 CPR is as follows:
Reserves Resources
---------- -----------------
Gross (MMstb) 1P 2P 2C(2) 2P+2C(2,3)
------------------------------------------- ---- ---- ----- ----------
31 December 2020 240 505 293 798
2021 & 2022 production (33) (33) - (33)
------------------------------------------- ---- ---- ----- ----------
31 December 2020 (adjusted for production) 207 472 293 765
------------------------------------------- ---- ---- ----- ----------
Revisions (8) 34 18 52
------------------------------------------- ---- ---- ----- ----------
31 December 2022 199 506 311 817
------------------------------------------- ---- ---- ----- ----------
GKP's 80% net working interest ("WI")(4) share of reserves and
resources at 31 December 2022 are:
Reserves Resources
---------- -----------------
Formation (80% WI) (MMstb) 1P 2P 2C(2) 2P+2C(2,3)
--------------------------- ---- ---- ----- ----------
Jurassic 159 405 81 486
Triassic - - 126 126
Cretaceous - - 42 42
--------------------------- ---- ---- ----- ----------
Total (net WI) 159 405 249 654
--------------------------- ---- ---- ----- ----------
(1) Reserves and resources have been calculated in accordance with the June 2018 SPE/WPC/AAPG/ SPEE/SEG/SPWLA/EAGE Petroleum Resources Management System).
(2) Contingent resources volumes are classified as such because
there is technical and commercial risk involved with their
extraction. In particular, there may be a chance that accumulations
containing contingent resources will not achieve commercial
maturity. The 2C (best estimate) contingent resources presented are
not risked for chance of development. All Contingent resource
volumes quoted in this document are volumes which could be
extracted prior to license expiry.
(3) Aggregated 2P+2C estimates should be used with caution as 2C
contingent resources are commercially less mature than the 2P
reserves.
(4) Net working interest reserves and resources do not represent
the net entitlement resources under the terms of the Production
Sharing Contract ("PSC").
Outlook
-- Given continued delays to KRG payments, we are currently
reviewing our forward capital programme and 2023 net capital
expenditure guidance of $160-$175 million
o With further clarity around KRG payments, we would consider
continued drilling following SH-18
o With continued payment delays, we would review reductions to
our capital programme
-- Looking ahead, subject to timely KRG payments and oil prices,
we are focused on transitioning towards capitalising on the
significant growth potential of the Shaikan Field, as confirmed by
the 2022 CPR, and attractive returns on capital from the
accelerated payback of investment as we recover our historic
costs
o Targeting step up in production levels through execution of
the Jurassic scope of the FDP, drilling additional Jurassic wells
and expanding the production facilities
o While timing of FDP approval remains uncertain, we continue to
advance towards key project sanction milestones, including the
conclusion of the Gas Management Plan ("GMP") tendering process
and, as appropriate, financing arrangements
-- We are committed to balancing profitable production growth,
shareholder returns and a robust balance sheet according to our
disciplined financial framework, in line with our historic track
record
o Following payment of $25 million interim dividend in March, we
are pleased to announce declaration of a final 2022 ordinary annual
dividend of $25 million, in line with the Company's dividend
policy
o Subject to approval at the AGM on 16 June 2023, we expect to
pay final dividend on 21 July 2023, based on a record date of 7
July 2023 and ex-dividend date of 6 July 2023
o Total dividends declared in 2023 of $50 million, equating to
an 11% yield for year to date 2023, based on the closing share
price on 22 March 2023
o The Board remains committed to distributing excess cash to
shareholders via dividends and/or share buybacks and will continue
to review distributions based on our disciplined financial
framework, as outlined in our 30 January 2023 trading update, which
includes regular assessment of the Company's expected liquidity,
cash flow generation and investment needs
-- Continue to monitor discussions between the Federal Iraqi
Government and the KRG on the management of oil and gas assets in
Kurdistan following the Iraqi Federal Supreme Court ruling in
February 2022. GKP's operations currently remain directly
unaffected
2023 guidance
-- 2023 guidance remains dependent on timely KRG payments and
oil prices. The Company will consider adjustments to the capital
programme based on how the business environment evolves
-- We remain focused on delivering 2023 gross average production
of 46,000-52,000 bopd, representing a 11% increase from 2022 at the
mid-point
o Reflects anticipated contributions from SH-17 and SH-18, as
well as the benefits of well workovers
o Continue to manage natural field declines, well production
rates ahead of water handling installation and higher gas
production from one of our wells near the gas cap, in line with our
reservoir modelling
-- Current 2023 net capital expenditure guidance of $160-$175 million:
o $30-$35 million: Completion of SH-17, drilling and completion
of SH-18 and well workover programme to optimise production
o $45-$50 million: Long lead items and preparing well pads to
enable continuous drilling
o $85-$90 million: Continued expansion of production facilities,
targeting by H2 2024 an increase in total field capacity from
c.60,000 bopd currently to 85,000 bopd and installation of water
handling capacity, potentially enabling the increase in production
rates from constrained wells
-- 2023 gross Opex guidance of $3.0-$3.4/bbl unchanged,
underpinned by the Company's continued focus on strict cost
control
Investor & analyst presentation
GKP's management team will be hosting a presentation for
analysts and investors at 10:00am (GMT) today via live audio
webcast:
https://brrmedia.news/GKP_FY2022
Management will also be hosting an additional webcast
presentation focused on retail investors via the Investor Meet
Company ("IMC") platform at 12:00pm (GMT) today. The presentation
is open to all existing and potential shareholders and participants
will be able to submit questions at any time during the event.
https://www.investormeetcompany.com/gulf-keystone-petroleum-ltd/register-investor
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
FTI Consulting +44 (0) 20 3727 1000
Ben Brewerton GKP@fticonsulting.com
Nick Hennis
or visit: www.gulfkeystone.com
Notes to Editors:
Gulf Keystone Petroleum Ltd. (LSE: GKP) is a leading independent
operator and producer in the Kurdistan Region of Iraq. Further
information on Gulf Keystone is available on its website
www.gulfkeystone.com
Disclaimer
This announcement contains certain forward-looking statements
that are subject to the risks and uncertainties associated with the
oil & gas exploration and production business. These statements
are made by the Company and its Directors in good faith based on
the information available to them up to the time of their approval
of this announcement but such statements should be treated with
caution due to inherent risks and uncertainties, including both
economic and business factors and/or factors beyond the Company's
control or within the Company's control where, for example, the
Company decides on a change of plan or strategy. This announcement
has been prepared solely to provide additional information to
shareholders to assess the Group's strategies and the potential for
those strategies to succeed. This announcement should not be relied
on by any other party or for any other purpose.
Chairman's statement
Gulf Keystone benefitted from strong oil prices in 2022, with
Dated Brent averaging $101/bbl in the year, up $30/bbl from 2021.
However, volatility was high, with peaks of around $130/bbl in the
first half of the year declining in the second half to around
$80/bbl in December, as concerns around energy security and supply
deficits, driven primarily by the tragic conflict in Ukraine and
recovery in global economic demand, transitioned to market fears of
inflationary pressures, fiscal tightening and recession.
From an operational perspective, working patterns in the Shaikan
Field and our offices returned to normal following the disruption
caused by the COVID-19 pandemic. Safety was a major focus for the
team as activity ramped up, and the Board and I are pleased with
the Company's performance in 2022. The Company is continuing to
manage tightness in regional and global supply chains, with ongoing
pressure on equipment lead times and cost pressures.
Looking at the geopolitical environment, while security in
Kurdistan was relatively stable in the year, the Iraqi Federal
Supreme Court ruling in February 2022 led to heightened tensions in
the longstanding dispute between Federal Iraq and the KRG regarding
oil and gas assets in Kurdistan. The situation has improved since
the formation of a new Federal Iraqi government in October 2022,
with an active dialogue taking place between both sides.
Nonetheless, it remains difficult to predict outcomes and the Board
continues to monitor the situation closely. We also continue to
closely monitor and engage with the KRG regarding the delays to
recent oil sales payments and the negotiation of a new lifting
agreement. While historically payments have been made, the recent
delays have been disappointing. We are experienced operating in
Kurdistan and look to maintain a prudent level of liquidity and
flexible capital programme to manage through periods of
uncertainty.
Against this backdrop, GKP delivered strong operational and
financial results in 2022 and continued execution of its strategy
of balancing investment in growth with sustainable shareholder
returns, while maintaining a robust balance sheet and prudent
liquidity levels.
From an operational perspective, the Company achieved its 2022
production guidance and completed a significant work programme,
paving the way for expected future increases in production. The
Company also advanced towards approval of the Shaikan Field
Development Plan ("FDP"). From a financial perspective, strong oil
prices and continued cost control and capital discipline supported
significant cash flow generation, enabling the Company to fund its
investment programme, pay record dividends to shareholders of $215
million and strengthen its balance sheet through the early
redemption of the outstanding $100 million bond. The Company
delivered top quartile total shareholder returns of 57% in the
year, assuming dividends reinvested.
The Company has seen a material increase in production in 2023,
with production recently exceeding 55,000 bopd. The achievement of
this important milestone has been supported by the Company's 2022
investments and decision to proceed with the execution of the FDP's
Jurassic scope.
Looking ahead to 2023, the Company is currently reviewing its
forward capital programme in light of continued delays to KRG
payments. Subject to timely payments and oil prices, the Company
will continue to transition to increased investment in profitable
production growth while advancing towards key project sanction
milestones of the full FDP, which the Board expects to maximise
long-term value for shareholders and Kurdistan. The Board and I are
pleased the 2022 Competent Person's Report reaffirms the
significant growth potential of the Shaikan Field, with 817 MMstb
2P reserves and 2C resources, 100% reserves replacement since the
2020 CPR and a 2P reserves-to-production ratio of 31 years.
As the Company progresses, the Board will manage the balance
between investment in growth, shareholder returns and balance sheet
strength according to a disciplined financial framework.
The Board is committed to paying an ordinary dividend of at
least $25 million per annum and distributing excess cash to
shareholders by way of dividends and/or share buybacks. In
determining the level of distributions, the Board regularly reviews
the Company's expected liquidity, cash flow generation and
investment needs. We are pleased to have declared total dividends
in 2023 date of $50 million, including the declaration of a $25
million 2022 ordinary annual dividend for shareholder approval at
the Company's AGM on 16 June 2023.
Sustainability continues to be a strategic priority for GKP and
the Board has direct oversight and responsibility for the Company's
strategy. The strategy has a number of objectives, of which
addressing climate-related risks and opportunities is key. For
fiscal year 2022, the Company's disclosures are fully consistent
with all of the Taskforce on Climate-related Financial Disclosures
("TCFD") recommendations, reflecting how a focus on climate-related
risks and opportunities is embedded into the Company's strategy and
governance, including risk management. The Company also continued
to make significant progress in the year in supporting the
development of its workforce, increasing gender diversity,
generating material economic and social value for Kurdistan and the
Company's local communities, as well as continuing to maintain
strong corporate governance, ethical business conduct and
compliance.
The Board continued to engage with the Company's shareholders in
2022 and welcomes ongoing interaction and feedback with all
investors. We encourage GKP shareholders to participate in our
Annual General Meetings, which are accessible virtually to all
investors. While we saw voting turnout improve at the 2022 AGM, it
remained low relative to prior years and we continue to look at
ways to improve shareholder participation and voting at future
general meetings.
We were delighted in July 2022 to welcome Wanda Mwaura to the
Board as a new Non-Executive Director and member of the Audit and
Risk Committee. Wanda brings over 25 years of expertise and
experience in accounting, external and internal audit, consulting,
regulatory and corporate governance to GKP. She is highly respected
and complements the Board with her extensive skill set.
GKP's 2022 Full Year Results and Annual Report will be my last
as Non-Executive Chairman, as I prepare to hand over the role
following the 2023 AGM. It has been a distinct privilege to serve
as Chairman of GKP and I am proud of the significant achievements
and progress the Company has made during my tenure to create value
for its shareholders, Kurdistan and broader stakeholder base.
Since my appointment in 2018, GKP has increased gross average
production from an average of 31,563 bopd in 2018 to over 55,000
bopd recently. In the same period, GKP has distributed $440 million
in dividends and share buybacks to shareholders, generated more
than $1.8 billion in gross revenues for the KRG from the Shaikan
Field and maintained a strong balance sheet throughout, against a
backdrop of commodity price volatility and the COVID-19 pandemic.
This performance has been underpinned by a rigorous focus on safety
and sustainability and strong leadership from the Board, with
regular Director visits to the Company's operations in
Kurdistan.
I am delighted to be succeeded by Martin Angle, my esteemed
fellow Director and current Deputy Chairman and Senior Independent
Director ("SID"), and that Martin's Deputy Chair and SID roles will
be taken on by Kimberley Wood, currently independent Non-Executive
Director. I have worked with both Martin and Kimberley since 2018
and they have both made an enormous contribution to the Company and
to the Board. Their experience and expertise will be invaluable to
GKP's future success.
On behalf of the Board, I would like to thank GKP's leadership
team and all of the Company's employees for their continued
commitment to safety, delivery of the Company's strategy and
relentless focus on creating value for GKP's shareholders and
stakeholder base. We are excited about the future and the year of
significant activity ahead.
Jaap Huijskes
Non-Executive Chairman
22 March 2023
CEO review
In 2022, we delivered strong operational and financial
performance as we continued to execute our clear strategy of
balancing investment in profitable growth with shareholder returns
while maintaining a robust balance sheet.
We commenced the execution of the Phase 1 Shaikan Field
Development Plan ("FDP") Jurassic scope with the agreement of the
MNR, comprising additional wells (with SH-15 and SH-16 completed in
2022 and SH-17 and SH-18 completed or currently underway in 2023)
and early works related to the expansion of our production
facilities. We also delivered another year of record production and
made good progress towards key FDP sanction milestones.
We generated record Adjusted EBITDA in 2022, driven by higher
production, strong oil prices and a continued focus on cost
management and efficiency, resulting in a more than doubling of
free cash flow to $266 million. Strong cash flow generation enabled
us to fund our capital programme and pay sector leading dividends
to our shareholders of $215 million, bringing total shareholder
distributions to $415 million since 2019, while at the same time
strengthening our balance sheet through the redemption of our $100
million bond. We are now debt free.
Our performance, as always, was underpinned by a rigorous focus
on safety, with zero Lost Time Incidents ("LTI") in the year and
only one recordable incident.
Gross average production in 2022 was 44,202 bopd, within our
annual guidance range. Despite the small increase versus 2021, our
2022 work programme has laid the foundations for a material
increase in future production. Our drilling performance is
improving and we are delivering wells on or below budget. The
latest well, SH-18, is progressing well and we expect start up in
Q2 2023, in line with our previous guidance. Continuous drilling
has been facilitated by our investment in well pad preparation,
flowlines and long lead items. In addition, completion of early
work for the production facility expansion in 2022 has positioned
us to increase total field processing capacity to 85,000 bopd and
install water handling capacity in H2 2024.
As we enter 2023, it is clear that our investments in 2022 and
decision to progress the Jurassic scope of the FDP are beginning to
pay off. Gross average production in 2023 year to date has been
c.48,900 bopd, while gross average production in March to date has
been c.53,500 bopd, including the achievement of a new production
record of over 55,000 bopd in the last few days, an important
milestone for the Company.
We continue to see significant growth potential from the Shaikan
Field, with the 2022 Competent Person's Report confirming gross 2P
reserves and 2C resources of 817 MMstb, 52 MMstb higher than the
previous CPR from 2020 after adjusting for production. The 2022 CPR
shows 100% reserves replacement, driven by a higher plateau rate of
85,000 bopd from the Jurassic reservoir and accelerating post
license production.
In addition, we see an excellent opportunity to create value for
our shareholders. Returns on capital from incremental investment in
the Shaikan Field are attractive, as the payback of investment
under the Shaikan Production Sharing Contract accelerates as we
recover our historic costs. By increasing profitable production, we
also expect to enhance the sustainability and longevity of the
Company's capacity for shareholder distributions.
Looking ahead, our intention is to continue our transition
towards increased investment in profitable production growth,
expanding the Jurassic reservoir while advancing towards key
project sanction milestones of the FDP. However, given continued
delays to KRG payments, we are currently reviewing our forward
capital programme and 2023 net capital expenditure guidance of
$160-$175 million. With further clarity around KRG payments, we
would consider continued drilling following SH-18. However, we will
also review potential reductions to our capital programme should
payment delays continue.
As we increase investment in profitable production growth
through a flexible capital programme, we remain focused on
delivering against our strategy of balancing growth with
sustainable shareholder returns, while maintaining a robust balance
sheet and prudent liquidity levels. We are pleased to declare a
final 2022 ordinary annual dividend of $25 million subject to
shareholder approval at the AGM on 16 June 2023, increasing total
dividends declared in 2023 to $50 million and equating to an 11%
yield for 2023, based on the closing share price on 22 March 2023.
The Board remains committed to distributing excess cash to
shareholders by way of dividends and/or share buybacks and will
continue to review distribution decisions based on a disciplined
financial framework.
We have an exciting year ahead of us at Gulf Keystone and a
number of opportunities to create significant value for our
shareholders and broader stakeholder base. I want to provide my
heartfelt thanks to GKP's teams in Kurdistan and the UK, whose
continued hard work and innovation are enabling the Company to
deliver against its strategy. I would also like to thank Jaap
Huijskes, who will be stepping down following the 2023 AGM, for all
his help and stewardship in my first two years as CEO. I wish him
well for the future.
Jon Harris
Chief Executive Officer
22 March 2023
Operational review
We delivered strong operational performance in 2022, safely
achieving higher production while investing in future growth and
further advancing towards approval of the Shaikan Field Development
Plan ("FDP"). We also continued to execute our sustainability
strategy with progress in several areas.
Throughout the year, the health and safety of our workforce and
local communities remained our priority. We were pleased to record
zero Lost Time Incidents ("LTIs") in 2022, despite a more than 50%
increase in working hours to 2.2 million hours. Unfortunately, we
experienced an LTI in January 2023 during drilling operations and
we are implementing remedial actions. As at 22 March 2023, we have
been operating for over 60 days without an LTI.
We achieved gross average production of 44,202 bopd in 2022, a
2% increase versus 2021 and in line with our revised annual
guidance range of 44,000-47,000 bopd. Production was supported by
incremental volumes from SH-13 and SH-14, brought on-stream in
December 2021, and from SH-15 and SH-16, which started up in April
and December 2022 respectively. Increases were mostly offset by the
continued prudent management of well production rates to avoid
trace amounts of water production ahead of installation of water
handling capacity, including the shut-in of SH-12 for most of H1
2022, as well as the temporary shut-in of one well during Q4 2022
due to an isolated Electrical Submersible Pump ("ESP") electrical
failure.
We delivered a significant work programme in 2022 as we
commenced execution of the FDP Jurassic scope that positions us to
drive profitable future production growth. Drilling activities in
2022 included the start-up of SH-15 and SH-16 and spud of SH-17
which was completed in early 2023 and started producing in February
2023. We have seen the benefit of a continuous drilling programme
with a general decline in drilling costs and times, while
investments in the year in well pad preparation, flowline
installation and long lead items have enabled us to maintain
momentum.
In addition, we advanced the expansion of the production
facilities in the year, carrying out early engineering and
construction work and progressing the procurement of long lead
items, despite ongoing equipment lead time and cost pressures,
positioning us to increase total field processing capacity to
85,000 bopd and install water handling capacity in H2 2024. Water
handling capacity will potentially enable us to increase production
rates from constrained wells which we are currently prudently
managing to avoid traces of water.
Shaikan Field Development Plan
We are continuing to progress towards approval of the FDP. Since
the initial draft was submitted in November 2021, we have engaged
extensively with the MNR and have substantially finalised the
technical scope and future work programme. We continue to progress
key project milestones, including optimising the work programme to
phase activity and facilitate accelerated cost recovery,
negotiating commercial terms including a potential update to the
Shaikan Production Sharing Contract ("PSC") with the target of
ensuring changes are at least value neutral, and concluding the Gas
Management Plan tendering process and, as appropriate, financing
arrangements.
As we progress, we have agreed with the MNR to execute the
Jurassic scope of the FDP before approval, to date drilling or in
the process of drilling a total of four FDP wells - SH-15, SH-16,
SH-17 and SH-18 - and advancing the expansion of the production
facilities. We remain focused on testing the Triassic reservoir,
targeting initial pilot production of up to 10,000 bopd, and
implementing the Gas Management Plan, which, depending on timely
sanction and implementation, will enable us to eliminate almost all
routine flaring, a requirement of the PSC, and more than halve our
Scope 1 emissions intensity by 2025 versus the original 2020
baseline.
2022 Competent Person's Report
We are pleased to announce the 2022 Competent Person's Report,
an updated independent third-party evaluation of the Company's
reserves and resources prepared by ERC Equipoise. The 2022 CPR
incorporates significant incremental information, including an
updated field development plan, new wells, production data and
further technical analysis, since the previous CPR dated 31
December 2020 also prepared by ERCE.
The 2022 CPR confirms the Shaikan Field's significant gross 2P
reserves and 2C resources of 817 MMstb, 52 MMstb higher than the
previous 2020 CPR after adjusting for production during the period.
It underlines the significant growth potential of the asset, with a
gross 2P reserves-to-production ratio of 31 years, based on 2022
gross production. It also reaffirms our deep understanding of the
reservoir, which has produced over 117 MMstb to date.
Gross 2P reserves have increased 7% to 506 MMstb relative to
2020 CPR volumes adjusted for production, with 100% reserves
replacement during the period. The increase is driven by the higher
plateau rate of 85,000 bopd from the Jurassic reservoir, bringing
more reserves volumes into the license period. Gross 1P reserves of
199 MMstb are 4% lower relative to 2020 CPR volumes adjusted for
production due to prudent management of production rates to avoid
traces of water ahead of water handling installation.
Gross 2C resources of 311 MMstb have increased 6% relative to
2020 CPR volumes due to higher planned production processing
capacity.
Current operational activity and 2023 outlook
We have seen a step-up in production in 2023, with gross average
year to date production of c.48,900 bopd and gross average
production in March to date of c.53,500 bopd. In the last few days,
we are delighted that production has exceeded 55,000 bopd.
Production growth has been supported by the continued ramp up of
SH-16, production from SH-17, which we are gradually ramping up,
and our well workover programme. Production increases have more
than offset the minor impact of the temporary suspension of
pipeline exports in February following the tragic earthquakes in
Turkey and Syria.
Looking ahead to the rest of the year, we are currently
reviewing our forward capital programme and 2023 net capital
expenditure guidance of $160-$175 million, given continued delays
to KRG payments. Our current guidance includes the completion of
SH-17 and the drilling and completion of SH-18, further investment
in well pad preparation and long lead items for continuous drilling
and the continued progression of the production facility expansion.
With further clarity around KRG payments, we would consider
continued drilling following SH-18. However, we will also moderate
investment levels should payment delays continue.
We remain focused on delivering our production guidance of
46,000-52,000 bopd, representing 11% growth at the mid-point versus
2022, as we continue to target start-up of SH-18 in Q2 2023. While
we have seen strong recent production, we continue to manage well
production rates ahead of water handling installation and are
optimising production from a single well near the gas cap due to
higher gas production, in line with our reservoir modelling.
Estimated base natural declines of 6-10% per annum across the
Shaikan Field remain low relative to the industry and are in line
with our expectations and development plan, even following
production of over 117 million barrels to date.
Sustainability strategy
We continued to deliver against our sustainability strategy in
2022, which is critical to the creation of long-term value for all
our stakeholders and our licence to operate. Our strategic
priorities include working safely, minimising our impact on the
environment, addressing climate change, enhancing diversity &
inclusion, generating local economic value and strong governance
and compliance.
There were a number of highlights to note, which we will publish
as part of our 2022 Annual Report and Sustainability Report, but I
am particularly pleased that this year our disclosures are fully
consistent with all of the TCFD recommendations as the Company
continues to address climate-related risks and opportunities, in
particular through progression of the Gas Management Plan tendering
process and development of a number of other decarbonisation
opportunities.
As we progress, we expect to see increases in our emissions
principally due to higher oil production and higher gas production
from a single well near the gas cap. Subject to timely sanction and
implementation, the Gas Management Plan will enable us to eliminate
almost all our routine flaring and more than halve our Scope 1
emissions intensity by 2025. We are also targeting further
emissions reductions through other decarbonisation projects and are
proceeding in the near term to eliminate methane venting from our
production facility storage tanks, which we expect to complete in
2024.
We also continued to make a significant contribution to
Kurdistan and our local communities, generating $515 million net
from the Shaikan Field for the KRG, employing almost 350 Kurdistan
nationals, representing three-quarters of our workforce in country,
increasing our purchasing and contracting with local suppliers by
31% to $64 million and spending over $1 million gross on impactful
projects for our local communities focused on agriculture,
education and infrastructure. In addition, we remain focused on
investing in the development of our people and improving the
diversity of our teams. The proportion of women in our workforce
increased to 14% in 2022 from 9% in 2021, a figure which we hope to
build momentum on into 2023 and beyond.
John Hulme
Chief Operating Officer
22 March 2023
Financial review
Year ended Year ended
31 December 2022 31 December 2021
Gross average production (1) bopd 44,202 43,440
Dated Brent (2) $/bbl 101.4 70.8
R ealised price (1) $/bbl 74.1 49.7
Discount to Dated Brent $/bbl 27.2 21.1
Revenue $m 460.1 301.4
Operating costs $m 41.9 34.4
Gross operating costs per barrel
(1) $/bbl 3.2 2.7
Other general and administrative
expenses $m 12.2 13.6
Incurred in relation to Shaikan
Field $m 5.2 4.1
Corporate G&A $m 7.0 9.5
Share option expense $m 13.8 8.5
Adjusted EBITDA (1) $m 358.5 222.7
Profit after tax $m 266.1 164.6
Basic earnings/(loss) per share cents 123.5 77.14
Revenue and arrears receipts
(1) $m 450.4 221.7
Net capital expenditure (1)(3) $m 114.9 46.2
Free cash flow (1) $m 266.5 122.2
Dividends $m 215 100
Cash and cash equivalents $m 119.5 169.9
Face amount of the Notes $m 0.0 100.0
Net cash (1) $m 119.5 69.9
------------------------------------ ------ ---------------- ----------------
(1) Gross average production, realised price, gross operating
costs per barrel, Adjusted EBITDA, revenue and arrears receipts,
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.
(2) Weighted average GKP sales volume price.
(3) 2021 restated as the definition of net capital expenditure
was amended to no longer exclude the increase/decrease of drilling
and other equipment.
Record profitability and cash flow generation in 2022 were
driven by an increase in the oil price, higher production and a
continued focus on cost control. The Company increased net capital
expenditure while maintaining capital discipline to drive future
production growth and paid oil and gas sector leading dividends,
while maintaining a robust balance sheet and prudent liquidity
levels to manage potential risks, including KRG payment delays.
Adjusted EBITDA
Adjusted EBITDA increased by 61% in 2022 to $358.5 million
(2021: $222.7 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 44,202 bopd in 2022, up 2% from
43,440 bopd in 2021 and within the Company's 2022 guidance range.
Revenue increased by 53% to $460.1 million (2021: $301.4 million),
driven by our leverage to the 43% increase in Dated Brent price
from an average of $70.8/bbl in 2021 to $101.4/bbl in 2022. The
increase was partially offset by a corresponding $11.4 million
increase in capacity building payments to $34.9 million (2021:
$23.5 million), which is a component of the KRG's entitlement from
the Shaikan Field.
The average realised price per barrel increased by 49% in the
year to $74.1/bbl (2021: $49.7/bbl), including the impact of an
increase in the discount to Dated Brent to $27.2/bbl (2021:
$21.1/bbl). The increase in the discount reflected a new pricing
mechanism proposed by the KRG for Shaikan oil sales changing the
reference price from Dated Brent to KBT, effective 1 September
2022, and increased pipeline tariffs.
While the Company has not accepted the proposed pricing
mechanism, revenue from September 2022 to December 2022 has been
recognised on this basis, resulting in an average reduction in the
realised sales price versus the previous pricing mechanism over the
four-month period of approximately $12/bbl or $23.4 million.
If the new pricing mechanism had been in place throughout 2022,
the reduction in monthly Shaikan realised prices would have ranged
from $4/bbl to $13/bbl versus the previous pricing mechanism,
assuming KBT crude specs during Q3 2022 were representative of
those during H1 2022. While it is difficult to predict how pricing
will evolve going forward given the historic fluctuation of KBT
prices, the KBT discount to Dated Brent has tightened since
November 2022, with the impact on Shaikan realised prices versus
the previous pricing mechanism decreasing to $6/bbl in February
2023.
Gulf Keystone continues to maintain a rigorous focus on cost
control. Gross operating costs per barrel increased to $3.2/bbl in
2022 (2021: $2.7/bbl), in line with the Company's 2022 guidance
range of $2.9-$3.3/bbl. The increase in operating costs in 2022 to
$41.9 million (2021: $34.4 million) was primarily driven by an
increase in staff costs reflecting increased activity, as well as
incremental maintenance activity.
Other general and administrative expenses ("G&A"),
comprising Shaikan Field and corporate G&A, were 10% lower in
2022 at $12.2 million (2021: $13.6 million), reflecting increased
capitalisation due to accelerating capital activity resulting in a
more than doubling of net capital expenditure. Share option expense
in the period increased by $5.3 million to $13.8 million (2021:
$8.5 million), principally due to the final contractual exercise of
share option entitlements by former Directors under the 2016 Value
Creation Plan ("VCP").
Profit after tax
Profit after tax increased to $266.1 million (2021: $164.6
million) driven by the increase in Adjusted EBITDA, partly offset
by higher depreciation, depletion and amortisation ("DD&A")
expense of $80.2 million (2021: $54.1 million) due to increased
production, accelerated cost recovery as result of recent high oil
prices, and updated future capital cost estimates.
Cash flows
The Company more than doubled cash from operating activities to
$374.3 million (2021: $178.5 million) primarily due to the increase
in Adjusted EBITDA.
In 2022, Gulf Keystone received revenue receipts from the KRG of
$450.4 million net to GKP for crude oil sales related to the
September 2021 to July 2022 invoices and repayment of arrears
outstanding from November 2019 to February 2020 invoices, which
were fully recovered with payment of the March 2022 invoice.
Since the beginning of 2023, the Company has received a further
$65.7 million net to GKP for crude oil sales related to the August
and September 2022 invoices. Discussions are ongoing with the KRG
regarding payments for October to December 2022 crude oil sales,
which are overdue and amount to $76.0 million net on the basis of
the KBT pricing mechanism.
During the year, the Company invested net capital expenditure of
$114.9 million (2021 restated: $46.2 million), in line with final
2022 guidance of $110-$120 million, to drive future profitable
production growth. $63.4 million was spent on the drilling of
SH-15, SH-16 and SH-17 that was completed in early 2023. $35.8
million was invested in early work for the expansion of the
production facilities with water handling capacity, as well as
future well pad preparation costs. $15.7 million was invested in
well workover and interventions to optimise production.
Free cash flow generation was $266.5 million in 2022, more than
double the prior year (2021: $122.2 million), enabling the Company
to continue to deliver against its strategic commitment of
balancing investment in growth with returns to shareholders, while
maintaining a robust balance sheet.
In 2022, GKP paid record dividends of $215 million, representing
a sector-leading dividend yield of 41% based on the closing share
price on 31 December 2022.
In early August 2022, the Company redeemed the $100 million of
notes outstanding leaving the Company debt free with significant
financial capacity. Net cash increased from $69.9 million at 31
December 2021 to $119.5 million at 31 December 2022. The Company
continues to maintain a robust balance sheet with cash and cash
equivalents of $118.8 million at 22 March 2023.
As at 31 December 2022, there were $213 million gross of
unrecovered costs, subject to potential cost audit by the KRG. The
R-factor, calculated as cumulative gross revenue receipts of $2,078
million divided by cumulative gross costs of $1,760 million, was
1.18. 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.
The Group performed a cash flow and liquidity analysis,
including the impact on the Group's working capital position due to
delays in revenue receipts from the KRG and the proposed revision
to the lifting agreement, 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
Given continued delays to KRG payments, we are currently
reviewing our forward capital programme and 2023 net capital
expenditure guidance of $160-$175 million. Our guidance includes
$30-$35 million related to drilling costs and well workovers,
$45-$50 million related to long lead items and well pad preparation
and $85-$90 million related to the expansion of the production
facilities and installation of water handling. With further clarity
around KRG payments, we would consider continued drilling following
SH-18. However, with continued payment delays we would review
reductions to our capital programme.
We remain focused on delivering 2023 gross average production of
46,000-52,000 bopd, representing an 11% increase from 2022 at the
mid-point. We also continue to target gross Opex of $3.0-$3.4/bbl
in 2023, implying no change from 2022 gross Opex per barrel at the
mid-point of guidance.
Financial framework & shareholder distributions
As we continue to transition towards increased investment in
profitable production growth from the Jurassic reservoir through a
flexible capital programme, we remain focused on balancing
investment in growth with sustainable shareholder returns, while
looking to maintain a robust balance sheet and prudent liquidity
levels.
Given our oil price outlook and flexible capital 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 the Company's dividend policy and financial
framework, we paid an interim dividend of $25 million to
shareholders on 3 March 2023 and we are pleased to declare a $25
million final 2022 ordinary dividend for shareholder approval at
the Company's AGM on 16 June 2023. Total dividends declared in 2023
of $50 million equate to an 11% yield based on the closing share
price on 22 March 2023.
The Board remains committed to distributing excess cash to
shareholders by way of dividends and/or share buybacks and will
continue to review further distributions based on a rigorous
framework that includes an assessment of the outlook for oil
prices, timeliness of payments from the KRG, expected liquidity,
cash flow generation and future PSC and capital commitments.
Ian Weatherdon
Chief Financial Officer
22 March 2023
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
Gross operating costs are divided by gross production to arrive
at operating costs per barrel.
2022 2021
--------------------------------------------- ---- ----
Gross production (MMstb) 16.1 15.9
Gross operating costs ($ million)(1) 52.3 43.0
--------------------------------------------- ---- ----
Gross operating costs per barrel ($ per bbl) 3.2 2.7
--------------------------------------------- ---- ----
(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.
2022 2021
$ million $ million
-------------------------------------------------- ----------- ----------
Profit after tax 266.1 164.6
Finance costs 9.7 11.4
Finance revenue (0.6) (0.4)
Tax credit (0.3) (0.9)
Depreciation of oil and gas assets 80.2 54.1
Depreciation of other PPE assets and amortisation
of intangibles 1.4 1.0
Impairment of receivables 2.0 (7.1)
-------------------------------------------------- ----------- ----------
Adjusted EBITDA 358.5 222.7
-------------------------------------------------- ----------- ----------
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 or any asset impairment.
2021
2022 Restated(1)
$ million $ million
---------------------------------- ----------- ------------
Net capital expenditure (note 11) 114.9 46.2
---------------------------------- ----------- ------------
(1) The definition of net capital expenditure has been amended
to no longer exclude the increase/decrease of drilling and other
equipment.
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.
2022 2021
$ million $ million
---------------------------------- ----------- ----------
Outstanding Notes - (99.1)
Unamortised issue costs (note 16) - (0.9)
Cash and cash equivalents 119.5 169.9
---------------------------------- ----------- ----------
Net cash 119.5 69.9
---------------------------------- ----------- ----------
Free cash flow
Free cash flow represents the Group's cash flows, before any
dividends, share buybacks and notes redemption, including related
fees.
2022 2021
$ million $ million
--------------------------------------------- ----------- ----------
Net cash generated from operating activities 374.3 178.6
Net cash used in investing activities (107.4) (55.7)
Payment of leases (0.4) (0.7)
--------------------------------------------- ----------- ----------
Free cash flow 266.5 122.2
--------------------------------------------- ----------- ----------
Consolidated income statement
For the year ended 31 December 2022
Notes 2022 2021
$'000 $'000
----- --------- ---------
Revenue 2 460,113 301,389
Cost of sales 3 (158,651) (111,721)
(Increase)/decrease of impairment
provision on trade receivables 14 (1,960) 7,065
--------- ---------
Gross profit 299,502 196,733
Other general and administrative
expenses 4 (12,202) (13,643)
Share option related expenses 5 (13,756) (8,490)
Profit from operations 273,544 174,600
Finance revenue 7 648 419
Finance costs 7 (9,655) (11,353)
Foreign exchange gains 1,232 57
--------- ---------
Profit before tax 265,769 163,723
Tax credit 8 325 874
--------- ---------
Profit after tax for the year 266,094 164,597
--------- ---------
Profit per share (cents)
Basic 9 123.52 77.14
Diluted 9 118.62 73.04
Consolidated statement of comprehensive income
For the year ended 31 December 2022
2022 2021
$'000 $'000
------- -------
Profit after tax for the year 266,094 164,597
Items that may be reclassified to
the income statement in subsequent
periods:
Fair value losses arising in the
period - (2,021)
Cumulative losses arising on hedging
instruments reclassified to revenue - 3,753
Exchange differences on translation
of foreign operations (1,950) (254)
------- -------
Total comprehensive income for the
year 264,144 166,075
======= =======
Consolidated balance sheet
Notes 31 December 31 December
2022 2021
$'000 $'000
----- ----------- -----------
Non-current assets
Intangible assets 10 4,307 3,583
Property, plant and equipment 11 436,443 404,205
Deferred tax asset 18 1,576 1,385
442,326 409,173
----------- -----------
Current assets
Inventories 13 6,372 6,018
Trade and other receivables 14 176,203 179,200
Cash and cash equivalents 119,456 169,866
----------- -----------
302,031 355,084
----------- -----------
Total assets 744,357 764,257
=========== ===========
Current liabilities
Trade and other payables 15 (128,561) (98,800)
Non-current liabilities
Trade and other payables 15 (325) (789)
Borrowings 16 - (99,123)
Provisions 17 (42,546) (43,841)
----------- -----------
(42,871) (143,753)
----------- -----------
Total liabilities (171,432) (242,553)
----------- -----------
Net assets 572,925 521,704
=========== ===========
Equity
Share capital 20 216,247 213,731
Share premium 20 528,125 742,914
Exchange translation reserve (4,718) (2,768)
Accumulated losses (166,729) (432,173)
Total equity 572,925 521,704
=========== ===========
The financial statements were approved by the Board of Directors
and authorised for issue on 22 March 2023 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 2022
Attributable to equity holders of the Company
Cost Exchange
Share Share Treasury of hedging translation Accumulated Total
capital premium shares reserve reserve losses equity
Notes $'000 $'000 $'000 $'000 $'000 $'000 $'000
Balance at 1 January
2021 211,371 842,914 (2,592) (1,732) (2,514) (593,422) 454,025
--------- --------- ---------- ----------- ------------ ----------- ---------
Profit after tax 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)
2
Employee share schemes 4 - - - - - 1,604 1,604
Share options exercised - - 2,592 - - (2,592) -
Share issues 20 2,360 - - - - (2,360) -
Balance at 31 December
2021 213,731 742,914 - - (2,768) (432,173) 521,704
--------- --------- ---------- ----------- ------------ ----------- ---------
Profit after tax for
the year - - - - - 266,094 266,094
Exchange difference
on translation of foreign
operations - - - - (1,950) - (1,950)
--------- --------- ---------- ----------- ------------ ----------- ---------
Total comprehensive
income for the year - - - - (1,950) 266,094 264,144
--------- --------- ---------- ----------- ------------ ----------- ---------
Dividends paid 25 - (214,789) - - - - (214,789)
2
Employee share schemes 4 - - - - - 1,866 1,866
Share issues 20 2,516 - - - - (2,516) -
Balance at 31 December
2022 216,247 528,125 - - (4,718) (166,729) 572,925
========= ========= ========== =========== ============ =========== =========
Consolidated cash flow statement
For the year ended 31 December 2022
Notes 2022 2021
$'000 $'000
--------- ---------
Operating activities
Cash generated from operations 21 383,846 189,155
Interest received 7 648 419
Interest paid 16 (10,194) (10,000)
Payment of put option premium - (1,043)
Net cash generated from operating
activities 374,300 178,531
--------- ---------
Investing activities
Purchase of intangible assets 10 (2,074) (2,725)
Purchase of property, plant and
equipment 21 (105,291) (52,959)
Net cash used in investing activities (107,365) (55,684)
--------- ---------
Financing activities
Payment of dividends 25 (214,789) (100,000)
Payment of leases 22 (458) (688)
Notes redemption 16 (100,000) -
Notes repayment fee 16 (2,000) -
Net cash used in financing activities (317,247) (100,688)
--------- ---------
Net (decrease)/increase in cash
and cash equivalents (50,312) 22,159
Cash and cash equivalents at
beginning of year 169,866 147,826
Effect of foreign exchange rate
changes (98) (119)
Cash and cash equivalents at
end of the year being bank balances
and cash on hand 119,456 169,866
========= =========
Summary of significant accounting policies
General information
Gulf Keystone Petroleum Limited (the "Company") is domiciled and
incorporated in Bermuda (registered address: Cedar House, 3rd
Floor, 41 Cedar Avenue, Hamilton, HM12, Bermuda); together with its
subsidiaries it forms the "Group". 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 2022 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 2022.
The following new accounting standards, amendments to existing
standards and interpretations are effective on 1 January 2022:
Reference to the Conceptual Framework (Amendments to IFRS 3),
Property, Plant and Equipment - Proceeds before Intended Use
(Amendments to IAS 16), Onerous Contracts - Cost of Fulfilling a
Contract (Amendments to IAS 37), and Annual Improvements to IFRS
Standards 2018-2020. 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
Amendments to IFRS Applying IFRS 9 'Financial Instruments' with
4 IFRS 4 'Insurance Contracts'; Extension of the
Temporary Exemption from Applying IFRS 9
Amendments to IAS Classification of Liabilities as Current or
1 Non-current; Classification of Liabilities as
Current or Non-current - Deferral of Effective
Date; Non-current Liabilities with Covenants
Amendments to IFRS Lease Liability in a Sale and Leaseback
16
Amendments to IFRS Initial Application of IFRS 17 and IFRS 9 -
17 Comparative Information; Amends IFRS 17 to address
concerns and implementation challenges that were
identified after IFRS 17 Insurance Contracts
was published in 2017
Amendments to IAS Disclosure of Accounting Policies
1 and IFRS Practice
Statement 2
Amendments to IAS Definition of Accounting Estimates
8
Amendments to IAS Deferred Tax related to Assets and Liabilities
12 arising from a Single Transaction
The directors do not expect that the adoption of the Standards
listed above will have a material impact on the financial
statements of the Group in future periods .
Statement of compliance
The financial statements have been prepared in accordance with
United Kingdom adopted International Accounting Standards .
Basis of accounting
The financial statements have been prepared under the historical
cost basis, except for the valuation of hydrocarbon inventory and
the valuation of certain financial instruments, which have been
measured at fair value, and on the going concern basis.
Equity-settled share-based payments are recognised at fair value at
the date of grant, and 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 22 March 2023, the Group had $118.8 million of cash and no
debt. 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 and delays to revenue
receipts, impact of climate change and geopolitical risks on the
Group's operations, including the Iraqi Supreme Court ruling on 15
February 2022, as further described in key sources of uncertainty
below.
In the current year, further consideration has been given to the
impact on the Group's working capital position due to delays in
revenue receipts from the KRG and the proposed revision to the
lifting agreement:
-- Revenue receipts - The timing of revenue receipts over the
last 12 months has increased from an average of 20-30 days past due
to 100 days for the most recent September production month payment.
At the date of this report, $76.0 million is overdue for October to
December 2022 oil sales; and
-- Lifting agreement: There has been no lifting agreement in
place since 1 September 2022 and negotiations are ongoing around
the pricing mechanism of oil sales. Instead of a Dated Brent based
pricing mechanism, the KRG has proposed a Kurdistan Blend (KBT)
based pricing mechanism to recognise the value they receive for oil
sales, as further described in note 2.
The Directors believe an agreement will ultimately be reached on
the terms of a revised lifting agreement, and we reasonably expect
that overdue balances will be paid and payments will return to a
more regular basis. However, a deferral of revenue receipts from
the KRG for an extended period of time could result in liquidity
pressures within the twelve month going concern period.
The Directors have considered sensitivities to assess the impact
on the Group's liquidity position if revenue receipts from the KRG
are deferred for an extended period of time. While the payment of
such amounts are outside of management's control, the Directors
believe sufficient mitigating actions are available to withstand
potential further delays in revenue receipts until such receipts
return to more routine payment terms. Mitigating actions include
deferring planned capital expenditures, reducing operating and
general and administrative expenses and managing supplier payment
timing.
Overall, 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
twelve months from the date of approval of the 2022 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 is considered to be a key accounting
judgement.
Revenue is earned based on the entitlement mechanism under the
terms of the Shaikan Production Sharing Contract ("PSC").
Entitlement has two components: cost oil, which is the mechanism by
which the Company recovers its costs incurred, and profit oil,
which is the mechanism through which profits are shared between the
Company, its partner and the Kurdistan Regional Government ("KRG").
The Company is liable for capacity building payments calculated as
a proportion of profit oil entitlement. Entitlement from cost oil
and profit oil are reported as revenue, and capacity building
payments are included in cost of sales.
All oil is sold by the Shaikan Contractor (the Company and
Kalegran BV, a subsidiary of MOL Hungarian Oil & Gas Plc,
("MOL")) to the KRG, who in turn resell the oil. The selling price
is determined in accordance with the principles of the crude oil
lifting agreement.
Under IFRS 15: Revenue from contracts with customers, GKP
considers that control of crude oil is transferred from the Shaikan
Contractor to the KRG at the delivery point as defined in the
lifting agreement, this being the export pipeline; at this point
the Shaikan Contractor is due economic benefits which can be
reliably measured and are probable to be received. The
consideration is variable and is dependent upon the monthly average
oil market price with deductions for quality and transportation
fees, with other fees and royalties due as determined by commercial
agreements; revenue is reported net of these deductions.
Effective September 1, 2022, the KRG proposed a new pricing
mechanism for crude oil sales. Under the new pricing mechanism, the
realised sales price for a month is based on the average market
price realised by the KRG for the Kurdistan blend (KBT) sold at
Ceyhan, Turkey, as advised by the KRG. The change in the benchmark
market price from Brent to KBT has not yet been agreed and no
lifting agreement has been in place since 1 September 2022.
Nonetheless, the Shaikan Contractor continued to produce and the
KRG continued to accept delivery of oil at the delivery points. GKP
continues to consider that control of crude oil was transferred at
the delivery points despite no commercial agreement being in place
and as such has recognised revenue based on the proposed new
pricing terms. A summary of the currently estimated financial
impact of the proposed change in pricing mechanism is detailed in
note 2.
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 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. 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 dialogue with the MNR to confirm whether to
proceed with a formal amendment to the PSC to reflect current
invoice terms.
Income tax arising from the Company's activities under its PSC
is settled by the KRG on behalf of the Company. Since the Company
is not able to measure the amount of income tax that has been paid
on its behalf the notional income tax amounts have not been
included in revenue or in the tax charge.
Finance revenue
Interest revenue is accrued on a time basis, by reference to the
principal outstanding and at the effective rate of interest
applicable, which is the rate that exactly discounts estimated
future cash receipts through the expected life of the nancial asset
to that asset's net carrying amount on initial recognition.
Intangible assets
Intangible assets include computer software and are measured at
cost and amortised over their expected useful economic lives of
three years.
Property, plant and equipment ("PPE")
Oil and gas assets
Development and production assets
Development and production assets are accumulated on a
field-by-field basis and represent the costs of acquisition and
developing the commercial reserves discovered and bringing them
into production, together with the exploration and evaluation
expenditure incurred in finding commercial reserves, directly
attributable overheads and costs for future restoration and
decommissioning. These costs are capitalised as part of PPE and
depreciated based on the Group's depreciation of oil and gas assets
policy.
The net book values of producing assets are depreciated
generally on a field-by-field basis using the unit of production
("UOP") basis which uses the ratio of oil and gas production in the
period to the remaining commercial reserves plus the production in
the period. Costs used in the calculation comprise the net book
value of the field, and estimated future development expenditures
required to produce those reserves.
Commercial reserves are proven and probable ("2P") reserves
which are estimated using standard recognised evaluation
techniques. The reserves estimate used in 2022 are based on the
June 2022 draft FDP submitted to the MNR. The previous independent
reserves report at 31 December 2020 did not reflect various known
updates since completion of the report. A new Competent Person's
Report reserves report has been completed by ERC Equipoise at 31
December 2022 and will be applied prospectively in the
depreciation, depletion and amortisation ("DD&A") calculation
from 1 January 2023.
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 ("FVLCTS") and value in use. In assessing FVLCTS and value in
use, the estimated future cash flows are discounted to their
present value using a pre-tax discount rate that reflects current
market assessments of the time value of money and the risks
specific to the asset for which the estimates of future cash flows
have not been adjusted.
Any i mpairment identified is immediately recognised as an
expense. Conversely, any reversal of an impairment is immediately
recognised as income.
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 future 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 future 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, foreign exchange or interest rate
risk.
Derivatives are initially recognised at fair value at the date a
derivative contract is entered into and are subsequently
re-measured to their fair value at each balance sheet date. The
resulting gain or loss is recognised in the profit or loss
immediately unless the derivative is designated and effective as a
hedging instrument, in which event the timing of the recognition in
profit or loss depends on the nature of the hedge relationship.
A derivative with a positive fair value is recognised as a
financial asset whereas a derivative with a negative fair value is
recognised as a liability. A derivative is presented as a
non-current asset or a non-current liability if the remaining
maturity of the instrument is more than twelve months and it is not
expected to be realised or settled within twelve months. Other
derivatives are presented as current assets or current
liabilities.
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 accounting policies described above,
the Group is required to make judgements, estimates and assumptions
about the carrying amounts of assets and liabilities that are not
readily apparent from other sources. The estimates and associated
assumptions are based on historical experience and other factors
that are considered to be relevant. Actual results may differ from
these estimates.
The estimates and underlying assumptions are reviewed on an
ongoing basis. Revisions to accounting estimates are recognised in
the period in which the estimate is revised if the revision affects
only that period or in the period of revision and future periods if
the revision affects both current and future periods.
Critical judgements in applying the Group's accounting
policies
The following are the critical judgements, apart from those
involving estimations (which are presented separately below), that
the directors have made in the process of applying the Group's
accounting policies and that have the most significant effect on
the amounts recognised in financial statements.
Revenue
The recognition of revenue, particularly the recognition of
revenue from exports, is considered to be a key accounting
judgement. The Group be gan commercial production from the Shaikan
Field in July 2013 and historically made sales to both the domestic
and export markets. The Group considers that revenue can be
reliably measured as it passes the delivery point into the export
pipeline. The critical accounting judgement applied in preparing
the 2022 financial statements is that it is appropriate to
recognise revenue for deliveries from 1 September 2022 based on the
proposed new pricing mechanism, notwithstanding that there is no
signed lifting agreement for that period and the pricing mechanism
has not yet been agreed. Further details of this judgement are
provided in the sales revenue accounting policy above. In making
this judgement, consideration was given to the fact that,
subsequent to the year end, the Group received payment for
September 2022 deliveries at an amount that was consistent with the
proposed new pricing terms.
A summary of the currently estimated financial impact of the
proposed change in pricing mechanism is detailed in Note 2.
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, potential climate change transition
risk impacts, 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 2022 was the Shaikan Field
with a carrying value of $391.0 million (2021: $358.3 million). The
Group performed an impairment trigger assessment and concluded that
the Iraqi Supreme Court ruling in February 2022 and the change in
the proposed basis of calculating the realised oil price from
September 2022 were potential impairment triggers. Accordingly a
full impairment evaluation was completed and it was concluded that
no impairment write-down was required.
The key areas of estimation in the impairment assessment are as
follows:
- Commodity prices for the current year were based on the
forward curve as at December 2022 for the period 2023 to 2028 with
inflation of 2% per annum thereafter. Prices at 31 December 2021
were determined based on the latest internal estimates, benchmarked
with external sources of information;
- All prices below are nominal and no impairment arose under either the base or stress case.
Scenario ($/bbl - nominal) 2022 2023 2024 2025 2026 2027 2028
31 December 2022 - base
case n/a 83.4 78.2 74.5 71.7 69.6 68.1
----- ----- ----- ----- ----- ----- -----
31 December 2022 - stress
case n/a 75.1 70.4 67.1 64.5 62.6 61.3
----- ----- ----- ----- ----- ----- -----
31 December 2021 - base
case 81 56.1 57.2 58.4 59.5 60.7 61.9
----- ----- ----- ----- ----- ----- -----
31 December 2021 - stress
case 80 51.0 52.0 53.1 54.1 55.2 56.3
----- ----- ----- ----- ----- ----- -----
- 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 per
barrel CO(2) emissions by at least 50% by 2025 versus the original
2020 baseline of 38 kgCO2e per barrel dependent on the timely
sanction and implementation of the Gas Management Plan. The
International Energy Agency's ("IEA") Announced Pledges Scenario
("APS") and Net Zero Emissions ("NZE") climate scenario oil prices
and carbon taxes were used to evaluate the potential impact of the
principal climate change transition risks. The APS being that
governments will meet, in full and on time, all of the climate --
related commitments that they have announced, including longer term
net zero emissions targets and pledges in Nationally Determined
Contributions ("NDCs") to reduce national emissions and adapt to
the impacts of climate change leading to a global temperature rise
of 1.7 C in 2100.The NZE being the normative scenario pathway to
the stabilisation of global average temperatures at 1.5 degC above
pre -- industrial levels. Neither adoption of the APS price
scenario nor NZE price scenario, both with and without the addition
of an incremental carbon tax, resulted in an impairment
arising.
- Discount rates that are adjusted to reflect risks specific to
the Shaikan Field and the Kurdistan Region of Iraq ("KRI"). The
impairment analysis was based on a pre-tax nominal 15% discount
rate (2021: 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,
including the impact of forecast short term inflationary pressures,
as well as the nature and location of the operation and the risks
associated therewith. Base case costs assumptions used in the
assessment reflect the latest cost estimates for the FDP, which
includes the estimated cost of implementing a Gas Management Plan,
as part of our ambition to reduce scope one emissions as outlined
above;
- Commercial reserves and production profiles used in the
assessment are consistent with the latest draft FDP and materially
consistent with the figures shown in the new independent reserves
report recently completed by ERC Equipoise at 31 December 2022 ;
and
- Timing of revenue receipts.
In February 2022, the Iraqi Federal Supreme Court ("FSC") had
ruled that the Kurdistan Oil and Gas Law ("KROGL") was
unconstitutional and subsequently the Iraqi Ministry of Oil
commenced proceedings in the Baghdad Commercial Court against
International Oil Companies ("IOCs"), including Gulf Keystone,
operating in the KRI seeking to nullify the PSCs issued under the
KROGL. The Company understands that the Baghdad Commercial Court
has issued adverse judgements against many of the IOCs, including
Gulf Keystone, in absentia. The KRG continues to affirm that KROGL
is validly constituted and the PSCs issued are valid and in full
force and effect. The Company's operations in the Shaikan Field are
currently unaffected. However, the matter continues to be closely
monitored, including any potential impact on the restrictions
placed on the export of crude oil, service contractors or any other
parties by the Iraqi Ministry of Oil.
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:
2022 2021
$'000 $'000
--------------- ------- -------
Kurdistan 436,213 402,787
United Kingdom 4,537 5,001
------- -------
440,750 407,788
======= =======
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.
2 Revenue
2022 2021
$'000 $'000
--------------------------------------- ------- -------
Oil sales 460,113 305,142
Hedging losses reclassified to revenue - (3,753)
------- -------
460,113 301,389
======= =======
The Group accounting policy for revenue recognition is set out
in the 'Summary of significant accounting policies', with revenue
recognised upon crude oil passing the delivery points into the
export pipeline.
From 1 January 2022 to 31 August 2022 the realised sales price
was based on the weighted monthly average Dated Brent price, which
was $107.3/bbl during the period (2021: $70.8/bbl) less a weighted
monthly average discount of $23.3 (2021: $21.2) per barrel for
quality and pipeline tariff costs. Since 1 September 2022 there has
been no lifting agreement in place between the Shaikan Contractor
and the KRG; production and export has continued whilst
negotiations are ongoing. The KRG proposal is for a new pricing
mechanism based upon the average monthly Kurdistan blend ("KBT")
sales price realised by the KRG at Ceyhan, as advised by the KRG.
The Company has not accepted the proposal and continues to invoice
the KRG for oil sales based on the pre-1 September 2022 pricing
formula.
Oil sales during 2022 were impacted by $2.4 million of backdated
pipeline tariff increases related to 2021 (2021: nil).
Considering the uncertainty in respect of the pricing mechanism,
the Company has concluded that it is appropriate to recognise
revenue based on the proposed mechanism from September to December
2022. The revenue impact of the proposed pricing mechanism for the
period is estimated to be a reduction of $23.4m. Taking into
account the associated reduction in capacity building payments
results in a total reduction of profit after tax for the year of
$21.7 million. Any difference between the proposed and final
pricing mechanism will be reflected in future periods.
Information about major customers
All oil sales revenue relates to sales to the KRG.
3 Cost of sales
2022 2021
$'000 $'000
--------------------------------------- ------- -------
Operating costs 41,835 34,372
Capacity building payments 34,927 23,529
Change in oil inventory value 555 (348)
Depreciation of oil and gas assets and
operational assets 80,225 54,168
Impairment of surplus drilling stock 1,109 -
158,651 111,721
======= =======
Capacity building payments have been recorded in line with the
proposed pricing mechanism (see note 2); any difference between the
proposed and final pricing mechanism will be reflected in future
periods.
Further details on the depreciation of oil and gas assets and
operational assets, as well as the recognition of capacity building
payments, are set out in the Summary of significant accounting
policies section.
The Company updated the depreciation calculation based on the
June 2022 draft FDP submitted to the MNR including an internal
reserves and cost update. This resulted in a higher 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 2022.
The impairment of surplus drilling stocks includes the carrying
value of items not anticipated to be used in future drilling
operations.
4 Other general and administrative expenses
2022 2021
$'000 $'000
--------------------------------------- ------- ------
Depreciation and amortisation 1,563 940
Auditor's remuneration (see below) 703 583
Other general and administrative costs 9,936 12,120
12,202 13,643
======= ======
Of the $12.2 million of general and administrative expenses,
$5.2 million (2021: $4.1 million) were incurred in relation to the
Shaikan Field.
2022 2021
$'000 $'000
-------------------------------------------------------- -------- -------
Fees payable to the Company's auditor
for the audit of the Company's annual
accounts 430 318
Fees payable to the Company's auditor
for other services to the Group
* audit of the Company's subsidiaries pursuant to
legislation 26 28
-------- -------
Total audit fees 456 346
Advisory services 112 107
Other assurance services (including a
half year review) 135 130
Total fees 703 583
======== =======
5 Share option related expense
2022 2021
$'000 $'000
Share-based payment expense 3,266 2,255
Payments related to share options exercised 8,690 4,142
Share-based payment related provision
for taxes 1,800 2,093
13,756 8,490
======= ======
On the final exercise of the legacy Value Creation Plan ("VCP")
share options by former Directors, the Company elected to make
required tax withholding settlements in cash instead of issuing and
selling additional shares. This together with payment of dividends
accumulated during the vesting period are the main components of
the payments related to share options exercised.
The legacy VCP scheme totalled $9.5 million of the $13.8 million
expense (2021: $3.4 million). There are no further VCP share
options outstanding and the plan has been terminated.
6 Staff costs
The average number of employees and contractors (including
Executive directors) employed by the Group was 460 (2021: 349); the
number of full-time equivalents of these workers was 317 (2021:
237).
Average number Average number
of employees of full-time
equivalents
2022 2021 2022 2021
---------------------------- ------ -------- ------- ---------
Kurdistan 421 317 280 205
United Kingdom 39 32 37 32
------ -------- ------- ---------
Total 460 349 317 237
====== ======== ======= =========
Staff costs were as follows:
2022 2021
$'000 $'000
Wages and salaries 46,879 36,835
Social security costs 2,503 1,880
Share-based payment (see note 24 ) 4,260 3,009
------- ------
53,642 41,724
======= ======
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. Staff costs are
shown gross before amounts recharged to joint operations.
7 Finance costs and finance revenue
2022 2021
$'000 $'000
------------------------------------------ ------- --------
Notes interest expense (see note 16 ) (5,833) (10,000)
Unwinding of finance and arrangement fees
(see note 16 ) (879) (489)
Notes repayment fee (see note 16) (2,000) -
Finance lease interest (77) (123)
Unwinding of discount on provisions (see
note 17 ) (866) (741)
------- --------
Total finance costs (9,655) (11,353)
------- --------
Finance revenue 648 419
------- --------
Net finance costs (9,007) (10,934)
======= ========
On 2 August 2022 the Group redeemed the $100m notes and paid an
early repayment fee (see note 16).
8 Income tax
2022 2021
$'000 $'000
------------------------------------------ --------- --------
Current year credit 216 75
Prior year adjustment - 28
Deferred UK corporation tax credit (see
note 18 ) 109 771
--------- --------
Tax credit attributable to the Company
and its subsidiaries 325 874
========= ========
The Group is not required to pay taxes in Bermuda on either
income or capital gains. The Group has received an undertaking from
the Minister of Finance in Bermuda exempting it from any such taxes
at least until the year 2035.
In the Kurdistan Region of Iraq, the Group is subject to
corporate income tax on its income from petroleum operations under
the Kurdistan PSC. Under the Shaikan PSC, any corporate income tax
arising from petroleum operations will be paid from the KRG's share
of petroleum profits. Due to the uncertainty over the payment
mechanism for oil sales in Kurdistan, it has not been possible to
measure reliably the taxation due that has been paid on behalf of
the Group by the KRG and therefore the notional tax amounts have
not been included in revenue or in the tax charge. This is an
accounting presentational issue and there is no taxation to be
paid.
The annual UK corporation tax rate for the year ended 31
December 2022 was 19.0% (2021: 19.0%).
On 3 March 2021, the UK Government announced that the
corporation tax rate in the UK will increase to 25% for companies
with taxable profits above GBP250,000 with effect from 1 April
2023, as well as announcing a number of other changes to allowances
and treatment of losses. These changes were substantively enacted
as at 31 December 2021.
Deferred tax is provided for due to the temporary differences,
which give rise to such a balance in jurisdictions subject to
income tax. All deferred tax arises in the UK.
9 Profit per share
The calculation of the basic and diluted profit per share is
based on the following data:
2022 2021
------- -------
Profit after tax for basic and diluted
per share calculations ($'000) 266,094 164,597
------- -------
Number of shares ('000s):
------- -------
Basic weighted average number of ordinary
shares 215,420 213,384
Basic EPS (cents) 123.52 77.14
------- -------
The Group followed the steps specified by IAS 33 in determining
whether potential common shares are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
Number of shares ('000s) 2022 2021
------- -------
Basic weighted average number of ordinary
shares outstanding 215,420 213,384
Effect of potential dilutive share options 8,909 11,962
------- -------
Diluted number of ordinary shares outstanding 224,329 225,346
Diluted EPS (cents) 118.62 73.04
------- -------
The weighted average number of ordinary shares in issue excludes
shares held by Employee Benefit Trustee ("EBT").
The diluted number of ordinary shares outstanding is calculated
on the assumption of the exercise of all potentially dilutive share
options.
10 Intangible assets
Computer
software
$'000
----------------------------------------- ---------
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
---------
Year ended 31 December 2022
Opening net book value 3,583
Additions 2,074
Amortisation charge (859)
Foreign currency translation differences (491)
Closing net book value 4,307
=======
At 31 December 2022
Cost 6,305
Accumulated amortisation (1,998)
-------
Net book value 4,307
=======
The amortisation charge of $859,000 (2021: $25,000) for computer
software has been included in other general and administrative
expenses (see note 4 ).
11 Property, plant and equipment
Oil and Fixtures Right Total
gas and of use
assets equipment assets
$'000 $'000 $'000 $'000
------------------------------------ --------- ---------- ------- ---------
Year ended 31 December 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
========= ========== ======= =========
Year ended 31 December 2022
Opening net book value 402,094 1,033 1,078 404,205
Additions 114,909 1,595 - 116,504
Impairment of surplus drilling
stocks (1,109) - - (1,109)
Revision to decommissioning
asset (2,161) - - (2,161)
Depreciation charge (80,177) (359) (347) (80,883)
Foreign currency translation
differences - (12) (101) (113)
Closing net book value 433,556 2,257 630 436,443
========= ========== ======= =========
At 31 December 2022
Cost 943,563 8,946 2,145 954,654
Accumulated depreciation (510,007) (6,689) (1,515) (518,211)
--------- ---------- ------- ---------
Net book value 433,556 2,257 630 436,443
========= ========== ======= =========
The net book value of oil and gas assets at 31 December 2022 is
comprised of property, plant and equipment relating to the Shaikan
block with a carrying value of $433.6 million (2021: $402.1
million).
The additions to the Shaikan asset during the year include costs
relating to the drilling and completion of SH-15 and SH-16, and
SH-17 that was completed early 2023, well pad preparation, PF-1 and
PF-2 expansion and water handling activities, and subsurface
studies.
The decrease in the decommissioning asset represents the change
in accounting estimates as detailed in note 17 partially offset by
additional decommissioning activities arising from capital projects
completed during the year and revisions to decommissioning cost
estimates.
The DD&A charge of $80.2 million (2021: $54.1 million) on
oil and gas assets has been included within cost of sales (note 3
). The depreciation charge of $0.4 million (2021: $0.4 million) on
fixtures and equipment and $0.3 million (2021: $0.6 million) on
right of use assets has been included in general and administrative
expenses (note 4 ).
Right of use assets at 31 December 2022 of $0.6 million (2021:
$1.1 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.
12 Group companies
Details of the Company's subsidiaries and joint operations at 31
December 2022 is as follows:
Name of subsidiary Place of Proportion Principal activity
incorporation of ownership
interest
------------------------ --------------- -------------- -------------------------
Gulf Keystone Petroleum United Kingdom 100% Management, support,
(UK) Limited geological, geophysical
6th floor and engineering
New Fetter Place services
8-10 New Fetter Lane
London EC4A 1AZ
------------------------ --------------- -------------- -------------------------
Gulf Keystone Petroleum Bermuda 100% Exploration, evaluation,
International Limited development and
Cedar House, 3rd Floor production activities
41 Cedar Avenue in Kurdistan
Hamilton HM12
Bermuda
------------------------ --------------- -------------- -------------------------
Name of joint operation Location Proportion Principal
of ownership activity
interest
------------------------ ---------- -------------- ------------------------
Shaikan Kurdistan 80% Production and
development activities
------------------------ ---------- -------------- ------------------------
13 Inventories
2022 2021
$'000 $'000
------------------------------- ------- ------
Warehouse stocks and materials 6,074 5,318
Crude oil 298 700
------- ------
6,372 6,018
======= ======
14 Trade and other receivables
Current receivables
2022 2021
$'000 $'000
-------------------------------- -------- --------
Trade receivables 158,032 174,634
Other receivables 16,828 3,622
Prepayments and accrued income 1,343 944
-------- --------
176,203 179,200
======== ========
Reconciliation of Trade Receivables
2022 2021
$'000 $'000
-------------------------------------------- -------- ---------
Gross carrying amount 161,112 175,754
Less: Impairment allowance (3,080) (1,120)
Carrying value at 31 December 158,032 174,634
============== ========
Gross trade receivables of $161.1 million (2021: $175.8 million)
are comprised of invoiced amounts due from the KRG for crude oil
sales totalling $148.9 million (2021: $163.6 million) related to
August - December 2022 and a share of Shaikan amounts due from the
KRG that the Group purchased from MOL amounting to $12.2 million
(2021: $12.2 million).
As detailed in the Summary of significant accounting policies,
sales revenue for September - December 2022 production and Note 2,
the revenue and corresponding receivable have been recognised based
on a proposed pricing mechanism. On 8 March 2023 GKP received
payment for crude oil sales relating to September 2022 in line with
the proposed pricing mechanism; this does not indicate that GKP has
accepted the terms of this proposed pricing mechanism.
At 31 December 2022, overdue trade receivables relating to oil
sales for August to October 2022 aggregated $99.1 million (2021:
$60.4 million). Since year end, $69.0 million has been received;
$40.8 million relating to August oil sales and $28.2 million
relating to September oil sales, which reflects the proposed
pricing mechanism based upon discounted KBT. 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 $3.1 million (2021: $1.1 million) was provided against
the receivables balance in line with the requirements of IFRS 9.
During the year, a $2.0 million charge was recognised due to the
increase in the ECL provision (2021: credit of $7.1 million);
driven by an estimated increase in the probability of counterparty
default as well as an extension to the expected date of receipt of
outstanding receivables.
The Group received the final payments in relation to the arrears
outstanding at 31 December 2021 in relation to November 2019 to
February 2020 invoices totaling $41.0 million during 2022. This was
settled in line with the KRG's proposal to pay 50% 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.
ECL sensitivities
The Group's profit before tax was not materially sensitive to
movements of +/-10% in production level, Brent price, loss given
default or probability of default.
Other receivables
Other receivables includes an amount relating to advances to
suppliers of $11.5 million (2021: $0.4 million) related to
property, plant and equipment that are included within investing
activities in the consolidated cash flow statement.
Included within Other receivables is an amount of $0.4 million
(2021: $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 2022 (2021: nil). No impairments
of other receivables have been recognised during the year (2021:
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.
Current liabilities
2022 2021
$'000 $'000
--------------------------------------- ------- ------------
Trade payables 3,499 6,494
Accrued expenditures 40,642 25,961
Other payables 84,035 65,927
Current lease liabilities (see note 22
) 385 419
128,561 98,800
======= ============
Other payables include $70.7 million (2021: $56.4 million) of
amounts payable to the KRG that are not expected to be paid in
cash, but rather offset against historic revenue due from the KRG,
which have not yet been recognised in the financial statements.
Within this amount, $34.2 million (2021: $22.6 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
2022 2021
$'000 $'000
-------------------------------------- ------- ------
Non-current lease liability (see note
22 ) 325 789
16 Long term borrowings
2022 2021
$'000 $'000
------------------------------------------ --------- --------
Liability component at 1 January 103,482 102,993
Interest expense, including unwinding
of finance & arrangement fees, and notes
early repayment fee 8,712 10,489
Interest paid during the year (10,194) (10,000)
Principal repaid in year (100,000) -
Settlement of notes early repayment fee (2,000) -
Liability component at 31 December - 103,482
========= ========
Liability component reported in:
2022 2021
$'000 $'000
------------------------------------ --------- --------
Current liabilities (see note 15 ) - 4,359
Non-current liabilities - 99,123
- 103,482
============================================== ========
In July 2018, the Group completed the private placement of a
5-year senior unsecured $100 million bond issue (the "Notes"). The
unsecured Notes were 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 was 25 July 2023;
- the Notes were redeemable in full with a prepayment penalty; and
- the interest rate was 10% per annum with semi-annual payment dates.
During the year, the Group was not in breach of any terms of the
Notes.
On 2 August 2022 the Group redeemed the $100m bond and paid a 2%
early repayment fee.
The Notes were traded on the Norwegian Stock Exchange and the
fair value at the prevailing market price as at the balance sheet
date was:
2022 2021
$'000 $'000
------- --- --------- --------
Notes - 103,750
As at year end, the Group's remaining contractual liability
comprising principal and interest based on undiscounted cash flows
is as follows:
2022 2021
$'000 $'000
----------------- -------- -------
Within one year - 10,000
Within two years - 105,639
--------
- 115,639
========================== =======
17 Provisions
Decommissioning provision 2022 2021
$'000 $'000
---------------------------------------- ------- ------
At 1 January 43,841 35,671
New provisions and changes in estimates (2,161) 7,429
Unwinding of discount 866 741
At 31 December 42,546 43,841
======= ======
The $2.2m decrease in new provisions and changes in estimates
comprises an increase relating to new drilling and facilities work
of $7.6 million (2021: $10.5 million), offset by a reduction of
$9.8 million (2021: $3.1 million) due to changes in inflation and
discount rates. The provision for decommissioning is based on the
net present value of the Group's estimated share of expenditure,
inflated in line with the table below and discounted at 3.8% (2021:
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.
Annual Inflation Assumption
(%)
2022 2021
------------- -------------- --------------
2022 - 2.00%
2023 5.00% 2.00%
2024 3.00% 2.00%
2025 - 2043 2.75% 2.00%
18 Deferred tax asset
The following are the major deferred tax liabilities and assets
recognised by the Group and movements thereon during the current
and prior reporting periods. The deferred tax assets arise in the
United Kingdom.
Accelerated Share-based Tax losses Total
tax depreciation payments carried
$'000 forward
$'000 $'000 $'000
-------------------------- ----------------- ----------- ---------- ------
At 1 January 2021 (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
(Charge)/credit to income
statement (139) 241 223 325
Exchange differences 62 (109) (87) (134)
----------------- ----------- ---------- ------
At 31 December 2022 (572) 1,181 967 1,576
================= =========== ========== ======
19 Financial instruments
2022 2021
$'000 $'000
-------------------------- -------- -------
Financial assets
Cash and cash equivalents 119,456 169,866
Receivables 162,990 178,258
-------- -------
282,446 348,124
Financial liabilities
Trade and other payables 128,886 99,589
Borrowings - 99,123
128,886 198,712
======== =======
All financial liabilities, except for 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.
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. On 2
August 2022 the company redeemed the Notes, therefore no amount
remained outstanding at 31 December 2022 (2021: fair value as
determined using market values of $103.8 million; carrying value of
$99.1 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 a $3.1 million provision
against trade receivables (2021: $1.1 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 (in prior year) 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.
Capital Structure
The Company'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 2022, 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.
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. Prior to redeeming the Notes in August 2022, the
Company paid interest on its Notes semi-annually in cash at 10% per
annum.
Based on the exposure to 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. A rate of 0.5% is used as it represents management's
assessment of a reasonable change in interest rates.
Credit risk management
Credit risk refers to the risk that a counterparty will default
on its contractual obligations resulting in financial loss to the
Group. As at 31 December 2022, the maximum exposure to credit risk
from a trade receivable outstanding from one customer is $161.1
million (2021: $175.8 million). Although the Group is confident in
the recovery of the trade receivables balance, a provision of $3.1
million (2021: $1.1 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.
20 Share capital
2022 2021
$'000 $'000
----------------------------------------- ------- -------
Authorised
Common shares of $1 each (2021: $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
----------------------------------------------
No. Share Share Total
of shares capital premium amount
'000 $'000 $'000 $'000
------------------------------- ----------- --------- ---------- ------------
Balance 1 January 2021 211,371 211,371 842,914 1,054,285
Dividends paid - - (100,000) (100,000)
Shares issued 2,360 2,360 - 2,360
Balance 31 December 2021 213,731 213,731 742,914 956,645
Dividends paid - - (214,789) (214,789)
Shares issued 2,516 2,516 - 2,516
Balance 31 December 2022 216,247 216,247 528,125 744,372
=========== ========= ========== ============
At 31 December 2022, a total of 0.4 million common shares at $1
each were held by the EBT (2021: 0.1 million at $1 each). These
common shares were included within reserves.
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 2022 2021
$'000 $'000
----- --------- --------
Cash flows from operating activities
Profit from operations 273,544 174,600
Adjustments for:
Depreciation, depletion and amortisation
of property, plant and equipment (including
the right of use assets) 80,883 55,111
Amortisation of intangible assets 859 25
Increase/(Decrease) of provision for
impairment of trade receivables 14 1,960 (7,065)
Put option hedging losses reclassified
to revenue - 3,752
Share-based payment expense 24 1,866 1,197
Impairment of PPE items 1,109 -
Operating cash flows before movements
in working capital 360,221 227,620
Increase in inventories (354) (258)
Decrease/(Increase) in trade and other
receivables 11,640 (75,259)
Increase in trade and other payables 12,339 36,977
Income taxes received - 75
Cash generated from operations 383,846 189,155
--------- --------
Reconciliation of property, plant and equipment additions to
cash flows from purchase of property, plant and equipment:
2022 2021
$'000 $'000
-------------------------------------------- --------- -------
Associated cash flows
Additions to property, plant and equipment 116,617 46,417
Movement in working capital (11,214) 6,927
Non-cash movements
Capitalised share option charges - (409)
Foreign exchange differences (112) 24
--------- -------
Purchase of property, plant and equipment 105,291 52,959
--------- -------
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 (2021: $0.7
million).
22 Lease Liabilities
During 2022, the total cash outflows relating to leased assets
was $0.5 million (2021: $0.7 million); this amount is the total of
capital repayments, interest charges and foreign exchange
impact.
2022 2021
$'000 $'000
------------------------------------------------------------------------------------------------- -------- -------
Analysed as:
Current liabilities (note 15 ) 385 419
Non-current liabilities (note 15 ) 325 789
-------- -------
710 1,208
======== =======
Lease liability maturity analysis
Year 1 385 419
Year 2 325 789
Amounts payable under leases
Within one year 436 509
In the second to fifth year inclusive 339 868
-------- -------
775 1,377
Less future interest charges (65) (169)
Net present value of lease obligations 710 1,208
-------- -------
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 2022, gross capital commitments in relation to the Shaikan
Field were estimated to be $41.9 million (2021: $20.6 million).
24 Share-based payments
2022 2021
$'000 $'000
----------------------------------------- ------- ------
Total share options charge 3,266 2,664
Capitalised share options charge - (409)
------- ------
Share options charge in Income Statement 3,266 2,255
======= ======
Value Creation Plan ("VCP")
The VCP was approved by shareholders in December 2016. As at 31
December 2022, nil (2021: 3.5 million) nil-cost share options were
outstanding under the VCP. There will be no further awards under
the plan.
During the year, the awards that were outstanding at 31 December
2021 vested, with the Company achieving a Total Shareholder Return
("TSR") of at least 8% compound annual growth, in accordance with
the VCP rules.
2022 2021
Number of Number of
share options share options
'000 '000
--------------------------- -------------- --------------
Outstanding at 1 January 3,508 7,017
Exercised during the year (3,508) (3,509)
Outstanding at 31 December - 3,508
Exercisable at 31 December - 3,508
============== ==============
No VCP options remained outstanding at 31 December 2022 with all
remaining awards at 2021 year end fully exercised in 2022.
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 as defined
in the scheme rules, the options may be exercised at any time
within a period of six months from departure date.
2022 2021
Number of Number of
share options share options
'000 '000
--------------------------- -------------- --------------
Outstanding at 1 January 65 973
Exercised during the year (55) (908)
Outstanding at 31 December 10 65
Exercisable at 31 December 10 65
============== ==============
The weighted average share price at the date of exercise for
share options exercised during the year was GBP2.56 (2021:
GBP1.70).
During the year no options (2021: nil) were granted to employees
under the Group's SRP.
A charge of nil (2021: nil) 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:
Expiry date Options ('000)
2022 2021
------------------ -------- -------
11 December 2026 9 12
30 June 2027 1 53
10 65
======== =======
The options outstanding at 31 December 2022 had a weighted
average remaining contractual life of 4 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.
2022 2021
Number of Number of
share options share options
'000 '000
--------------------------- -------------- --------------
Outstanding at 1 January 8,275 7,254
Granted during the year 2,278 2,747
Exercised during the year (586) (1,014)
Forfeited during the year (1,182) (712)
Outstanding at 31 December 8,785 8,275
Exercisable at 31 December - -
============== ==============
The weighted average share price at the date of exercise for
share options exercised during the year was GBP2.44 (2021:
GBP1.69).
The inputs into the calculation of fair values of the shares
granted during the year are as follows:
2022 2021
------------------------------------------------- --------- ---------
Weighted average share price GBP2.44 GBP2.26
Weighted average exercise price Nil Nil
Expected volatility 57.7% 58.7%
Expected life 3 years 3 years
Risk-free rate 0.14% 0.14%
Expected dividend yield (on the basis dividends Nil Nil
equivalents received)
========= =========
The options outstanding at 31 December 2022 had a weighted
average remaining contractual life of 2 years.
The aggregate of the estimated fair value of options granted in
2022 is $5.0 million (2021 $4.3 million).
A charge of $3.1 million (2021: $2.5 million) in relation to the
LTIP is included in the total share options charge.
25 Dividends
During 2022 a total of $215 million (2021: $100 million) of
dividends were paid to shareholders including an ordinary dividend
of $25 million (11.561 US cents per Common Share), a special
dividend of $50 million (23.12 US cents per Common Share) and
interim dividends totalling $140 million (65.27 US cents per Common
Share).
To date in 2023 an interim dividend of $25 million has been
paid. An ordinary dividend of $25million is subject to approval at
the AGM on 16 June 2023.
26 Related party transactions
The Company has a related party relationship with its
subsidiaries and in the ordinary course of business, enters into
various sales, purchase and service transactions with joint
operations in which the Company 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 2022 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
W Mwaura - Non-Executive Director (appointed July 2022)
J Harris - Chief Executive Officer
I Weatherdon - Chief Financial Officer
G Papineau-Legris - Chief Commercial Officer
C Kinahan - Chief Human Resources Officer
A Robinson - Chief Legal Officer and Company Secretary
S Catterall - Chief Operating Officer (resigned February
2022)
J Hulme - Chief Operating Officer (appointed April 2022)
The values below are calculated in accordance with IAS 19 and
IFRS 2.
2022 2021
$'000 $'000
------------------------------ ------- ------
Short-term employee benefits 4,725 5,809
Share-based payment - options 1,499 1,012
6,224 6,821
======= ======
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 (2021:
$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 June 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.
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END
FR SESESEEDSEID
(END) Dow Jones Newswires
March 23, 2023 03:00 ET (07:00 GMT)
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