REG - Gulf Keystone Petrol - 2022 Full Year Results
23/03/2023 07:15
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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 (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
(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 (mailto:aclark@gulfkeystone.com)
FTI Consulting +44 (0) 20 3727 1000
Ben Brewerton GKP@fticonsulting.com (mailto:GKP@fticonsulting.com)
Nick Hennis
or visit: www.gulfkeystone.com (http://www.gulfkeystone.com)
Notes to Editors:
Gulf Keystone Petroleum Ltd. (LSE: GKP) is a leading independent operator and
producer in the Kurdistan Region of Iraq. Further information on Gulf Keystone
is available on its website www.gulfkeystone.com
(http://www.gulfkeystone.com/)
Disclaimer
This announcement contains certain forward-looking statements that are subject
to the risks and uncertainties associated with the oil & gas exploration
and production business. These statements are made by the Company and its
Directors in good faith based on the information available to them up to the
time of their approval of this announcement but such statements should be
treated with caution due to inherent risks and uncertainties, including both
economic and business factors and/or factors beyond the Company's control or
within the Company's control where, for example, the Company decides on a
change of plan or strategy. This announcement has been prepared solely to
provide additional information to shareholders to assess the Group's
strategies and the potential for those strategies to succeed. This
announcement should not be relied on by any other party or for any other
purpose.
Chairman's statement
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
Realised 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.
2022 2021
$ million Restated((1))
$ 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 (#_2_Revenue) 460,113 301,389
Cost of sales 3 (#_3_Cost_of) (158,651) (111,721)
(Increase)/decrease of impairment provision on trade receivables 14 (#_14_Trade_and) (1,960) 7,065
Gross profit 299,502 196,733
Other general and administrative expenses 4 (#_4_General_and) (12,202) (13,643)
Share option related expenses 5 (#_5_Share_option) (13,756) (8,490)
Profit from operations 273,544 174,600
Finance revenue 7 (#_7_Finance_costs) 648 419
Finance costs 7 (#_7_Finance_costs) (9,655) (11,353)
Foreign exchange gains 1,232 57
Profit before tax 265,769 163,723
Tax credit 8 (#_8_Income_tax) 325 874
Profit after tax for the year 266,094 164,597
Profit per share (cents)
Basic 9 (#_9_Profit/(loss)_per) 123.52 77.14
Diluted 9 (#_9_Profit/(loss)_per) 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 2022 31 December 2021
$'000 $'000
Non-current assets
Intangible assets 10 (#_10_Intangible_assets) 4,307 3,583
Property, plant and equipment 11 (#_11_Property,_plant) 436,443 404,205
Deferred tax asset 18 (#_18_Deferred_tax) 1,576 1,385
442,326 409,173
Current assets
Inventories 13 (#_13_Inventories) 6,372 6,018
Trade and other receivables 14 (#_14_Trade_and) 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 (#_154_Trade_and) (128,561) (98,800)
Non-current liabilities
Trade and other payables 15 (#_154_Trade_and) (325) (789)
Borrowings 16 (#_156_Long_term) - (99,123)
Provisions 17 (#_17_Provisions) (42,546) (43,841)
(42,871) (143,753)
Total liabilities (171,432) (242,553)
Net assets 572,925 521,704
Equity
Share capital 20 (#_20_Share_capital) 216,247 213,731
Share premium 20 (#_19_Share_capital) 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
Share Cost of hedging reserve Exchange translation reserve Accumulated losses Total
Notes Share premium Treasury equity
capital shares
$'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 (#_24_Dividend) - (100,000) - - - - (100,000)
Employee share schemes 2 (#_23_Share-based_payments) 4 - - - - - 1,604 1,604
Share options exercised - - 2,592 - - (2,592) -
Share issues 20 (#_20_Share_capital) 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 (#_24_Dividend) - (214,789) - - - - (214,789)
Employee share schemes 2 (#_23_Share-based_payments) 4 - - - - - 1,866 1,866
Share issues 20 (#_20_Share_capital) 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 (#_21_Cash_flow) 383,846 189,155
Interest received 7 (#_7_Finance_costs_1) 648 419
Interest paid 16 (#_7_Finance_costs_1) (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 (#_21_Cash_flow) (105,291) (52,959)
Net cash used in investing activities (107,365) (55,684)
Financing activities
Payment of dividends 25 (#_25_Dividend) (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 119,456 169,866
hand
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 4 Applying IFRS 9 'Financial Instruments' with IFRS 4 'Insurance Contracts';
Extension of the Temporary Exemption from Applying IFRS 9
Amendments to IAS 1 Classification of Liabilities as Current or Non-current; Classification of
Liabilities as Current or Non-current - Deferral of Effective Date;
Non-current Liabilities with Covenants
Amendments to IFRS 16 Lease Liability in a Sale and Leaseback
Amendments to IFRS 17 Initial Application of IFRS 17 and IFRS 9 - 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 1 and IFRS Practice Statement 2 Disclosure of Accounting Policies
Amendments to IAS 8 Definition of Accounting Estimates
Amendments to IAS 12 Deferred Tax related to Assets and Liabilities arising from a Single
Transaction
The directors do not expect that the adoption of the Standards listed above
will have a material impact on the financial statements of the Group in future
periods.
Statement of compliance
The financial statements have been prepared in accordance with United Kingdom
adopted International Accounting Standards.
Basis of accounting
The financial statements have been prepared under the historical cost basis,
except for the valuation of hydrocarbon inventory and the valuation of certain
financial instruments, which have been measured at fair value, and on the
going concern basis. Equity-settled share-based payments are recognised at
fair value at the date of grant, 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 financial asset to that asset's net carrying amount on
initial recognition.
Intangible assets
Intangible assets include computer software and are measured at cost and
amortised over their expected useful economic lives of three years.
Property, plant and equipment ("PPE")
Oil and gas assets
Development and production assets
Development and production assets are accumulated on a field-by-field basis
and represent the costs of acquisition and developing the commercial reserves
discovered and bringing them into production, together with the exploration
and evaluation expenditure incurred in finding commercial reserves, directly
attributable overheads and costs for future restoration and decommissioning.
These costs are capitalised as part of PPE and depreciated based on the
Group's depreciation of oil and gas assets policy.
The net book values of producing assets are depreciated generally on a
field-by-field basis using the unit of production ("UOP") basis which uses the
ratio of oil and gas production in the period to the remaining commercial
reserves plus the production in the period. 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 impairment 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 (#_23_Share-based_payments) .
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 (#_23_Share-based_payments) .
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 began
commercial production from the Shaikan Field in July 2013 and historically
made sales to both the domestic and export markets. The Group considers that
revenue can be 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 1.7⁰C in 2100.The NZE being the normative scenario pathway to the
stabilisation of global average temperatures at 1.5 °C 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 430 318
accounts
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 of employees Average number 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 (#_23_Share-based_payments) ) 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 (#_156_Long_term) ) (5,833) (10,000)
Unwinding of finance and arrangement fees (see note 16 (#_156_Long_term) ) (879) (489)
Notes repayment fee (see note 16) (2,000) -
Finance lease interest (77) (123)
Unwinding of discount on provisions (see note 17 (#_167_Provisions) ) (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 $'000
Current year credit 216 75
Prior year adjustment - 28
Deferred UK corporation tax credit (see note 18 (#_17_Deferred_tax) ) 109 771
Tax credit attributable to the Company and its subsidiaries 325 874
The Group is not required to pay taxes in Bermuda on either income or capital
gains. The Group has received an undertaking from the Minister of Finance in
Bermuda exempting it from any such taxes at least until the year 2035.
In the Kurdistan Region of Iraq, the Group is subject to corporate income tax
on its income from petroleum operations under the Kurdistan PSC. Under the
Shaikan PSC, any corporate income tax arising from petroleum operations will
be paid from the KRG's share of petroleum profits. Due to the uncertainty over
the payment mechanism for oil sales in Kurdistan, it has not been possible to
measure reliably the taxation due that has been paid on behalf of the Group by
the KRG and therefore the notional tax amounts have not been included in
revenue or in the tax charge. This is an accounting presentational issue and
there is no taxation to be paid.
The annual UK corporation tax rate for the year ended 31 December 2022 was
19.0% (2021: 19.0%).
On 3 March 2021, the UK Government announced that the corporation tax rate in
the UK will increase to 25% for companies with taxable profits above £250,000
with effect from 1 April 2023, as well as announcing a number of other changes
to allowances and treatment of losses. These changes were substantively
enacted as at 31 December 2021.
Deferred tax is provided for due to the temporary differences, which give rise
to such a balance in jurisdictions subject to income tax. All deferred tax
arises in the UK.
9 Profit per share
The calculation of the basic and diluted profit per share is based on the
following data:
2022 2021
Profit after tax for basic and diluted per share calculations ($'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
(#_4_Other_general) ).
11 Property, plant and equipment
Oil and gas Fixtures and Right of use assets Total
assets equipment $'000
$'000 $'000
$'000
Year ended 31 December 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 (#_3_Cost_of) ). 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
(#_4_Other_general) ).
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 incorporation Proportion of ownership interest Principal activity
Gulf Keystone Petroleum (UK) Limited United Kingdom 100% Management, support, geological, geophysical and engineering services
6th floor
New Fetter Place
8-10 New Fetter Lane
London EC4A 1AZ
Gulf Keystone Petroleum International Limited Bermuda 100% Exploration, evaluation, development and production activities in Kurdistan
Cedar House, 3rd Floor
41 Cedar Avenue
Hamilton HM12
Bermuda
Name of joint operation Location Proportion of ownership interest Principal
activity
Shaikan Kurdistan 80% Production and development activities
( )
13 Inventories
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 (#_22_Lease_Liabilities) ) 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 (#_22_Lease_Liabilities) ) 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 8,712 10,489
notes early repayment fee
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 (#_154_Trade_and) ) - 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 tax depreciation Share-based payments Tax losses carried forward Total
$'000 $'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 (#_154_Trade_and) ), 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 (#_14_Trade_and) ), 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 (#_14_Trade_and) ). 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 (#_20_Share_capital) 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. of shares Share capital Share premium Total 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 80,883 55,111
(including the right of use assets)
Amortisation of intangible assets 859 25
Increase/(Decrease) of provision for impairment of trade receivables 14 (#_14_Trade_and) 1,960 (7,065)
Put option hedging losses reclassified to revenue - 3,752
Share-based payment expense 24 (#_23_Share-based_payments) 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 (#_154_Trade_and) ) 385 419
Non-current liabilities (note 15 (#_154_Trade_and) ) 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 £2.56 (2021: £1.70).
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 £2.44 (2021: £1.69).
The inputs into the calculation of fair values of the shares granted during
the year are as follows:
2022 2021
Weighted average share price £2.44 £2.26
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 equivalents received) Nil Nil
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 4,725 5,809
benefits
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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