THIS
ANNOUNCEMENT CONTAINS INSIDE INFORMATION
27 March 2024
ITHACA ENERGY PLC
("Ithaca Energy", the "Company" or the "Group")
Full
Year 2023 Results
Robust 2023 operational and
financial performance with continued strategic delivery, supporting
long- term value creation
Ithaca Energy, a leading UK
independent exploration and production company, today announces its
audited full year results for the year ended 31 December
2023.
Financial key performance
indicators (KPIs)
|
2023
|
2022
|
Group adjusted EBITDAX1
($m)
|
1,722.7
|
1,916.2
|
Net cash flow from operating
activities ($m)
|
1,290.8
|
1,723.3
|
Available liquidity1 ($m)
|
1,028.2
|
578.8
|
Statutory net income ($m)
|
215.6
|
1,031.5
|
Unit operating expenditure1 ($/boe)
|
20.5
|
19.0
|
Other KPIs
Total production (boe/d)
|
70,239
|
71,403
|
Tier 1 process safety events
|
1
|
-
|
Serious injury and fatality
frequency
|
-
|
-
|
Scope 1 and 2 emissions
(tCO2e3)
|
435,792
|
483,325
|
Greenhouse gas intensity
(kgCO2e/boe)
|
25.0
|
23.8
|
1 Non-GAAP measure (see pages
77 to 79)
2023 Strategic and Operational
Highlights
·
Full year production of 70.2 thousand barrels of
oil equivalent per day (kboe/d), in line with previously stated
guidance of 68-74 kboe/d
- Underpinned by high levels of production efficiency across
our operated asset base of 84%
- Production split 66% liquids and 34% gas
·
Increase in Year-end 2P reserves and 2C resources
to 544 mmboe (2022: 512 mmboe)
·
Significant progress across our strategic goals
in 2023, delivering against our BUY, BUILD and BOOST
BUY
·
Completed acquisitions of the remaining 40% stake
in Fotla and 30% stake in Cambo, at minimal near-term cost,
providing full control over pre-Final Investment Decision (FID)
work programme and timing
BUILD
·
FID taken to progress Phase I of the Rosebank
development, the UK's largest undeveloped discovery with all major
contracts awarded and work underway to upgrade the Petrojarl Knarr
FPSO
·
Pre-FID work continues across the Group's
high-value greenfield and brownfield development portfolio
including:
-
Actively engaging with potential farm-in partners
to enable the future progression of Cambo and Fotla towards FID,
subject to fiscal and market conditions
-
Awarded license milestone extensions from 31
March 2024 to 31 March 2026 for Cambo field, on 19 March
2024
-
Captain Electrification FEED study matured to
support FID in 2024, subject to market and fiscal
conditions
-
Marigold Unitisation and Unit Operating Agreement
executed with work progressing on preparation of a Field
Development Plan
-
Fotla development concept selection in
2024
·
Successful exploration drilling at the K2
prospect (Ithaca Energy working interest 50%) and appraisal
drilling at non-operated Leverett field, with good flow rates
achieved (Ithaca Energy working interest 12%)
BOOST
·
Captain Enhanced Oil Recovery (EOR) Phase II
project now substantially complete (>90%), supporting first
Phase II polymer injection into the subsea wells in summer 2024
with the remaining project scopes to completion including
commissioning and subsea tie-in activities
2023 Financial Highlights
Key financial highlights in-line
with estimated results provided in FY 2023 Trading Update on 15
February 2024
·
|
Adjusted EBITDAX of $1,723 million
(2022: $1,916 million) on revenues of $2,319 million (2022: $2,599 million)
|
·
|
Net cash flow from operating
activities of $1,291 million (2022: $1,723 million)
|
·
|
Net Operating costs of $524
million, representing a net unit opex cost of $20.5/boe (2022:
$19.0/boe) at the bottom end of lowered management guidance of
$525-$575 million. Operating cost performance reflects the success
of the Group's internal cost optimisation projects and stringent
cost control, and improved FX rates.
|
·
|
Trading performance benefited from
the Group's active hedging policy with $266 million of hedge gains
in the year due to realised oil prices of $85/bbl before hedging
(2022: $100/bbl) and $82/bbl after hedging (2022: $91/bbl) and gas
prices of $76/boe before hedging (2022: $149/boe) and $111/boe
after hedging (2022: $137/boe)
|
·
|
Net producing asset capital cost of $393 million, at the bottom end of management guidance
of $390-$435 million reflecting
reduction in planned activity
|
·
|
Net capital spend of $97 million
on Rosebank development project, in line with management guidance
of $90-$110 million and reflecting the meaningful activity in 2023
as project activity ramps up to support a targeted first oil date
of 2026/27
|
·
|
Strong cash flow generation
supported continued deleveraging of the business, reporting a
reduction in adjusted net debt from $971.2 million to $571.8
million, representing a Group leverage position of 0.33x (2022:
0.51x), with the Group's Reserve Based Lending Facility fully paid
down
|
·
|
Third Interim 2023 dividend
declared of $134 million payable in April 2024, delivering against
our IPO commitment of a total 2023 dividend of $400 million,
representing ~30% of post-tax CFFO for the year
|
Guidance and Outlook 2024
·
We expect full year 2024 production in range of
56-61 kboe/d reflecting:
- A
reduction in investment in near-term projects as a direct result of
the Energy Profits Levy including deferred or cancelled projects at
the Greater Stella Area, Montrose Arbroath Area, Elgin Franklin
Area and Alba
- Longer path to Captain EOR II polymer well driven peak
production, which is now expected in 2026. Ultimate reserve
recovery of EOR Phase I and II remains unchanged
- Operational issues at non-operated Pierce and Schiehallion
fields and compressor issues at Erskine's host facility (Lomond)
impacting production in Q1 2024
·
FY 2024 net operating cost guidance range of
$540-590 million driven partly by tariff revenue reductions in the
Greater Stella Area due to third party field production
decline
·
FY 2024 net producing asset capital cost guidance
range of $335-385 million (excluding pre-FID projects and Rosebank
development)
·
FY 2024 net Rosebank project capital cost
guidance range of $190-230 million
·
FY 2024 cash tax guidance of $345-355
million
·
Drawdown on unutilised capex carry arrangements
of $150 million
·
Reaffirming dividend policy for 2024 targeting
dividend at the top end of our capital allocation policy range of
15 - 30% post-tax CFFO
Medium-Term
·
Beyond 2024, the Group expects production growth
through the medium-term with a return towards 80 kboe/d by 2027, as
we see the full benefit of investment in our Captain EOR Phase II
project and first production from the sanctioned Rosebank
development
·
Strategic M&A focus on adding complementary
cash-generative production portfolios that will support our
investment in long-term organic growth opportunities to build a
portfolio of significant scale and longevity
·
Continued focus on advancing high-value
development projects and preserving optionality across our
portfolio while prioritising capital allocation to maximise
sustainable shareholder returns
Exclusivity Agreement for a
potential transformational combination with Eni S.p.A.'s UK
Business
·
Ithaca Energy today announces that it has entered
into an exclusivity agreement (the "Exclusivity Agreement") in relation to
a potential transformational combination with substantially all of
Eni S.p.A.'s ("Eni") UK
upstream assets including the recently acquired Neptune Energy
assets, excluding certain assets including Eni's CCUS and Irish sea
assets (the "Potential
Combination")
·
Pursuant to the Exclusivity Agreement, Eni has
granted Ithaca Energy exclusivity in respect of the assets the
subject of the Potential Combination for a period of four weeks
from the date of this announcement. Ithaca Energy and Eni have
entered into the Exclusivity Agreement to allow time to separately
progress the contractual documentation required in connection with
the Potential Combination.
Key highlights of the Potential
Combination
·
Eni will contribute its UK business in exchange
for the issuance of new Ithaca Energy shares to Eni, with Eni
anticipated to hold between 38% and 39% of the enlarged issued
share capital of Ithaca Energy following completion
·
Eni has a well-diversified asset base across four
key hubs: Elgin Franklin, J-Area, Cygnus and Seagull; Ithaca Energy
is already a partner in the Elgin Franklin and Jade
fields
·
Eni's UK business had 2023 pro forma production
of 40-45 kboe/d and 2P reserves of c.100 mmboe as at 31 December
20231
·
The Potential Combination would represent a
value-accretive opportunity for Ithaca Energy's shareholders,
supporting delivery of the Company's BUY, BUILD and BOOST
strategy
·
The Potential Combination would:
o Add significant scale and diversification to Ithaca Energy's
business: Significantly growing pro-forma production to above 100
kboe/d, creating the 2nd largest independent operator in the UKCS
by production2
o Create a leading UKCS portfolio: Enhancing Ithaca Energy's
status as the largest independent operator by resource, holding
stakes in 6 of the 10 largest fields3
o Enable material future growth for Ithaca Energy: Boost
near-term cash flows to unlock growth from Ithaca Energy's
development projects whilst supporting shareholder
returns
o Create a long-term strategic partnership with Eni: Eni would
become a major shareholder in the enlarged group supportive of
delivery of Ithaca Energy's BUY, BUILD and BOOST strategy. It is
contemplated that Ithaca Energy would have access to Eni's leading
technical expertise to drive future growth.
·
Ithaca Energy anticipates that the Potential
Combination will require shareholder approval as a Class 1
transaction. Additionally, as Eni UK will hold between 38% and 39%
of the voting rights of Ithaca Energy at completion of the
Potential Combination, a mandatory offer would normally be required
under Rule 9 of the UK Code on Takeovers and Mergers (the
"Takeover Code"). However,
given that Delek Group will still hold shares carrying more than
50% of the voting rights following completion of the Potential
Combination, the UK Panel on Takeover and Mergers (the "Panel") have granted a dispensation
from Rule 9 pursuant to note 5 (b) of Rule 9 under the Takeover
Code. Accordingly, completion of the Potential Combination will not
be conditional upon and will not require approval by Ithaca
Energy's independent shareholders in relation to a Rule 9
waiver.
·
Although the discussions are at an advanced
stage, there can be no certainty that a Potential Combination will
occur, nor as to the final terms or timing on which a Combination
might be concluded.
Executive Chairman, Gilad Myerson, commented: "I am delighted to share the news that we have
entered into an Exclusivity Agreement with Eni S.p.A to explore a
transformational combination with Eni UK's upstream assets. We
believe this potential combination would be a strong strategic fit
with Eni UK's cash generative portfolio complementing Ithaca
Energy's high-quality, long-life asset base with significant
development opportunity.
1 Wood Mackenzie
2 Wood Mackenzie
3 Wood Mackenzie
Eni has a proven track record of
value creation through its strategic satellite model with regional
exploration and production companies including successful joint
ventures in Norway and Angola with Vår Energi and Azule Energy
respectively. We look forward to updating the markets in the coming
month."
Interim Chief Executive Officer and Chief Financial Officer,
Iain Lewis, commented: "We have
made material progress in 2023, executing against our BUY, BUILDand BOOSTstrategy including the milestone
sanctioning of Phase I of the Rosebank development and the
significant progress towards delivering our Captain EOR Phase II
project.
I am pleased to share a strong set
of financial results for 2023, despite the significant fiscal and
political headwinds we have faced in the year. The Energy Profits
Levy continues to have a direct impact on investment in the UK
North Sea, with projects across our operated and non-operated
deferred or cancelled. The extension of the Energy Profits Levy by
a further year to a sunset date of March 2029, highlights the
continued fiscal uncertainty our sector faces."
Ithaca Energy will host an in
person and virtual presentation and Q&A session for investors
and analysts at 09:00 GMT today, 27 March 2024, accessible via our
website: https://investors.ithacaenergy.com/
Performance
Overview
Executing our BUY, BUILD and BOOST Strategy
We made significant progress
across our strategic goals in 2023, delivering against our BUY,
BUILD and BOOST strategy to support the material long-term growth
of the Group. We continue to focus on maximising value from across
our diverse portfolio with targeted investment in high-quality
assets demonstrating our commitment to investing in the UK North
Sea.
In 2023, we were delighted to
announce the landmark sanctioning of Phase I of the Rosebank
development, with total recoverable resources over 300 mmboe and
Phase I gross reserves of 234 mmboe. As the UK's largest
undeveloped discovery, the field will provide critically important
domestic energy, supporting a forecasted 7% of UK oil production
from first production to 2030. And crucially, with its low carbon
emissions design, the field has the potential to
produce at a fraction of the world's average
CO2 emissions contributing to both the
UK's energy security and Net Zero objectives.
The Rosebank development is core
to Ithaca Energy's BUILD strategy, executing on the material
development portfolio acquired from Siccar Point Energy in 2022.
With estimated net production of 15 kboe/d at the field's peak and
a production life of 25 years, the field supports the Group's
medium to long-term production growth. After taking the Final
Investment Decision (FID), project activity has ramped up with work
underway on upgrading the Petrojarl Rosebank FPSO (previously named
Petrojarl Knarr), including making the vessel electrification ready
in line with the North Sea Transition Deal. In 2024, work will
commence on the installation of templates and satellite structures
as part of the multi-year development timeline towards first
production in 2026/27.
At Captain, material progress was
made during the year on executing Phase II of our pioneering
polymer Enhanced Oil Recovery (EOR) project with the project now
over 90% complete and on track to support first Phase II polymer
injection into the subsea wells in summer 2024. Remaining work
scopes include final commissioning activities on the topsides,
subsea tie-in campaign and completion of the drilling programme
(completed during Q1 2024).
The EOR Phase II project, designed
to maximise and accelerate reserve recovery from Captain and
deliver on our strategy to BOOST field performance, will build on
the success of the first phase of polymer injection with over 12
mmbbls recovered to date. Extensive subsurface modelling completed
in H2 2023 to refine the predicted EOR Phase II polymer response,
based on reprocessed seismic and latest field performance, has
successfully confirmed initial overall EOR Phase II reserve
recovery predictions. However, our expectation is that Captain
production will now follow a longer path to peak response with
production expected to peak in 2026, before plateau.
The Group continues to leverage
our M&A capabilities to deliver on our BUY strategy evaluating
potential inorganic opportunities both in the UK and
internationally. In 2023, the Group acquired the remaining stakes
of the Cambo and Fotla fields with the aim of preserving the
long-term value of our assets by taking full control of pre-FID
work programmes and timing.
Following the successful extension
of the Cambo license milestones from 31 March 2024 to 31 March
2026, the Group is actively engaging with potential farm-in
partners to secure an aligned joint venture partnership that would
enable the future progression of the Cambo project towards
FID.
In line with the Group's BUILD
strategy we continue to target high-return tie-back opportunities
close to existing infrastructure to maximise reserve recovery. In
2023, the Group reported positive appraisal activity at its
non-operated Leverett discovery (Ithaca Energy Working Interest:
12%) and successful exploration drilling at its operated K2
prospect (Ithaca Energy Working Interest: 50%), however, the
subsequent side-track encountered significant operational issues
due to severe weather caused by Storm Babet and the sidetrack was
suspended.
Strong delivery against 2023
management guidance
Our production in 2023 averaged
70.2 kboe/d (2022: 71.4 kboe/d), closing the year towards the
mid-point of our 68-74 kboe/d production guidance range. Production
was split 66% liquids and 34% gas with the Group's operated assets
accounting for 51% of total 2023 production.
Our production performance in 2023
has been supported by strong production efficiency across our
operated base of 84%, reflecting our commitment to maximise asset
value through operational excellence. Most notably at FPF-1, where
our focus on value and our investment in driving operational
efficiency and uptime improvements continues to yield production
efficiency rates above 90%.
Production from our non-operated
portfolio was impacted by the delayed start-up and curtailed
production from the Pierce field, where operational issues related
to the vessel mooring system have temporarily shut down production
from the field. We expect this issue to be rectified during H1
2024.
Operating costs in 2023 of $524
million (2022: $496 million), representing a net unit Opex cost of
$20.5/boe (2022: $19.0/boe), came in below revised and lowered
management guidance of $525 million to $575 million, reflecting the
Group's stringent focus on cost control in an inflationary
environment, improved FX rates and a reduction in planned
activity.
Total net producing asset capital
expenditure (excluding decommissioning) of $393 million (2022: $405
million), came in at the bottom end of the Group's management
guidance range of $390 million to $435 million. Net capital
expenditure on the progression of the Rosebank development totalled
$97 million, compared to management guidance of $90 million to $110
million reflecting the meaningful activity in 2023 as project
activity ramps up to support a targeted 2026/27 first oil
date.
During 2023, the Group launched a
cost optimisation project focused on maintaining tight control on
expenditure across our operated and non-operated assets and
corporate overhead base. The project was successful in continuing
to build upon Ithaca Energy's strong cost culture and delivered
more than $100 million of cash savings during the year.
Strong safety performance is
critical to our continued success
Safety is our non-negotiable,
number-one priority and is central to our business success - we do
it safely or not at all. The Group delivered a slightly improved
safety performance in 2023, with fewer Tier 1 and Tier 2 process
safety events recorded in the year (2023: 1 Tier 1 and 2 events,
2022: 2 Tier 1 and 2 events). However, we believe there are areas
for continued improvement and the Group is responding to an
increase in personal safety incidents and process safety near
misses in the final quarter of the year by revisiting the tone of
safety leadership across the business.
Major accident prevention has been
a core focus area in 2023, with the introduction of a process
safety barrier tool across all operating locations designed to
strengthen our defences against high-potential incidents and
process safety events. The Process Safety Fundamentals programme
supports greater visibility of our Major Accident Hazard (MAH)
risks and aims to enable front-line workers to focus on process
safety where potential for MAH events present in day-to-day
operations. We will continue to support the roll-out of the barrier
tool in 2024 with the aim of improving our focus on process safety
risks and maintaining focus on preventing high-consequence
events.
Meaningful focus on Decarbonisation
As we continue to progress
short-term emissions reductions projects, we have made significant
progress towards our long-term emissions reduction strategy,
following the decision to proceed with the development of the low
emission intensity Rosebank field. Development of Rosebank will act
as a material catalyst as the Group looks to fundamentally
transition our portfolio to low-intensity assets in the medium to
long-term, as older higher-intensity assets move closer to the
natural end of their life.
The Rosebank FPSO has been
designed to be electrification ready as part of its optimised
design to reduce carbon emissions, in line with the North Sea
Transition Deal. The Group is collaborating with Equinor (as
Operator), industry partners and government to pursue a regional
solution for power from shore to Rosebank and nearby fields to
minimise carbon emissions from production. With full
electrification, it is estimated that the
Rosebank lifetime upstream CO2 intensity would decrease from 12kg
to approximately 3kg CO2/boe - a seventh of the current UK
average of 21kg CO2/boe and a fraction of the emissions intensity associated
with importing.
The Group's Scope 1 and 2 GHG
emissions across our operated profile reduced from 483,325
tCO2e in 2022 to
435,792 tCO2e in
2023, representing a slight increase per barrel from 23.8kg
CO2/boe to 25.0kg
CO2/boe,
due to a reduction in operated assets production
in 2023 versus 2022, and an absolute reduction of 23%, compared to
our 2019 baseline. The 23% reduction achieved in 2023 versus the
Group's 2019 baseline, reflects reductions achieved through
operational improvements of 12%, as well as a 11% reduction in
emissions associated with Alba's John Brown turbine outage during
the year, which is not expected to be a recurring reduction. We
continue to work hard to deliver our targeted 25% reduction in
Scope 1 and 2 CO2e emissions on a net equity basis by 2025 and
remain on track to reach this target.
2023 has seen continued progress
across our operated portfolio delivering operational improvements
at FPF- 1 and Captain, while expanding our focus to more material
emission reduction initiatives such as the potential for
electrifying our flagship Captain field. Following a successful
conclusion of a pre-Front-End Engineering and Design (FEED) study
in Q1 2023, FEED activity commenced in Q2 and has been matured to
support a Financial Investment Decision in the coming months. With
over 70% of Captain's GHG emissions related to power generation,
partial electrification of the asset has the potential to
substantially reduce emissions intensity and is
critical to the Group's ability to achieve its targeted 50%
reduction in Scope 1 and 2 CO2e emissions on a net equity basis by 2030. We continue to seek
assurances from the UK government to ensure the protection of the
decarbonisation allowance on sanctioned projects to protect the
economic viability of the project. In parallel, the Group will
determine investment viability as projects compete for capital
following a reduction in cash flow available for reinvestment as a
result of the continued impact of the Energy Profits
Levy.
Robust cash flow generation
supporting low leverage position
In 2023, we delivered another year
of strong cash flow generation supporting the further strengthening
of our balance sheet. Our diversified, high-quality asset base
reported adjusted EBITDAX of $1.7 billion (2022: $1.9 billion),
generated free cash flow of $0.7 billion (2022: $1.1 billion),
lowering our adjusted net debt position to $571.8 million at
year-end (2022: $971.2 million), representing an adjusted net debt
to adjusted EBITDAX ratio of 0.33x (2022: 0.51x).
With a robust available liquidity
position at 31 December 2023 of over $1 billion (2022: $0.6
billion), the Group has sufficient available capital to support our
future growth plans. During 2023, we have entered into attractive
lending arrangements that supplement our existing capital structure
including a five-year $100 million term loan facility agreement
with bp at a commercial interest rate, and a $150 million project
capex carry arrangement which was unutilised at the
year-end.
Profit for the year of $215.6
million (2022: $1,031.5 million), was impacted by a $557.9 million
pre-tax impairment charge (post-tax $154.0 million), principally in
relation to the Greater Stella Area (GSA) and Alba, together with
other gains of $89.1 million in the period. The impairment charge
for GSA follows the decision not to proceed with further infill
drilling at Harrier, as a direct result of the Energy Profits Levy
(EPL) and falling gas prices and in relation to Alba due to the
reduction in estimated future production.
Following revisions to the Energy
Profits Levy in November 2022, that saw the rate of EPL rise to
35%, the Group incurred current EPL charges of $333.4 million in
the year (2022: $131.4 million), with the charge payable in October
2024. The Group's cash flows continue to be protected by our tax
efficient structure with a material ring fence corporate tax and
supplementary charge tax loss position of $4.5 billion at
year-end.
The importance of the Group's
robust hedging policy has been highlighted in the year, with
hedging gains recorded of $266 million. As we move into 2024, we
continue to take a disciplined approach to hedging, recognising the
importance of balancing upside exposure to commodity prices while
managing downside protection of our cash flows. At year-end, the
Group has a hedged position of 8.2 million barrels of oil
equivalent (mmboe) (57% oil) from 2024 into 2025 at an average
price floor of $78/bbl for oil and 135p/therm for gas.
In our first full year as a listed
company, we are delighted to report that our strong financial
performance in the year has supported the delivery of our 2023
dividend target. The Board has declared a further interim dividend
of $134 million in respect of the 2023 financial year, bringing our
overall 2023 dividend to $400 million, representing ~30% post-tax
cash flow from operations (CFFO) in the year.
Outlook
Following a successful year of
progress against our BUY, BUILD and BOOST strategy in 2023, we
enter 2024 with a strong and diverse portfolio of cash-generative
assets and increased 2P Reserves and 2C Resources of 544 mmboe
(2022: 512 mmboe) following the acquisition of the remaining stakes
in Cambo and Fotla, offset by a full year of production. With
further strengthening of our balance sheet in 2023, we are well
positioned to continue to deliver against our capital allocation
framework supporting our long-term growth aspirations.
Through strategic acquisitions we
have preserved our investment optionality across our portfolio with
significant brownfield and greenfield development opportunities
such as Cambo, Marigold, Fotla and Tornado and infill drilling at
Montrose, Schiehallion and Mariner. With further consolidation in
the sector likely due to continued market dislocation, our focus in
2024 will be on prioritising investment across our portfolio
alongside the potential for value-accretive M&A to maximise
shareholder returns.
As a direct result of the Energy
Profits Levy, investment across the UK North Sea during 2023 has
been significantly impacted, as the UK competes for capital across
global portfolios. Our 2024
production guidance of 56-61 kboe/dreflects the impact of
deferred or cancelled projects across our operated and non-operated
asset base including in the Greater Stella Area, Montrose Arbroath
Area, Elgin Franklin Area and Alba.
Beyond 2024, the Group expects
production growth through the medium-term with a return towards 80
kboe/d by 2027, as we see the full benefit of investment in our
Captain EOR Phase II project and first production from the
sanctioned Rosebank development.
Our operating cost guidance for 2024 of
$540-590 million reflects our
continued focus on cost control but increasing net costs from the
$524 million 2023 outturn, due partly to tariff revenues reducing
with lower third-party throughput at Greater Stella Area. As a
result of forecasted reductions in 2024 volumes we expect an
increase in unit operating cost per barrel in the
short-term.
Our mid-term ambition is to drive
down our average operating cost per barrel as we transition our
portfolio to earlier-life assets from mature assets with a
significantly lower unit operating cost profile.
Our producing asset capital cost guidance of $335-385
million (excluding capital
investment for projects awaiting Final Investment Decision and
Rosebank), reflects investment in executing the final stages of the
Captain EOR Phase II project to completion and first injection in
the subsea wells, continued drilling at Mariner and Schiehallion
and facilities upgrades at Captain. In 2024, we forecast capital
spend on the Rosebank development
to be in the range of $190-230 million reflecting a
significant ramp up of activities including FPSO upgrades and
installation of subsea templates and satellites
structures.
Ithaca Energy is targeting a 2024
dividend at the top end of its capital allocation policy range of
15 - 30% post-tax CFFO.
Enquiries
The information contained within this announcement is deemed
by Ithaca Energy to constitute inside information for the purposes
of Article 7 of the Market Abuse Regulation (EU)
No 596/2014 (as it forms part of UK domestic law by virtue of the
European Union (Withdrawal) Act 2018). By the publication of this
announcement via a Regulatory Information Service, this inside
information is now considered to be in the public
domain.
The person
responsible for making this announcement on behalf of Ithaca Energy
is Julie McAteer, General Counsel and Company
Secretary.
About Ithaca Energy plc
Ithaca Energy is a leading UK
independent exploration and production company focused on the UK
North Sea with a strong track record of material value creation. In
recent years, the Company has been focused on growing its portfolio
of assets through both organic investment programmes and
acquisitions and has seen a period of significant M&A driven
growth centred upon two transformational acquisitions in recent
years. Today, Ithaca Energy is one of the largest independent oil
and gas companies in the United Kingdom Continental Shelf (the
"UKCS"), ranking second by resources.
With stakes in six of the ten
largest fields in the UKCS and two of UKCS's largest
pre-development fields, and with energy security currently being a
key focus of the UK Government, the Group believes it can utilise
its significant reserves and operational capabilities to play a key
role in delivering security of domestic energy supply from the
UKCS.
Ithaca Energy serves today's needs
for domestic energy through operating sustainably. The Group
achieves this by harnessing Ithaca Energy's deep operational
expertise and innovative minds to collectively challenge the norm,
continually seeking better ways to meet evolving
demands.
Ithaca Energy's commitment to
delivering attractive and sustainable returns is supported by a
well-defined emissions-reduction strategy with a target of
achieving net zero by 2040.
Ithaca Energy plc was admitted to
trading on the London Stock Exchange (LON: ITH) on 14 November
2022.
-ENDS-
Financial review
Our first full year as a listed company has not been
without its challenges including the investment and cash impact of
fiscal changes. Yet despite these, we have reduced adjusted net
debt by approximately $400 million during the year and have lowered
our leverage ratio to 0.33 times adjusted net debt to adjusted
EBITDAX whilst paying out $266 million of interim dividends.
We have achieved another strong year of production as
well as maintaining our focus on operating costs with initiatives
such as the Partnered Cost Optimisation project.
We have delivered a robust set of results, as well as
moving forwards with sanctioning of the Rosebank development and
strengthening our positions with the Cambo and Fotla prospects.
With a strong liquidity position at year end of $1,028
million (2022: $578.8 million), the Group has sufficient available
capital to support investment and is well positioned to finance
future growth plans. During the year we have entered into
attractive lending arrangements including a new $100 million
five-year term loan facility with bp and a $150 million capex carry
arrangement which was unutilised at the year end.
Statutory profit for the year of $215.6 million (2022:
$1,031.5 million) was impacted by a $557.9 million pre-tax
impairment charge principally in relation to the Greater Stella
area following the decision not to proceed with Harrier drilling,
as a direct result of the Energy Profits Levy (EPL) and falling gas
prices and in relation to Alba due to a reduction in estimated
future production. In 2022, we benefitted from a one-off gain on
bargain purchase of $1,335.2 million partly offset by a deferred
tax charge of 766.5 million on the introduction of EPL.
The increase in the EPL rate to 35% at the start of
the year was another disappointment for the industry as it further
reduces the free cash available for reinvestment. However, despite
this, we have continued to create substantive organic value through
2023 and we believe that our capital allocation framework should
give investors confidence as we seek to continue to grow value
through 2024 and beyond.
The Group reported average production of 70,239 boe/d
for 2023 (2022: 71,403 boe/d) driving Groupadjusted EBITDAX of
$1,722.7 million, net cash flow from operations of $1,290.8 million
and statutory profit for the year of $215.6 million.
Financial
performance: adjusted EBITDAX
Adjusted EBITDAX is a key measure of operational
performance delivery in the business and in 2023 was $1,722.7
million (2022: $1,916.2 million). The reduction in EBITDAX was due
to a combination of lower commodity prices, higher unit operating
expenditure, discussed further below and slightly lower production
volumes driven mainly by the planned maintenance shutdowns in Q3
2023.
Average realised oil prices for the year were $85/boe
before hedging results and $82/boe after hedging results (2022:
$100/boe before hedging results and $91/boe after hedging results).
Average realised gas prices for 2023 were $76/boe before hedging
results and $111/boe after hedging results (2022: $149/boe before
hedging results and $137/boe after hedging results).
Unit operating expenditure increased to $20.5/boe
(2022: $19.0/boe) largely due to the planned Q3 shutdowns as well
as inflationary pressures slightly outweighing our disciplined cost
management approach across the portfolio. When post shutdown
production resumed in Q4 2023, unit operating expenditure was
$18.5/boe which was broadly the same as Q4 2022.
Total costs and
charges
Total costs and charges amounted to $2,017.8 million
(2022: $358.0 million) and comprised:
|
2023
$m
|
2023
$m
|
Depletion, depreciation and
amortisation
|
(740.3)
|
(662.9)
|
Operating costs
|
(576.7)
|
(547.8)
|
Movement in inventory
|
20.6
|
(130.3)
|
Inventory provision
|
(16.3)
|
-
|
Royalties
|
(4.4)
|
(11.3)
|
Impairment charges
|
(557.9)
|
(31.5)
|
Exploration and evaluation
|
(13.6)
|
(9.0)
|
Other gains/losses
|
89.1
|
(9.5)
|
Administrative expenses
|
(34.3)
|
(87.9)
|
Gain on bargain purchase
|
-
|
1,335.2
|
Net finance costs
|
(184.0)
|
(203.0)
|
Total costs
and charges
|
(2,017.8)
|
(358.0)
|
Depletion, depreciation and amortisation charges were
$740.3 million (2022: $662.9 million). The year-on-year increase is
principally due to the full-year effect of acquisitions made during
2022. Depletion, depreciation and amortisation per barrel was $29
(2022: $25).
Operating costs amounted to $576.7 million (2022:
$547.8 million) with the increase driven by the full-year impact of
acquisitions made in 2022. As noted above, unit operating
expenditure increased principally as a result of the Q3 maintenance
shutdowns.
Movements in oil and gas inventories was a credit of
$20.6 million (2022: charge of $130.3 million) representing
movements in underlift/overlift entitlement imbalances.
Materials inventory provisions of $16.3 million (2022:
$nil) were made in respect of principally MonArb, Britannia and
Elgin-Franklin.
Impairment charges of $557.9 million (2022: $31.5
million) principally reflects charges in respect of the Greater
Stella area and Alba following changes in commodity prices and
planned drilling activities due to EPL.
Exploration and evaluation costs amounted to $13.6
million (2022: $9.0 million) and principally related to licence
relinquishments during the year as a result of unsuccessful
geotechnical evaluation.
Other gains of $89.1 million (2022: losses of $9.5
million) comprise principally the settlement of a claim relating to
a historic acquisition of $50.1 million and a $43.0 million gain on
the revaluation and realisation of commodity hedges.
Administrative expenses were $34.3 million (2022:
$87.9 million) with the decrease principally due to non-recurring
costs associated with the IPO of $20.3 million and acquisition
costs of $25.8 million in 2022.
Gain on bargain purchase in 2022 arose on the Marubeni
and Siccar Point Energy acquisitions (see note 17 for further
details).
Net finance costs were $184.0 million (2022: $203.0
million) with the reduction principally due to there no longer
being interest on related-party loans which were repaid during 2022
and lower bank interest due to lower debt levels, partly offset by
higher accretion charges as the discount rate on long-term
liabilities has increased from 2.5% in the year to 31 December 2022
to 4.25% in the year to31 December 2023.
Taxation
The tax charge for the year was $86.4 million (2022:
$1,029.0 million) with the reduction principally due to the
introduction of the EPL last year. The charge for 2022 included an
exceptional EPL deferred tax charge of $766.5 million and a current
EPL tax charge of $131.4 million compared to a 2023 EPL deferred
tax credit of $215.9 million and a current EPL tax charge of $333.4
million.
Earnings per share
(EPS)
Statutory EPS was 21.4 cents (2022: 102.6 cents) and
adjusted EPS was 36.7 cents (2022: 46.0 cents). Adjusted EPS
eliminates items which distort year-on-year comparisons such as
gain on bargain purchase, impairment charges, the tax effect of
these items where applicable and the exceptional non-cash deferred
EPL charge upon initial implementation in 2022.
Shares in
issue
During the year, 7.8 million shares were issued to the
Ithaca Energy plc Employee Benefit Trust (EBT) in order to satisfy
the exercise of employee share options during the year and in
future. As at 31 December 2023 there were 1,014.4 million (2022:
1,006.6 million) shares in issue.
The weighted average number of shares, excluding
shares held by the EBT, for EPS calculations was 1,006.7 million
(2022: 1,005.2 million).
Dividends
Interim dividends of $266.0 million (2022: $nil) were
paid during the year. A further interim dividend for FY 2023 of
$134.0 million will be paid in April 2024.
Financial position:
assets/liabilities/equity
|
2023
$m
|
2023
$m
|
Total assets
|
6,246.6
|
6,759.6
|
Total liabilities
|
(3,802.2)
|
(4,302.1)
|
Net assets
and shareholders' equity
|
2,444.4
|
2,457.5
|
Assets
At 31 December 2023, total assets amounted to$6,246.6
million (2022: $6,759.6 million), of which current assets were
$845.6 million (2022: $988.7 million) and non-currents assets were
$5,401.0 million (2022: $5,770.9 million). The decrease in total
assets during the year was primarily due to fixed asset impairment
charges of $557.9 million and lower cash balances of $100.6 million
due to the repayment of debt partly offset by a higher deferred tax
asset of $235.3 million due principally to the asset impairment
charges.
Liabilities
At 31 December 2023, total liabilities amounted to
$3,802.2 million (2022: $4,302.1 million) including decommissioning
provisions of $1,859.7 million (2022: $1,720.5 million) and
non-current borrowings of $718.2 million (2022: $1,213.7 million).
The reduction in total liabilities during the year was primarily
due to lower noncurrent borrowings of $495.5 million and a
reduction in trade and other payables of $232.8 million due to a
lower level of negative value commodity hedge positions, partly
offset by higher decommissioning liabilities of $139.2 million,
mainly due to revisions to asset retirement obligation estimates,
and higher current tax payable of $214.4 million principally due to
EPL.
Equity and
reserves
At 31 December 2023, total equity and reserves
amounted to $2,444.4 million (2022: $2,457.5 million) The decrease
in equity and reserves during the year was primarily due to interim
dividend payments of $266.0 million partly offset by the retained
profit for the year of $215.6 million and net hedging gains of
$23.9 million.
Financial position:
cash
|
2023
$m
|
2023
$m
|
Opening
cash
|
253.8
|
44.8
|
Operating cash flows
|
1,290.8
|
1,723.3
|
Investing cash flows
|
(492.4)
|
(1,404.2)
|
Financing cash flows
|
(900.7)
|
(107.4)
|
Foreign exchange
|
1.7
|
(2.7)
|
Net cash flow
|
(100.6)
|
209.0
|
Closing
cash
|
153.2
|
253.8
|
Undrawn borrowing facilities
|
725.0
|
325.0
|
Undrawn capex carry facility
|
150.0
|
-
|
Available
liquidity
|
1,028.2
|
578.8
|
Operating cash
flows
Net cash from operating activities amounted to
$1,290.8 million (2022: $1,723.3 million) after accounting for
adverse working capital movements of $210.8 million (2022:
favourable movements of $94.8 million) with the reduction
principally due to lower operating profit, the working capital
movements and higher corporation tax payments during the year.
Investing cash
flows
Cash flow used in investing activities was $492.4
million (2022: $1,404.2 million) reflecting capital expenditure of
$478.8 million (2022: $380.6 million) driven mainly by Captain
enhanced oil extraction activities and Rosebank, including ongoing
modifications to the FPSO. 2022 included investing cash flows
related to acquisitions (net of cash acquired) of $957.4 million
being primarily the Siccar Point Energy ($926.7 million)
acquisition.
Financing cash
flows
Cash outflow from financing activities amounted to
$900.7 million (2022: $107.4 million) with dividend payments of
$266.0 million (2022: $nil), interest costs and lease payments of
$141.7 million (2022: $177.2 million) and a net reduction in
principal debt of $500.0 million (2022: net increase of $50.0
million).
At 31 December 2023, cash balances were $153.2 million
(2022: $253.8 million) and available liquidity was $1,028.2 million
(2022: $578.8 million).
Principal
risks
The principal and emerging risks facing the Group are
the same as those set out in the H1 Trading Update.
Derivative financial
instruments
Derivative financial instruments are utilised to
manage commodity price risk in a substantive financial hedging
programme for future oil and gas production volumes. As at 31
December 2023, the following hedges were in place:
|
2024
|
2025
|
Oil
|
|
|
Volume hedged (mmboe)
|
4.7
|
-
|
Weighted average floor hedged price
($/bbl)
|
78
|
-
|
|
|
|
Gas
|
|
|
Volume hedged (mmboe)
|
3.0
|
0.5
|
Weighted average floor hedged price
|
137
|
123
|
Subsequent
events
On 6 March 2024, it was announced that EPL will be
extended by a further year to 31 March 2029. If this had been
enacted at the balance sheet date, it is estimated that this would
have increased the deferred tax liability by $112.2 million.
On 19 March 2024, the North Sea Transition Authority
sanctioned the extension of the licence on the Cambo field to 31
March 2026.
On 26 March 2024, the Group signed an exclusivity
agreement between ENI and Ithaca Energy covering substantially all
of ENI's UK upstream assets, excluding ENI CCUS and Irish sea
assets, under which ENI has granted Ithaca exclusivity whilst a
potential business combination is pursued. Under the terms of the
proposed business combination ENI is anticipated to hold between
38% and 39% of the enlarged issued share capital of Ithaca Energy
following completion. If this progresses further, it will be
subject to the issuance of both a Circular and a Prospectus and the
related shareholder approvals and will also be subject to, amongst
other things, regulatory approvals.
Going
concern
Management closely monitor the funding position of the
Group including monitoring continued compliance with covenants and
available facilities to ensure sufficient headroom is maintained to
fund operations.
Management have considered a number of risks
applicable to the Group that may have an impact on the Group's
ability to continue as a going concern. Short-term and long-term
cash forecasts are produced on aweekly and quarterly/annual basis
respectively along with any related sensitivity analysis. This
allows proactive management of any business risks including
liquidity risk.
The Directors consider the preparation of the
financial statements on a going concern basis to be appropriate.
This is due to the following key factors:
• Continuing robust commodity price backdrop and a
well-hedged portfolio over the next 12 months;
• New unsecured loan arrangements of $100 million with
bp which was fully drawn at 31 December 2023 and a new $150 million
optional project specific capital expenditure carry arrangement
available at the discretion of the Group which was undrawn at 31
December 2023;
• Reserves Based Lending (RBL) headroom of $836
million ($nil drawn versus $836 million available),plus $303
million of cash at 22 March 2024; and
• Robust operational performance and a well
diversified portfolio
.
The Group's base case going concern assessment assumes
an average oil price of $81/bbl and a gas price of 67p/therm in
2024 and an oil price of $77/bbl and a gas price of 75p/therm in
the six months to 30 June 2025 with production in line with
approved asset plans.
Owing to the ongoing fluctuations in commodity demand
and price volatility, management prepared sensitivity analyses to
the forecasts and applied a number of plausible downside scenarios
including: decreases in production of 10%, reduced sales prices of
20% and increases in operating and capital expenditures of 10%.
Management aggregated these scenarios to create a reasonable
combined worst-case scenario. The sensitivity analysis showed that,
after consideration of the mitigation strategies within
management's control, there was no reasonably possible scenario
that would result in the business being unable to meets its
liabilities as they fall due. The analysis demonstrated that the
Group would still continue to comply with financial covenants and
have sufficient liquidity throughout the period to 30 June 2025 to
continue trading.
In addition reverse stress tests have been performed
reflecting further reductions in commodity prices, prior to any
mitigating actions, to determine at what levels they would have to
reach such that either lending covenants are breached or there is
no liquidity headroom left. This stress test demonstrated that the
likelihood of the fall in price required to cause a breach of
covenants or liquidity issue, is considered sufficiently remote in
the context of the mitigation strategies available to management.
The mitigation strategies within the control of management include
the reduction in uncommitted capital expenditure and variable opex
savings in the low production scenario. In addition to this, there
is also further potential to refinance the Group's borrowing
arrangements.
Based on their assessment of the Group's financial
position over the period to 30 June 2025, the Directors believe
that the Group will be able to continue in operational existence
for the foreseeable future. Accordingly, they continue to adopt the
going concern basis of accounting in preparing the consolidated
financial statements.
Consolidated statement of profit or loss
For the year ended 31 December
|
|
|
Note
|
2023
US$'000
|
2022
US$'000
|
Revenue
|
5
|
2,319,811
|
2,598,482
|
Cost of sales
|
6
|
(1,317,010)
|
(1,352,324)
|
Gross profit
|
|
1,002,801
|
1,246,158
|
Impairment charges
on development and production assets
|
19
|
(557,936)
|
(31,467)
|
Exploration and evaluation expenses
|
14
|
(13,634)
|
(9,040)
|
Administrative expenses
|
7
|
(34,259)
|
(87,851)
|
Other gains/(losses)
|
8
|
89,091
|
(9,429)
|
Gain on
bargain purchase
|
17
|
-
|
1,335,171
|
Profit from
operations before
tax, finance
income and
finance costs
|
|
486,063
|
2,443,542
|
Finance
income
|
9
|
5,688
|
695
|
Finance costs
|
9
|
(189,724)
|
(203,708)
|
Profit before
tax
|
|
302,027
|
2,240,529
|
Income tax
|
27
|
(86,392)
|
(1,208,997)
|
Profit for the year
|
|
215,635
|
1,031,532
|
Earnings per
share
|
Note
|
2023
Cents
|
2022
Cents
|
Basic
|
10
|
21.4
|
102.6
|
Diluted
|
10
|
21.2
|
102.1
|
The results above are entirely derived from continuing operations.
|
|
|
|
The accompanying notes
on pages
23 to
75 are
an integral
part of
the financial
statements.
|
|
|
|
Consolidated statement of comprehensive
income
For the year ended 31 December
|
|
|
|
|
Note
|
2023
US$'000
|
2022
US$'000
|
Profit for the year
|
|
215,635
|
1,031,532
|
Items that may be reclassified to profit and loss
|
|
|
|
Fair value gains on cash flow hedges
|
29
|
92,484
|
453,862
|
Fair value gains on cost of hedging
|
|
3,116
|
14,231
|
Deferred tax charge on cash
flow hedges and cost of hedging
|
27
|
(71,700)
|
(200,455)
|
Other comprehensive
income
|
|
23,900
|
267,638
|
Total comprehensive
income for
the year
|
|
239,535
|
1,299,170
|
The accompanying notes
on pages
23 to
75 are
an integral
part of
the financial
statements.
|
|
|
|
Consolidated statement of financial
position
as at 31 December
|
|
|
Note
|
2023
US$'000
|
2022
US$'000
|
Assets
|
|
|
|
Current
assets
|
|
|
|
Cash and
cash equivalents
|
|
153,215
|
253,822
|
Trade and other receivables
|
11
|
334,290
|
359,994
|
Decommissioning
reimbursements
|
11
|
30,417
|
38,115
|
Prepaid expenses and decommissioning
securities
|
12
|
37,678
|
9,055
|
Inventories
|
13
|
150,496
|
176,881
|
Derivative financial instruments
|
30
|
139,497
|
150,858
|
|
|
845,593
|
988,725
|
Non-current assets
|
|
|
|
Decommissioning reimbursements
|
11
|
165,064
|
162,710
|
Exploration and evaluation assets
|
14
|
548,354
|
775,773
|
Property, plant
and equipment
|
15
|
3,258,206
|
3,634,896
|
Deferred tax assets
|
27
|
627,738
|
392,456
|
Derivative financial instruments
|
30
|
17,810
|
21,191
|
Goodwill
|
18
|
783,848
|
783,848
|
|
|
5,401,020
|
5,770,874
|
Total assets
|
|
6,246,613
|
6,759,599
|
Liabilities and
equity
|
|
|
|
Current
liabilities
|
|
|
|
Borrowings
|
20
|
(29,913)
|
-
|
Trade and other payables
|
22
|
(478,607)
|
(711,412)
|
Current tax payable
|
27
|
(321,116)
|
(106,678)
|
Decommissioning
liabilities
|
23
|
(107,026)
|
(146,829)
|
Lease liability
|
24
|
(19,898)
|
(41,637)
|
Contingent and deferred consideration
|
25
|
(101,669)
|
(107,680)
|
Derivative financial instruments
|
30
|
(13,708)
|
(136,668)
|
|
|
(1,071,937)
|
(1,250,904)
|
Consolidated Statement of financial position
continued
As at 31 Deember
|
|
|
|
|
Note
|
2023
US$'000
|
2022
US$'000
|
Non-current liabilities
|
|
|
|
Borrowings
|
20
|
(718,238)
|
(1,213,731)
|
Decommissioning
liabilities
|
23
|
(1,752,652)
|
(1,573,711)
|
Lease liability
|
24
|
(660)
|
(17,221)
|
Contingent and deferred consideration
|
25
|
(258,700)
|
(219,120)
|
Derivative financial instruments
|
30
|
-
|
(27,440)
|
|
|
(2,730,250)
|
(3,051,223)
|
Total liabilities
|
|
(3,802,187)
|
(4,302,127)
|
Net assets
|
|
2,444,426
|
2,457,472
|
Shareholders' equity
|
|
|
|
Share capital
|
26
|
11,540
|
11,445
|
Share premium
|
26
|
308,845
|
293,712
|
Capital contribution reserve
|
26
|
181,945
|
181,945
|
Own shares
|
26
|
(12,412)
|
-
|
Share-based payment reserve
|
26
|
15,494
|
4,920
|
Cash flow hedge
reserve
|
29
|
39,818
|
16,710
|
Cost of hedging
reserve
|
29
|
4,068
|
3,275
|
Retained earnings
|
|
1,895,128
|
1,945,465
|
Total equity
|
|
2,444,426
|
2,457,472
|
The accompanying notes
on pages
23 to
75 are
an integral
part of
the financial
statements.
|
|
|
|
Approved on behalf of the Board on 26 March 2024:
|
|
|
|
Iain C S Lewis
Director
|
|
|
|
Consolidated statement of changes in equity For the year ended 31 December
|
|
|
|
Share
|
Share
|
Capital contribution
|
|
Share-based
|
Cash
flow
|
Cost
of
|
|
|
|
|
capital
|
premium
|
reserve
|
Own
Shares
|
payment
reserve
|
hedge reserve
|
hedging
reserve
|
Retained
earnings
|
Total
|
|
Note
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
Balance at 1 January 2022
|
|
1
|
634,658
|
114,000
|
-
|
-
|
(242,791)
|
(4,862)
|
175,503
|
676,509
|
Issuance
of shares for capital reduction
|
26
|
114,000
|
-
|
(114,000)
|
-
|
-
|
-
|
-
|
-
|
-
|
Reduction in capital
|
26
|
(114,000)
|
(634,658)
|
-
|
-
|
-
|
-
|
-
|
748,658
|
-
|
Issuance of shares
|
26
|
11,444
|
293,712
|
-
|
-
|
(3,004)
|
-
|
-
|
(10,228)
|
291,924
|
Capital contribution through debt cancellation
|
26
|
-
|
-
|
181,945
|
-
|
-
|
-
|
-
|
-
|
181,945
|
Share-based payments
|
26
|
-
|
-
|
-
|
-
|
7,924
|
-
|
-
|
-
|
7,924
|
Comprehensive income
for the
year:
|
|
|
|
|
|
|
|
|
|
|
Profit for the year
|
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
1,031,532
|
1,031,532
|
Other comprehensive income
|
|
-
|
-
|
-
|
-
|
-
|
259,501
|
8,137
|
-
|
267,638
|
Total comprehensive
income for
the year
|
|
-
|
-
|
-
|
-
|
-
|
259,501
|
8,137
|
1,031,532
|
1,299,170
|
Balance at
31
December 2022
|
|
11,445
|
293,712
|
181,945
|
-
|
4,920
|
16,710
|
3,275
|
1,945,465
|
2,457,472
|
Balance at 1 January 2023
|
|
11,445
|
293,712
|
181,945
|
-
|
4,920
|
16,710
|
3,275
|
1,945,465
|
2,457,472
|
Dividends
|
33
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
(265,972)
|
(265,972)
|
Issuance of shares
|
26
|
95
|
15,133
|
-
|
(15,228)
|
-
|
-
|
-
|
-
|
-
|
Share-based payments
|
26
|
-
|
-
|
-
|
2,816
|
10,574
|
-
|
-
|
-
|
13,390
|
Comprehensive income
for the
year:
|
|
|
|
|
|
|
|
|
|
|
Profit for the year
|
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
215,635
|
215,635
|
Other comprehensive income
|
|
-
|
-
|
-
|
-
|
-
|
23,108
|
793
|
-
|
23,901
|
Total comprehensive
income for
the year
|
|
-
|
-
|
-
|
-
|
-
|
23,108
|
793
|
215,635
|
239,536
|
Balance at
31
December 2023
|
|
11,540
|
308,845
|
181,945
|
(12,412)
|
15,494
|
39,818
|
4,068
|
1,895,128
|
2,444,426
|
Detail on the movements in the capital contribution reserve
can be
found in
notes 26
and 31.
The ccompanying notes on
pages 23to 75are
an integral part of the financial statements.
Consolidated statement of cash flows
For the year ended 31 December
|
|
|
Note
|
2023
US$'000
|
2022
US$'000
|
Cash provided
by/(used in):
|
|
|
|
Operating
activities
|
|
|
|
Profit before tax
|
|
302,027
|
2,240,529
|
Adjustments
for:
|
|
|
|
Depletion, depreciation
and amortisation
|
15
|
740,300
|
662,947
|
Impairment of capitalised exploration
and evaluation
expenditure
|
14
|
13,634
|
9,040
|
Impairment charges on
development and
production assets
|
19
|
557,936
|
31,467
|
Increase in contingent/deferred
consideration
|
|
8,008
|
4,295
|
Loan fee
amortisation
|
9
|
4,508
|
6,418
|
Fair value gains on derivatives
|
29
|
(43,059)
|
(16,787)
|
Gain on
bargain purchase
|
|
-
|
(1,335,170)
|
Hedging resets1
|
|
-
|
(39,680)
|
Accretion
|
9
|
76,162
|
56,511
|
Finance costs
|
9
|
109,054
|
122,163
|
Interest income
|
9
|
(5,688)
|
-
|
Interest on related-party loan
|
9
|
-
|
17,924
|
Unrealised foreign exchange on cash and cash equivalents
|
|
(1,725)
|
2,464
|
Share-based payment
expenses
|
|
13,390
|
14,069
|
Decommissioning expenditure
|
|
(95,552)
|
(65,707)
|
Operating cash
flows before
movements in
working capital
|
|
1,678,995
|
1,710,483
|
Decrease
in inventories
|
|
26,386
|
4,051
|
Decrease/(increase) in
trade and
other receivables
|
|
12,540
|
(50,575)
|
(Decrease)/increase in
trade and
other payables
|
|
(249,760)
|
141,275
|
Operating cash
flows
|
|
1,468,161
|
1,805,234
|
Corporation tax paid
|
|
(176,305)
|
(81,914)
|
Settlement
of foreign exchange and commodity derivative financial
instruments
|
29
|
(6,739)
|
-
|
Interest received
|
|
5,688
|
-
|
Net cash from operating activities
|
|
1,290,805
|
1,723,320
|
Consolidated statement
of
cash flows
continued
For the year ended 31 December
|
|
|
Note
|
2023
US$'000
|
2022
US$'000
|
Investing activities
|
|
|
|
Capital expenditure
|
|
(478,838)
|
(380,640)
|
Acquisition of subsidiaries
net of cash acquired
|
17
|
-
|
(957,452)
|
Deferred consideration payments
|
25
|
(6,367)
|
(55,092)
|
Contingent consideration payments
|
25
|
(7,200)
|
(11,040)
|
Net cash used in investing activities
|
|
(492,405)
|
(1,404,224)
|
Financing activities
|
|
|
|
Receipt
from issue of equity
|
|
-
|
299,749
|
Dividends paid
|
|
(265,972)
|
-
|
Payments
for lease liabilities (principal)
|
24
|
(41,902)
|
(34,348)
|
Repayment of RBL loan
|
|
(600,000)
|
(500,000)
|
Repayment
of shareholder loan
|
|
-
|
(273,055)
|
Drawdown of RBL loan
|
|
-
|
550,000
|
Drawdown of bp loan
|
|
100,000
|
-
|
Bank interest and charges
paid
|
|
(99,825)
|
(142,820)
|
Interest
rate swaps
|
9
|
6,967
|
851
|
Costs of share issue
|
|
-
|
(7,825)
|
Net cash used in financing activities
|
|
(900,732)
|
(107,448)
|
Currency translation differences relating
to cash
|
|
1,725
|
(2,675)
|
(Decrease)/increase in
cash and
cash equivalents
|
|
(100,607)
|
208,973
|
Cash and cash equivalents at
1 January
|
|
253,822
|
44,849
|
Cash and cash equivalents at 31 December
|
|
153,215
|
253,822
|
1. Hedging resets relate to the amortisation of the deferred reset gains which have been recycled to the current year profit and loss.
|
|
|
|
The accompanying notes
on pages
23 to
75 are
an integral
part of
the financial
statements.
|
|
|
|
Notes to the consolidated
financial statements
1. General information
Ithaca Energy plc (the Group or Ithaca Energy), is a Company limited by shares incorporated
and domiciled
in the
UK and
is a Group involved in the development and production of oil and gas in the North Sea. The Group's registered office
is 33 Cavendish Square, London, United Kingdom, W1G 0PP.
The financial information for the
years ended 31 December 2023 and 2022 contained in this document
does not constitute statutory accounts of Ithaca Energy plc (the
Company), as defined in section 435 of the Companies Act
2006. The
financial information for the years ended 31 December 2023 and 2022 have been extracted from the consolidated financial statements
of Ithaca
Energy plc
and all
its subsidiaries
(the Group),
which were
authorised by
the Board
of Directors
on 26
March 2024
and which
will be
delivered to
the Registrar
of Companies
in due
course. The
auditor's report
on those
financial statements was unqualified and did not contain a statement under section 498 of the Companies Act 2006.
2. Basis of preparation
The consolidated financial
statements are
prepared in
accordance with
United Kingdom
adopted International Accounting
Standards (IAS)
and in
conformity with
the requirements
of the
Companies Act
2006. The
consolidated financial statements
are presented
in US
Dollars as
this is
the functional
currency of
the business.
All values
are rounded
to the
nearest thousand
(US$'000), except
when otherwise
indicated. The principal
accounting policies applied
in the preparation of the financial statements
are set out below. These policies have been consistently applied
to all
the periods
presented.
3. Material accounting policies, judgements and estimation
uncertainty
Basis of measurement
The consolidated financial
statements have
been prepared
on a going concern basis using the historical cost convention, except for the revaluation of certain financial assets and financial liabilities, under
International Financial Reporting
Standards (IFRS),
to fair
value, including
derivative instruments. Historical
cost is
generally based
on the
fair value
consideration given in exchange for the assets and liabilities.
Going concern
Management closely monitor the funding position of the Group including monitoring
compliance with
covenants and
available facilities to ensure sufficient
headroom is
maintained to
fund operations.
Management have
considered a
number of
risks applicable
to the
Group that
may have
an impact
on the
Group's ability
to continue
as a going concern. Short-term and long-term cash forecasts are prepared on a weekly and quarterly/annual
basis respectively along
with any
related sensitivity analysis.
This allows
proactive management of any business risk including liquidity risk.
The Directors consider the preparation of the
financial statements on a going concern basis to be appropriate.
This is due to the following key factors:
•
Continuing robust
commodity price
backdrop and
a well-hedged
portfolio over
the next
12 months;
•
New unsecured
loan arrangement
of $100
million with
bp which
was fully
drawn at
31 December
2023 and
a new
$150 million
optional project
specific capital
expenditure carry
arrangement available at the discretion of the Group which was undrawn at 31
December 2023;
•
Reserves Based Lending
(RBL) liquidity headroom of $836 million
($nil drawn versus $836 million
available), plus $303 million of cash as
at 22 March 2024; and
•
Robust operational performance and a
well-diversified portfolio.
Cash flow forecast - base case
assumptions:
|
|
2024
|
H1 2025
|
Average oil price
|
$/bbl
|
81
|
77
|
Average gas price
|
p/th
|
67
|
75
|
Average hedged oil price
(including floor price for zero cost collars)
|
$/bbl
|
78
|
N/A
|
Average hedged gas price
(including floor price for zero cost collars)
|
p/th
|
137
|
123
|
Owing to the ongoing fluctuations
in commodity
demand and
price volatility,
management prepared sensitivity
analyses to
the forecasts
and applied
a number
of plausible
downside scenarios including
decreases in
production of
10%, reduced
sales prices
of 20%
and increases
in operating
and capital
expenditures of
10%. Management
aggregated these
scenarios to
create a
reasonable combined worst-case
scenario. The
sensitivity analysis showed that, after
consideration of mitigation strategies within
management's control, there were was no reasonably possible
scenario that would result in the business being unable to meet its
liablilities as they fell due. In addition, reverse stress tests
have been performed reflecting
further reductions in commodity prices,
prior to
any mitigating
actions, to
determine at
what levels
prices would
have to
reach such
that there
is no
liquidity headroom left. The stress test demonstrated
that the
likelihood of
the fall
in prices
required to
cause a
liquidity issue
is considered
sufficiently remote in the context of the mitigation strategies
available to
management. The
mitigation strategies within
the control
of management
include a
reduction in
uncommitted capital expenditure
and variable
opex savings
in the
low production
scenario. In
addition to
this, there
is also
further potential
to refinance
the Group's
borrowing arrangements. The
analysis demonstrated that the Group would
still continue to comply with financial covenants and have
sufficient liquidity throughout the period to 30 June 2025 to
continue trading.
3. Material accounting policies,
judgements and estimation uncertainty continued
Based on their assessment of the Group's financial position
in the
period to
30 June
2025, the
Directors believe
that the
Group will
be able
to continue
in operational
existence for
the foreseeable
future. Accordingly, they
continue to adopt the
going concern basis of accounting in preparing the financial
statements.
Basis of
consolidation
The consolidated financial
statements of
the Group
includes the
financial information of Ithaca Energy and all wholly-owned subsidiaries
as listed
per note
31. All
intergroup transactions and balances have been eliminated on consolidation.
Subsidiaries are all entities over which the Group has control. The plc controls an entity when the Group is exposed to or has rights to variable returns from its investments with the entity and has the ability to affect those returns through its power over the
investee. Subsidiaries are fully consolidated
from the date on which control is transferred to the
Group. They
are deconsolidated on
the date
that control
ceases.
Impact of climate change on the
financial statements and related notes
Judgements and estimates made in assessing the impact of climate change and the energy transition
Climate change and the transition to a lower-carbon system
were considered
in preparing
the consolidated
financial statements. These
may have
the potential
for significant
impacts on
the carrying
values of
the Group's
assets and
liabilities discussed below as well as on assets and liabilities that may be reflected in the future. There is also the potential for significant impact
on future
cash flows.
There is
generally a
high level
of uncertainty
about the
speed and
magnitude of
impacts of
climate change
which, together
with limited
historical data,
provides significant challenges
in the
preparation of
forecasts and
financial plans
with a
wide range
of potential
future outcomes.
The Group's ambition is to have one of the lowest carbon emission portfolios
in the
UK North
Sea and
to achieve
Net Zero
(whereby the
amount of
CO2 added by the Group's activities is no greater than the amount taken away), on a net equity basis (by applying the Group's working interest in each respective asset to the total emissions of that asset), and in respect of Scope 1 and 2 emissions, by 2040, ten years ahead of the North Sea Transition Deal commitment. This will be achieved by optimising the Group's current portfolio
in the
short term
and fundamentally
transitioning the
Group's portfolio
over the
medium to
long term
whilst maintaining forecast
levels of
production. Initiatives include,
but are
not limited
to, operational
improvements, offshore electrification,
and the
eventual cessation of production of mature fields which have higher carbon intensity. Where the Group cannot reduce Scope 1 and Scope 2 emissions, Ithaca Energy will invest in carbon offsets to achieve the Group's goal of Net Zero. All new economic investment decisions
include estimated
costs of
the energy
transition based
on existing
technology and
estimated costs
of carbon
and these
opportunities are
assessed on
their climate
impact potential
and alignment
with Ithaca
Energy's Net
Zero target,
taking into
account both
greenhouse gas
volumes and
emissions intensity.
Specific considerations of
the potential
impacts of
climate change
on significant
judgements and
estimates used
in the
consolidated financial statements
are considered
below. The
items outlined
below are
likely to
manifest themselves over a number of years and are therefore not generally considered
to represent
'key sources
of estimation
uncertainty' as
required by
IAS 1
(being those
which could
have a
material impact
on the
Group's results
in the
12 months
following the
reporting date)
which are
separately disclosed later in this note.
Impairment of goodwill and property, plant and equipment
The energy transition
has the
potential to
significantly impact future commodity and carbon prices in that as the UK and global energy system decarbonises,
reduced demand
for oil
and gas
products in
favour of
low carbon
alternatives could cause oil and gas prices to fall which would, in turn, affect the recoverable amount
of goodwill
and property,
plant and
equipment. In
the current
period management's estimate
of the
long-term commodity price assumptions are, in real terms from 2028, $93/bbl for Brent
Crude and 87p/therm for UK NBP gas. Further details of climate
change including a sensitivity in this area are provided in note
19.
Recoverable values used for
impairment testing for all cash-generating units (CGUs) include the
estimated cost of UK carbon emissions allowances of £70 per tonne
for CO2e. The recoverable value of CGU's may be impacted
by future carbon pricing legislation changes,
which could
increase operating costs through higher emissions allowances
or the
introduction of
other carbon
pricing mechanisms. Electrification
of offshore
operations for
specific assets
is planned
in line
with the
Group's 2040
Net Zero
ambitions and
where feasible
based on
existing technology, estimated
electrification costs are included within the assessment of the recoverable value
of the
relevant CGU.
Property, plant and equipment - depreciation and useful economic lives
The energy transition
has the
potential to
reduce the
expected useful
economic lives
of assets
and hence
accelerate depreciation charges.
Although no
changes have
been identified
or recognised
to date,
as noted
in the
Strategic Report
on page
[XX],
it is
anticipated that
certain higher
emission-intensity assets such as FPF-1 and Alba will cease production in the medium term and will be replaced by new lower-emission
intensity assets.
Management does
not currently
expect the
useful economic
lives of
the Group's
reported property, plant and equipment to significantly change solely as a result of the energy transition. However,
significant capital expenditure
is still
required for
ongoing projects and
therefore the useful lives of future capital expenditure may be
different
.
Intangible assets - exploration and evaluation assets
The impacts of climate change and the energy transition
may affect
the viability
of exploration
prospects. The
recoverability of
the existing
intangibles was
considered during
2023, however,
no significant
write-offs were
identified as
a result
of climate
change considerations. Viability
of these
assets will
continue to
be assessed
on a regular basis.
Decommissioning
provisions
Most of the Group's existing decommissioning
obligations are estimated to be completed over the course of the
next 20 years. The impacts of climate change and the energy
transition may bring forward the expected timing
of decommissioning activity,
increasing the
present value
of the
associated decommissioning provisions.
The potential
impact of
a reasonably
possible acceleration of estimated decommissioning
dates, which
considers the
potential impact
of the
energy transition, is considered to be two years. The impact of such an acceleration of cessation of production across
the Group's
entire producing
portfolio would
result in
an increase
in the
decommissioning provision of approximately $69
million (2022:
$74 million).
The risk
in this
area may
increase if
key assets
within the
Group's existing
exploration, appraisal and development portfolio
proceed to
the production
stage, as
this is
likely to
significantly extend the life of the Group's portfolio, in some cases to 2050 or beyond.
While the pace of the transition to a lower-carbon economy is uncertain, oil and gas demand is expected to remain a key element of the energy mix for many years based on stated policies, commitments
and announced
pledges to
reduce emissions.
Therefore given
the estimated
useful lives
of the
Group's oil
and gas
portfolio, a
material adverse
change is
not anticipated
to the
carrying value
of the
Group's assets
and liabilities
in the
short-term as
a result
of climate
change and
the transition
to a lower-carbon economy.
Business combinations
Business combinations are accounted for using the acquisition method.
The cost
of an
acquisition is
measured as
the fair
value of
the consideration
given for
the assets
acquired, equity
instruments issued and liabilities incurred
or assumed at the date of completion of
the acquisition. Transaction costs incurred are expensed and
included in administrative expenses. Identifiable assets acquired
and liabilities and contingent liabilities assumed in a business
combination are measured initially
at their
fair values
at the
acquisition date.
The excess
of the
cost of
acquisition over
the fair
value of
the Group's
share of
the identifiable
net assets
acquired is
recorded as
goodwill. If
the cost
of the
acquisition is
less than the Group's
share of the net
assets acquired, the difference is recognised directly in the
consolidated statement of profit or
loss as
a gain
on bargain
purchase.
Goodwill
Capitalisation
Goodwill is initially recognised and measured as set
out above. Following initial recognition, goodwill is measured at
cost less any accumulated impairment losses.
Impairment
Goodwill is tested annually for
impairment and also when circumstances indicate that the carrying
value may be at risk of being impaired. Impairment is determined
for goodwill by assessing the recoverable amount of each CGU or
group of CGUs to which the goodwill relates. If the recoverable amount of a CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of goodwill allocated
to the
unit and
then to
the other
assets of
the unit pro-rata based
on the carrying amount of each asset in the unit. Any impairment
loss is recognised in the consolidated statement of profit or loss.
Impairment losses relating to goodwill cannot be reversed in future
periods. The CGU for the purposes
of the
goodwill test
is the
North Sea,
i.e. the
entire Group
portfolio of
oil and
gas assets
which is
consistent with
the operating
segment view
of the
business.
Interest in joint ventures and
associates
Under IFRS 11, joint arrangements
are those
that convey
joint control
which exists
only when
decisions about
the relevant
activities require the unanimous consent
of the
parties sharing
control. Investments in joint arrangements
are classified
as either
joint operations
or joint
ventures depending on the contractual rights and obligations of each investor. Associates are investments over which the Group has significant influence
but not
control or
joint control,
and generally holds between 20% and 50% of
the voting rights.
The Group's interest in joint operations (e.g. exploration and production arrangements)
are accounted
for by
recognising its
assets (including
its share
of assets
held jointly),
its liabilities
(including its
share of
liabilities incurred jointly),
its revenue
from the
sale of
its share
of the
output arising
from the
joint operation
and its
expenses (including its share of any expenses incurred jointly).
Revenue
The sale of crude oil, gas or condensate represents
a single
performance obligation, being
the sale
of barrels
equivalent on
collection of
a cargo
or on
delivery of
commodity into
an infrastructure. Revenue
is accordingly
recognised for
this performance
obligation when
control over
the corresponding
commodity is
transferred to
the customer.
Revenue is
recognized at
a point
in time
and is
measured based
on the
consideration to
which the
group expects
to be
entitled in
a contract
with a
customer and
excludes amounts
collected for
third parties.
Details of
hedging gains
and losses
presented in
revenue are
discussed in
the hedging
acccounting policy set out below.
3. Material accounting
policies, judgements and estimation uncertainty
continued
Tariff income is recognised as the underlying
commodity is shipped through the pipeline network based on
established tariff rates.
Foreign currency translation
Items included in these consolidated
financial statements are measured using the currency of the primary economic environment in which the Group and its subsidiaries operate (the functional currency).
The consolidated
financial statements are presented in US Dollars, which is the Group's presentation currency
as well
as the
functional currency of the Parent Company and each of its subsidiaries.
In preparing
the financial
statements of
the parent
and its
subsidiaries, trans actions in currencies other than the entity's functional currency
(foreign currencies) are recognised at the rates of exchange prevailing on the dates of the transactions. At each reporting date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items
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. Non-monetary items
that are
measured in
terms of
historical cost
in a foreign currency are not retranslated.
Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange
rates of
monetary assets
and liabilities
denominated in
foreign currencies are recognised in the statement of profit or loss.
Exchange differences are recognised in profit or
loss in the period in which they arise except for:
•
Exchange differences on foreign currency borrowings relating
to assets
under construction for future productive
use, which
are included
in the
cost of
those assets
when they
are regarded
as an
adjustment to
interest costs
on those
foreign currency borrowings;
•
Exchange differences on transactions entered
into to
hedge certain
foreign currency
risks (see
below under
financial instruments/hedge accounting).
Financial instruments
All financial instruments are initially recognised
at fair value on the statement of financial position. Measurement
in subsequent periods is dependent on the classification of the
respective financial instrument.
The Group derecognises
a financial
asset only
when the
contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially
all the
risks and
rewards of
ownership of
the asset
to another
entity. The
Group derecognises financial
liabilities when,
and only
when, the
Group's obligations are discharged, cancelled
or have
expired. The
difference between the carrying amount of the financial asset or financial liability derecognised and the
consideration received/receivable
or paid/payable respectively is recognised in
profit or loss.
IFRS 9 classifications:
Cash and cash equivalents are classified at amortised cost which equates to its fair value. Accounts receivable
and long-term
receivables are
classified and
carried at
amortised cost
less expected
credit losses
as they
have a
business model
of held
to collect
and the
terms of
the financial
instrument meet
the solely
payments of
interest on
principle outstanding. Accounts
payable, accrued
liabilities, certain other long-term liabilities,
and borrowings
are classified
as other
financial liabilities and carried at amortised cost using the effective interest
method. Amortised
cost is
calculated by
taking into
account any
issue costs,
discount or
premium. Contingent consideration
is measured
at fair
value though
profit or
loss. Although
the Group
does not
intend to
trade its
derivative financial instruments,
they are
required to
be carried
at fair
value with
the treatment
of fair
value movements
explained further
below.
Interest-free loans from parents are initially recognised
at fair
value. The
difference between the fair value of the loans and the nominal value is accounted for as a capital contribution
and is
credited to
equity. After
initial recognition, the loans are measured
at amortised cost using implied interest rate of the
notes.
Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability and original issue discounts on long-term debt have been included in the carrying value of the related financial
asset or
liability and
are amortised to consolidated net earnings over
the life of the financial instrument using the effective interest
method.
Impairment of financial
assets
For trade receivables
and accrued
income, the
Group applies
a simplified
approach in
calculating expected credit losses (ECLs). Therefore, the Group does not track changes in credit risk, but instead, recognises any material loss allowance based on lifetime ECLs at each reporting date. For all other financial assets,
the Group
measures the
loss allowance
using 12-month
expected credit
losses unless
there was
a significant
increase in
credit risk
since initial
recognition in
which case
the loss
allowance is
measured using
lifetime expected
credit losses.
In making this assessment whether
the credit
risk increased
significantly since initial recognition, the Group considers both quantitative
and qualitative
information that
is reasonable
and supportable,
including historical experience
and forward-looking information
that is
available without
undue cost
or effort.
The Group
considers that
the credit
risk increased
significantly since initial recognition when the credit rating changes, the debtor has significant financial difficulty
or if
there was
a breach
of contract.
For balances
that are
beyond 30
days overdue
it is
presumed to
be an
indicator of
a significant
increase in
credit risk.
The Group considers a financial asset in default when contractual payments
are 90
days past
due. However,
in certain
cases, the
Group may
also consider
a financial
asset to
be in
default when
internal or
external information indicates
that the Group is unlikely to receive the
outstanding contractual amounts in full before taking into account
any credit enhancements held by the Group.
A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. Financial assets written off may still be subject to enforcement activities
under the
Group's recovery
procedures, taking into account legal advice where appropriate. Any recoveries made are recognised in profit or loss.
Derivative financial instruments
The Group enters into a variety of derivative financial
instruments to
manage its
exposure to
commodity risks,
interest rate
and foreign
exchange rate
risks. These
instruments include: commodity
swaps, collars
and options;
foreign exchange
forward contracts
and collars;
and interest
rate swaps.
Further details
of derivative
financial instruments are disclosed in notes 29 and 30.
Derivatives are recognised initially at fair value
at the date a derivative contract is entered into and are
subsequently remeasured to their fair value at each reporting date.
The resulting gain or loss on remeasurement of derivatives is
recognised in
profit or
loss immediately
unless the
derivative is
designated in
a hedge
relationship 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 financial liability.
Derivatives are
not offset
in the
financial statements unless
the Group
has both
a legally
enforceable right
and intention
to offset.
A derivative
is presented
as a non-current asset
or a non-current liability
if the
remaining maturity of the instrument is more than 12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and
expected to be realised or settled in less than 12 months are presented as current assets or current liabilities.
Hedge accounting
The Group designates certain derivatives as hedging
instruments in respect of commodity risks in cash flow hedges.
At the inception of the hedge relationship,
the Group
documents the
relationship between the hedging instrument
and the
hedged item,
along with
its risk
management objectives and its strategy for undertaking various hedge transactions. 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.
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 aligned 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 in
the same
line as
the hedged
item. If
the Group
expects that
some or
all of
the loss
accumulated in
the cost
of hedging
reserve will
not be
recovered in
the future,
that amount
is immediately
reclassified to
profit or
loss.
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
hedge 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 'other
gains and
losses' line
item.
3. Material accounting policies,
judgements and estimation uncertainty continued
Amounts previously recognised
in other
comprehensive income and accumulated in equity are reclassified to profit or loss in the periods when the hedged item affects profit or loss, in the same revenue line as the recognised hedged item. However, when the hedged forecast transaction
results in
the recognition
of a non-financial asset
or a non-financial liability,
the gains
and losses
previously recognised in other comprehensive
income and
accumulated in
equity are
removed from
equity and
included in
the initial
measurement of
the cost
of the
non-financial asset or non-financial liability.
This transfer
does not
affect other
comprehensive income. Furthermore,
if the
Group expects
that some
or all
of the
loss accumulated
in the
cash flow
hedge reserve
will not
be recovered
in the
future, that
amount is
immediately reclassified to profit or loss.
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.
If a hedge of a transaction related
item is
discontinued part
way through
the life
of the
hedge (e.g.
due to
early termination
of the
swap, hedging
resets), but
the hedged
item is
still expected
to occur,
the amounts
deferred in
equity would
remain in
equity until
the earlier
of: (i)
the hedged
transaction occurring; or (ii) expectation that the amount deferred in equity will not be recovered in the future periods.
Note 29 and note 30 set out details of the fair
values of the derivative instruments used for hedging purposes and
movements in the hedging reserve in equity are detailed in note
29.
Contingent and deferred
consideration
Contingent consideration in relation to a business combination or asset acquisition
is accounted
for as
a financial
liability and
measured at
fair value
at the
date of
acquisition with
any subsequent
remeasurements recognised in profit or loss in accordance with IFRS 9. These fair values are generally based on risk-adjusted future cash flows discounted using appropriate
discount rates.
Changes in
fair value
of the
contingent consideration that
qualify as
measurement period adjustments are
adjusted retrospectively, with corresponding adjustments against
goodwill. Measurement period adjustments are adjustments that arise
from additional information obtained during the 'measurement
period' (which cannot exceed one year from the acquisition date)
about facts
and circumstances
that existed
at the
acquisition date.
The subsequent accounting
for changes
in the
fair value
of the
contingent consideration that
do not
qualify as
measurement period adjustments
depends on
how the
contingent consideration is classified. Contingent
consideration that is classified as equity is not remeasured at subsequent reporting dates and its subsequent settlement
is accounted
for within
equity. Other
contingent consideration is remeasured to fair value at subsequent reporting dates with changes in fair value recognised in profit or loss.
Deferred consideration is measured at amortised cost
because the amount payable in the future is fixed.
Settlement of contingent consideration is recorded as investing outflows
in the
cash flow
statement to
the extent
that cumulative
amounts paid
do not
exceed the
amount recognised
at the
date of
acquisition, with
any excess
recorded as
an operating
cash outflow.
Settlement of
deferred consideration is recorded as either an investing or financing outflow
in the
cash flow
statement, depending on the substance of the arrangement at inception. Key considerations
in forming this judgment will include the extent of inferred financing
costs included
in the
overall consideration arrangements
at acquisition,
the period
of time
over which
the payments
are made,
the rationale
for agreeing
to defer
elements of
the consideration
and the
general level
of funding
resources available to the Group at the time of acquisition.
Cash and cash equivalents
For the purpose of the statement of cash flow, cash and cash equivalents include investments
with an
original maturity
of three
months or
less. In
the statement
of financial
position, cash
and bank
balances comprise
cash (i.e.
cash on
hand and
demand deposits)
and cash
equivalents. Cash
equivalents are
short-term (generally with original maturity
of three
months or
less), highly-liquid investments
that are
readily convertible to a known amount of cash and which are subject to an insignificant risk of changes in value. Cash equivalents are held for the purpose of meeting short-term cash commitments rather
than for
investment or
other purposes.
Inventories - hydrocarbon and materials
Inventories of materials 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 determined on the first-in, first-out method.
Current hydrocarbon inventories
are stated
at net
realisable value,
which is
based on
estimated selling
price less
any further
costs expected
to be
incurred to completion and disposal/sale. Non-current oil and
gas inventories are stated at historic cost. Provision is made for
obsolete, slow-moving and defective items where appropriate.
Lifting or offtake arrangements
Lifting or offtake arrangements for oil and gas produced in certain of the Group's oil and gas properties are such that each participant may not receive and sell its precise share of the overall production
in each
period. The
resulting imbalance between cumulative
entitlement and cumulative volume sold is an 'underlift' included
within inventories, and 'overlift' is included within trade and
other payables in the statement of financial position. Both are
stated at net realisable value. Movements
during an accounting
period are adjusted through cost of sales in the consolidated
statement of profit or loss.
Exploration and evaluation assets
Oil and gas expenditure - exploration and evaluation (E&E)
assets
Geological and geophysical costs and costs incurred pre-licence are expensed as incurred. Costs directly associated
with an
exploration well
are initially
capitalised as
an intangible
asset until
the drilling
of the
well is
complete and
the results
have been
evaluated. These
costs include
employee remuneration, materials
and fuel
used, freight
costs and
payments made
to contractors.
If potentially
commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal
activity, are
likely to
be capable
of commercial
development, the
costs continue
to be
carried as
an asset.
If it
is determined
that development
will not
occur, that
is, the
efforts are
not successful,
then the
costs are
expensed.
Costs directly associated with appraisal activity
undertaken to determine the size, characteristics and commercial
potential of a reservoir following the initial discovery of
hydrocarbons, including the costs of appraisal
wells where hydrocarbons
were not
found, are
initially capitalised as an intangible asset. Upon external approval
for development
and recognition
of proved
or sanctioned
probable reserves, the relevant expenditure
is first
assessed for
impairment and,
if required,
an impairment
loss is
recognised. The
remaining balance
is then
transferred to
development and
production (D&P) assets.
If development
is not
approved and
no further
activity is
expected to
occur, then
the costs are expensed.
The determination of whether potentially
economic oil
and natural
gas reserves
have been
discovered by
an exploration
well is
usually made
within one
year of
well completion,
but can
take longer,
depending on
the complexity
of the geological
structure. Exploration wells that discover potentially economic
quantities of oil and natural gas in areas where major capital
expenditure (e.g. an offshore platform or a pipeline) would be
required before production could begin and
where the
economic viability of that major capital expenditure
depends on
the successful
completion of
further exploitation or appraisal work in the area remain capitalised on the balance sheet as long as such work is under way or firmly planned.
Property, plant and equipment
Oil and gas expenditure - D&P
assets
Capitalisation
Costs of bringing a field into production, including the cost of facilities, wells
and subsea
equipment, direct
costs including
staff costs
together with
E&E assets
reclassified in
accordance with
the above
policy, are
apitalized as
a D&P
asset. Normally
each individual
field development
will form
an individual
D&P asset
but there
may be
cases, such
as phased
developments, or
multiple fields
around a
single production
facility when
fields are
grouped together
to form a single
D&P asset.
Depreciation
All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation
is calculated
on a unit of production basis based on the proved and probable reserves of the asset generally on a field-by-field basis. Any re-assessment of reserves affects the depreciation rate prospectively.
Significant items
of plant
and equipment
will normally
be fully
depreciated over
the life
of the
field. However,
these items
are assessed
to consider
if their
useful lives
differ from
the expected
life of
the D&P
asset.
Non-oil and natural gas
operations
Non-oil and gas assets
are initially recorded
at cost and depreciated over their estimated useful lives on a
straight-line basis as follows-
Buildings
|
10 years
|
Computer and office equipment
|
3 years
|
Furniture and fittings
|
5 years
|
3. Material accounting policies,
judgements and estimation uncertainty continued
Impairment
For impairment review
purposes the
Group's oil
and gas
assets are
aggregated into
CGUs typically
on a field-by-field basis
for development
and production
assets in
accordance with
IAS 36,
and on
a North
Sea segment
basis for
exploration and
evaluation assets
in accordance
with IFRS
6. A review is carried out at each reporting date for any indicators that the carrying value of the Group's assets may be impaired or previously impaired assets (excluding goodwill)
where a
reversal of
a previous
impairment may
arise. Such
reviews are
carried out
on a field-by-field basis
for both
development and
production assets
and exploration
and evaluation
assets. For
assets where
there are
such indicators,
an impairment
test is
carried out
on the
CGU. The
impairment test
involves comparing the carrying value with the recoverable value
of an
asset. The
recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to the recoverable amount. The resulting impairment
losses are
written off
to the
consolidated statement of profit or loss. Previously impaired
assets (excluding goodwill) are reviewed for possible reversal of
previous impairment at each reporting date. The maximum possible
reversal is capped at the net book value had the asset not been impaired in the past. Where an exploration and evaluation licence
is relinquished,
amounts capitalised in respect of the licence are witten off to profit or loss in the period in which the licence is relinquished.
Borrowing costs
Borrowing costs directly attributable to the
acquisition, construction or production of qualifying assets, which
are assets that necessarily take a substantial period of time to
get ready for their intended use or sale, are added to the cost of
those assets until such time as the assets are substantially
ready for
their intended
use or
sale. All
other borrowing
costs are
expensed as
incurred. Borrowing costs directly attributable
to E&E
assets are
not capitalised
and are
expensed directly
to profit or loss when incurred.
Decommissioning
liabilities
The Group records the present value of legal obligations
associated with
the retirement
of long-term
tangible assets,
such as
producing well
sites and
processing plants, in the period in which they are incurred with a corresponding increase in the carrying amount of the related long-term asset. Liabilities for decommissioning are
recognised when
the Group
has an
obligation to
plug and
abandon a
well, dismantle
and remove
a facility
or an
item of
plant and
restore the
site on
which it
is located,
and when
a reliable
estimate can
be made.
Where the
obligation exists
for a
new facility
or well,
such as
oil and
gas production
or transportation
facilities, the
obligation generally arises when the asset is installed or the ground/environment
is disturbed
at the
field location.
In subsequent
periods, the
asset is
adjusted for
any changes
in the
estimated amount
or timing
of the
settlement of
the obligations.
The amount
recognised is
the present
value of
the estimated
future expenditure determined
in accordance
with local
conditions and
requirements. The
carrying amounts
of the
associated decommissioning assets
are depleted
using the
unit of
production method, in accordance with the depreciation policy for development and production assets.
Actual costs
to retire
tangible assets
are deducted
from the
liability as
incurred. The
unwinding of
discount in
the net
present value
of the
total expected
cost is treated as an interest expense. Changes
in the estimates are reflected prospectively over the remaining
life of the field.
Where some or all of the expenditure required to
settle a provision is expected to be reimbursed by another party, a
reimbursement asset is recognised when, and only when, it is
virtually certain that reimbursement will be received if the
entity settles
the obligation.
The amount
recognised for
the reimbursement
may not
exceed the
amount of
the provision.
Taxation
Current tax
Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted
by the
reporting date.
Taxable profit
differs from
net profit,
as reported
in the
consolidated statement of profit or loss, because it excludes items of income or expense that are taxable or deductible in other accounting periods
and it further excludes items of income or
expenses that are never taxable or deductible.
Deferred tax
Deferred tax is recognised using the liability method, providing
for temporary
differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred
tax is
measured at
the tax
rates that
are expected
to be
applied to
the temporary
differences when
they reverse,
based on
the laws
that have
been enacted
or substantively
enacted at
each balance
sheet date.
Deferred tax
liabilities are
not recognised
if they
arise from
the initial
recognition of
goodwill and
deferred tax
is not
accounted for
if it
arises from
initial recognition of an asset or liability in a transaction other
than business
combination that
at the
time of
the transaction
affects neither
accounting nor
taxable profit
or loss.
Deferred tax
assets are
recognised only
to the
extent that
it is
probable that
future taxable
profits will
be available
against which
the temporary
differences can
be utilised.
The carrying
amount of
deferred tax assets is reviewed at each balance sheet date and all
available evidence is considered in evaluating the recoverability
of these deferred tax assets. Deferred tax assets and liabilities
are offset where there is a legally enforceable right to offset current tax assets and liabilities relating to taxes levied by the same taxation authority on either the same taxable entity or different taxable
entities where
there is
an intention
to settle
the balances
on a net basis.
Deferred Petroleum Revenue
Tax (PRT)
assets are
recognised where
PRT relief
on future
decommissioning costs is probable.
Leases
The Group assesses at contract inception all arrangements to determine whether
it is,
or contains,
a lease.
That is,
if the
contract conveys
the right
to control
the use
of an
identified asset
for a
period of
time in
exchange for
consideration. The Group is not a lessor in any transactions, it is only a lessee. The Group recognises a right-of-use asset
and a
corresponding lease liability with respect to all lease arrangements
in which
it is
the lessee.
The Group
has elected
to apply
Paragraph 6
of IFRS
16 to
short-term leases
(defined as
leases with
a lease
term of
12 months
or less)
and leases
of low-value
assets (such
as tablets
and personal
computers, small
items of
office furniture
and telephones). Lease
payments associated with
these leases are expensed over the relevant lease
term.
Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses,
and adjusted
for any
remeasurement of
lease liabilities. The cost of right-of-use assets
includes the
amount of
lease liabilities
recognised, initial direct costs incurred, and lease payments made at or before the commencement date
less any
lease incentives
received. The
right-of-use asset is depreciated over the useful life of the asset.
The Group's right-of-use assets are included in
property, plant and equipment (note 15).
At the commencement date of the lease, the Group recognises lease liabilities measured
at the
present value
of lease
payments to
be made
over the
lease term.
In calculating
the present
value of
lease payments,
the Group
uses its
incremental borrowing rate at the lease commencement
date because
the interest
rate implicit
in the
lease is
generally not
readily determinable. After
the commencement
date, the
amount of
lease liabilities
is increased
to reflect
the accretion
of interest
and reduced
for the
lease payments
made. In
addition, the
carrying amount
of lease
liabilities is
remeasured if
there is
a modification,
a change
in the
lease term,
a change
in the
lease payments
(e.g. changes
to future
payments resulting from a change in an index or rate used to
determine such lease payments) or a change in the assessment of an option to purchase the underlying asset.
Maintenance expenditure
Expenditure on major maintenance refits or repairs
is capitalised where it enhances the life or performance of an
asset above its originally assessed standard of performance,
replaces an asset or part of an asset which was separately
depreciated and
which is
then written
off, or
restores the
economic benefits
of an
asset which
has been
fully depreciated. All other maintenance
expenditure is
charged to
the statement
of profit
or loss
as incurred.
Share-based payments
The Group issues equity-settled share-based
payments to
certain employees. Equity-settled
share-based payments are measured at fair value at the date of grant. The fair value is expensed over the vesting term either on a straight-line basis or as specified in
the vesting terms, based on the Group's estimate
of shares that will eventually vest and is adjusted for the effects of non-market-based vesting
conditions.
Fair value is measured by using a Black-Scholes or other appropriate
valuation model.
The expected
life used
in the
model is
adjusted based
on management's
best estimate
for the
effects of
non-transferability, exercise restrictions
and behavioural considerations.
Retirement benefit costs
The Group operates a defined contribution pension
scheme and
payments into
this plan
are charged
as an
expense as
they fall
due. There
is no
further obligation to pay contributions
into the
plan once
the contributions
specified in
the plan rules have been paid.
Short-term employee benefits
A charge or liability is recognised for benefits accruing
to employees
in respect
of salaries,
bonuses, annual
leave and
sick leave
in the
period the
related service
is rendered
at the
undiscounted amount of the benefits expected to be paid for that service. Charges or liabilities recognised in respect of short-term employee
benefits are
measured at
the undiscounted
amount of
the benefits
expected to
be paid
in exchange
for the
related service.
Non-GAAP measures
In measuring the Group's adjusted operating performance,
additional financial measures
derived from
the reported
results have
been used
by management
in order
to eliminate
factors which
distort year-on-year comparisons.
The Group's
adjusted performance is used to explain year-on-year
changes when
the effect
of certain
items is
significant, including material
impairment charges or reversals, non-cash
bargain purchase
credits, the
tax effect
of these
items where applicable
and non-cash deferred tax charges on the initial application of
EPL.
Adjusted EBITDAX, adjusted
net income,
adjusted EPS,
unit operating
expenditure, leverage ratio, adjusted net debt and certain other reported metrics are non-GAAP measures that are not specifically defined
under IFRS
or other
generally accepted accounting
principles. Further details are set out on pages 76 to 78.
3. Material accounting policies,
judgements and estimation uncertainty continued
Changes in
accounting pronouncements
The Group has adopted all new and amended IFRS Standards effective
in the
consolidated financial statements
for the
period 1
January 2022
to 31
December 2023
including IFRS
17 Insurance
Contracts.
There was
no impact
of this
or of any of the amendments to existing standards
and interpretations which were effective from 1 January
2023.
New and revised IFRS Standards in
issue but not yet effective
At the date of authorisation of these consolidated
financial statements, the Group has not applied the following
revisions to IFRS Standards that have been issued but are not yet
effective.
Amendments to IFRS 10 and IAS
28
|
Sale or Contribution of Assets between an Investor and its
Associate or Joint
Venture
|
Amendments to IAS 1
|
Classification of Liabilities as Current or Non-current
|
Amendments to IAS 1
|
Non-current liabilities with Covenants
|
Amendments to IAS 7 and IFRS
7
|
Supplier Finance Arrangements
|
Amendments to IFRS 16
|
Lease Liability in a Sale and Leaseback
|
Amendments to IAS 21
|
The Effects
of Changes
in Foreign
Exchange Rates:
Lack of
Exchangeability
|
The Company does not expect that the adoption of the
amendments listed above will have a material impact on the
consolidated financial statements of the Group in future
periods.
Critical judgements and key
sources of estimation uncertainties 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.
Decommissioning
provision estimates
Amounts used in recording a provision for decommissioning are
estimates based
on current
legal and
constructive requirements and current technology
and price
levels for
the removal
of facilities
and plugging
and abandoning
of wells.
Due to
changes in
relation to
these items,
the future
actual cash
outflows in
relation to
decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements,
technology and
price levels,
the carrying amounts of decommissioning
provisions are
reviewed on
a regular
basis. The
effects of
changes in
estimates do
not give
rise to
prior year
adjustments and
are dealt
with prospectively. For
operated assets,
cost estimates
are based on management's assessment of work programmes (including
durations) and supply chain conditions including, amongst other
factors, applicable vessel and rig rates and durations. For
non-operated assets, cost estimates are arrived
at by management's review
of the basis of estimates as provided by the
respective operators.
While the Group uses its best estimates and judgement, actual results could differ from these estimates. Expected
timing of
expenditure can
also change,
for example
in response
to changes
in laws
and regulations
or their
interpretation, and/or due to changes in commodity prices. The payment dates are uncertain and depend on the production lives of the respective fields.
Management does
not expect
any reasonable
change in
the expected
timing of
decommissioning to have
a material effect on the decommissioning provisions, assuming cash
flows remain unchanged. Decommissioning costs are expected to be
incurred over the next 40 years. A nominal discount rate of 4.60%
(2022: 4.25%),
based on the average risk-free
rate over
the second
half of
2023, is
used to
discount the
estimated costs.
The inflation
rate applied
to estimated
costs is
2.0% (2022:
2.0%). Given
the long-term
nature of
the Group's
decommissioning liabilities and the historic compounded inflation
rates in
the industry,
management do
not believe
that the
current short-term inflationary
pressures will
have a
material impact
on the
decommissioning liabilities of the Group. A reduction or an increase in this discount rate of 1% would increase or reduce the decommissioning liabilities
by approximately
$223 million
or $188
million respectively (2022:
$218 million
or $201
million respectively), and
is not
expected to
have a
material impact
on the
corresponding decommissioning reimbursement
asset. For
further details
regarding the
estimated value,
inputs and
assumptions refer
to note
23. Given
the large
number of
variables involved, management
consider that
it is
not practical
to provide
sensitivities for
the various
other individual
assumptions.
Contingent consideration
Liabilities for contingent consideration have been
recognised on certain business combinations, which are measured at
fair value at acquisition and remeasured at fair value through
profit and loss at each reporting date.
The amounts of contingent consideration
ultimately payable depend on several factors, including
the progress
of certain
of the
oil and
gas properties
acquired and
the achievement
of certain
production and
commodity price
thresholds. Management has estimated the fair value as the aggregate value of each element of the contingent consideration in each case using an appropriate valuation
technique, taking
into account
the likelihood
of occurrence
of each
contingent event
and the
net present
value of
the amount
potentially payable. Where applicable, risking
assumptions applied in the measurement of contingent consideration were
consistent with
those applied
in the
fair valuation
of the
related oil and
gas properties.
A 20% decrease in
probability of payment, with all other
assumptions held constant, would result in a decrease in
contingent consideration of
$97.1 million (2022:
$87.1 million). Whereas a 20% increase in probability of
payment, with all other
assumptions held constant, would result in an increase in
contingent consideration of $84.1 million (2022: $83.6
million).
Other areas of estimation
The key assumptions concerning the future, and other sources of estimation uncertainty at the reporting period, but are not expected to cause a material adjustment
to the
carrying amounts
of assets
and liabilities
within the
next financial year, are discussed
below:
Taxation estimates
The Group's operations
are subject
to a number of specific tax rules which apply to exploration, development
and production
companies such
as the
Energy Profits
Levy at
35%, ring-fenced
Corporation Tax
at 30%,
the Supplementary
Charge of
10% and
the application
of investment
allowances. In
addition, the
tax provision
is prepared
before the
relevant companies have filed their tax returns with the relevant tax authorities and, significantly, before
these have
been agreed.
As a result of these factors, the tax provision process
necessarily involves the use of a number of judgements and estimates including those required in calculating the effective tax rate. The Group recognises deferred tax assets on unused tax losses where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the likelihood of future taxable profits and the amount of deferred tax that can be recognised. Further
details regarding
the estimated
value and
related inputs
are set
out in
note 27.
The Group's deferred tax assets are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised, including
as a result of Group re-organisations
and asset
transfers. In
accordance with
IAS 12
Income Taxes,
the Group
assesses the
recoverability of
its deferred
tax assets
at each
period end.
Consistent with
the impairment
sensitivity described above, as at 31 December 2023, a 20% reduction in future revenues, with all other assumptions held constant, would eliminate current
headroom and
result in
a deferred
tax asset
derecognition of
$304 million
(2022: $24
million). It
should be
noted that
mitigating actions are considered to be available to materially offset this impact. An increase in future revenues would result in no additional deferred
tax asset
recognition on
the basis
that deferred
tax assets
are already
recognised in
full. The
$304 million
(2022: $24
million) de-recognition assumes
that cash
flows are
equivalent to
taxable profits
and that
any reorganisation required
to utilise
certain deferred
tax assets
does not
result in
a displacement
of other
balances.
Estimates in oil and gas reserves
and contingent resources
The Group's estimates
of oil
and gas
reserves and
contingent resources, and the associated production forecasts,
are used
in the
impairment testing of property plant and equipment and goodwill, in the measurement of depletion and decommissioning provisions,
the measurement
of certain
elements of
contingent consideration, the
going concern
assessment, the
viability assessment and in the determination of whether deferred tax assets are recoverable. The business
of the Group is to enhance hydrocarbon recovery and extend the
useful lives of mature and underdeveloped assets and associated
infrastructure in a profitable and responsible manner. Estimates of
oil and gas reserves and contingent resources
require critical
judgement. Factors such as the availability of geological and engineering data,
reservoir performance data,
drilling of
new wells
and estimates
of future
oil and
gas prices
all impact
on the
determination of
the Group's
estimates of
its oil
and gas
reserves which
could result
in different
future production
profiles affecting prospectively
the discounted
cash flows
used in
impairment testing.
The Group's estimates
of reserves
and resource
volumes used
for accounting
purposes are
built up
from historically-matched models
for operated
assets and
principally from
operators' estimates for non-operated assets.
A review
process is
undertaken to
compare the
results of
the Group's
internal estimates to those of an independent consultant to understand any differences in underlying assumptions
to ensure
there are
no material
unreconciled differences between
the estimates.
For the purposes of depletion and decommissioning
estimates, the
Group uses
proved and
probable reserves; and for the purposes of the impairment tests performed and deferred tax asset recoverability, the
Group considers
the same
proved and
probable reserves
as well
as risked
resource volumes.
These risking
adjustments are
reflective of
management's assessment of technical and commercial factors
that reflect
the value
considerations of
a market
participant. Changes in estimates of oil and gas reserves and resources resulting in different future production profiles
will affect
the discounted
cash flows
used in
impairment testing, the anticipated date of decommissioning,
the depletion
charges in
accordance with
the unit
of production
method and
the recoverability of
deferred tax
assets. The
sensitivity of
the Group's
impairment tests
and deferred
tax recoverability assessments
to key
sources of
estimation uncertainty including
reserves and
resources is
discussed below.
3. Material accounting
policies, judgements and estimation uncertainty
continued
Estimates in impairment of oil and
gas assets and goodwill
Determination of whether the Group's oil and gas assets (note 15) or goodwill (note 18) have suffered any impairment requires an estimation of the recoverable amount of the CGU to which oil and gas assets and goodwill have been allocated. Projected
future cash
flows are
used to
determine a
fair value
less cost
to sell
to establish
the recoverable
amount. Key
assumptions and
estimates in
the impairment
models relate
to: commodity
prices that
are based
on internal view of forward curve prices
that are considered to be a best estimate of what a market
participant would use; discount rates which reflect management's
estimate of a market participant post-tax weighted average cost of
capital; and oil
and gas
reserves and
resources on
a risked
basis as
described above.
Management's estimates of a market participant's view
of pricing
and discount
rates are
supported by
an independent
consultant.
The sensitivity of the Group's carrying amounts to these assumptions is illustrated by the impairments and reversals disclosed in note 19, and by the sensitivity disclosures in note 19. Sensitivity disclosures
include, in
particular, the impact of a 20% reduction
in forecast revenues.
Critical accounting judgements
The following are the critical judgements, apart
from those
involving estimation (which
are presented
separately above), that the Directors have made in applying the Group's accounting policies
and that
have the
most significant
effect on
the amounts
recognised in
the financial
statements.
Cambo field carrying value
Management has reviewed the carrying value of the Cambo field of $391 million and has concluded that due to the recent licence extension
to 31
March 2026
and the
detailed plans
in place
for final
investment decision (FID), there are currently no indicators of impairment. The Group is actively engaging
with potential
farm-in partners
to secure
an aligned
joint venture
partnership that
would progress
the project
towards FID
and assist
in obtaining
the additional
funding required
for the
project. The
Group is
also mindful
that the
outcome of
the 2024
General Election
could have
implications for
the project
as well
as the
wider fiscal
uncertainties on
oil and
gas investment
in general.
Details of
contingent consideration in respect of Cambo are
set out in note 17 and note 25.
Notes to the consolidated financial
statements continued
4. Segmental reporting
The Group operates a single class
of business being oil and gas exploration, development and
production and related activities in a single geographical area,
presently being the North Sea. The Group's segmental reporting
structure remained in place for all
periods presented and is consistent with the way in which the
Group's activities are reported to the Board and Chief Decision
Making Officer. The Group's activities are considered to be an
individual operating segment due to the nature of the Group's
operations being consistent, and such operations existing in a
single geographical region that is covered by the same
regulations.
5. Revenue
|
2023
US$'000
|
2022
US$'000
|
Oil sales
|
1,329,751
|
1,692,697
|
Gas sales
|
658,659
|
1,348,212
|
Condensate sales
|
48,789
|
75,445
|
Other income
|
32,341
|
40,617
|
Realised losses on oil derivative
contracts
|
(31,676)
|
(211,636)
|
Put premiums on oil derivative instruments
|
(11,850)
|
(14,629)
|
Realised gains/(losses) on
gas derivative
contracts
|
297,387
|
(289,877)
|
Put premiums on gas derivative
instruments
|
(3,590)
|
(42,347)
|
|
2,319,811
|
2,598,482
|
The majority of payment terms are
on a specified monthly date, as detailed in the initial contract.
Otherwise, payment is due within 30 days of the invoice date. No
significant judgements have been made in determining the timing
of satisfaction
of performance
obligations, the
transactions price and the amounts allocated to performance obligations.
Other income
relates to
tariff income
receivable in
the year.
Revenue from two customers
exceeded 10% of the Group's consolidated revenue arising from
hydrocarbon sales for the year ended 31 December 2023, representing
$1,296 million and $436 million of revenue respectively
(2022: one customer representing $2,436
million of
revenue).
Revenue from contracts with
customers derives largely from customers within a single
geographical region, being the United Kingdom. Revenue from
contracts with customers out with the United Kingdom is immaterial
and is therefore not disclosed separately.
6. Cost of sales
|
2023
|
2022
|
US$'000
|
US$'000
|
Movement in oil and gas inventory (including underlift/overlift)
|
20,582
|
(130,295)
|
Operating costs of
hydrocarbon activities
|
(576,660)
|
(547,795)
|
Materials inventory provision
|
(16,268)
|
-
|
Royalties
|
(4,364)
|
(11,287)
|
Depreciation on right-of-use assets
(note 15)
|
(42,648)
|
(37,438)
|
Depletion, depreciation
and amortisation (note
15)
|
(697,652)
|
(625,509)
|
|
(1,317,010)
|
(1,352,324)
|
Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds
a 100%
interest in the
Stella and
Harrier fields.
|
|
|
7. Administrative expenses
|
|
|
2023
US$'000
|
2022
US$'000
|
Administrative expenses excluding
transaction costs
|
(34,259)
|
(41,762)
|
Transaction costs
|
-
|
(46,089)
|
|
(34,259)
|
(87,851)
|
Transactions costs in 2022 relate to the acquisitions of Marubeni Oil & Gas Limited (MOGL), Summit Exploration
and Production
Limited (Summit)
and Siccar
Point Energy
entities, and
costs incurred
in connection
to the
IPO. Further details on
the acquisitions can be found in note 17.
The total employee benefit expenses which are either capitalised
or included
in cost
of sales,
pre-licence exploration and evaluation expenses
and administrative expenses
are noted
below.
Employee benefit expenses
|
2023
US$'000
|
2022
US$'000
|
Wages and salaries
|
(104,027)
|
(81,017)
|
Share-based payment charges (note 32)
|
(16,369)
|
(14,069)
|
Social security costs
|
(12,290)
|
(9,902)
|
Pension costs
|
(9,997)
|
(8,298)
|
|
(142,683)
|
(113,286)
|
Directors' emoluments in aggregate
were $13.4 million (2022: $18.1 million). The average number of employees during each year was as
follows:
|
|
|
|
2023
|
2022
|
Onshore and administrative
|
316
|
268
|
Offshore
|
283
|
249
|
|
599
|
517
|
The increase in average employee numbers in 2023 reflects the full-year impact of acquisitions made
in 2022
and the
conversion of
a number
of contractor
roles to
staff positions.
|
|
|
7. Administrative expenses
continued
|
2023
|
2022
|
Audit fees
|
US$'000
|
US$'000
|
Fees payable to the Company's
auditor for audit
of the Company's financial statements
|
1,286
|
1,095
|
Audit of the Company's subsidiaries pursuant to legislation
|
326
|
324
|
Non-audit fees provided by the auditors
|
205
|
4,707
|
|
1,817
|
6,126
|
Non-audit fees provided by the auditors for the year ended 31 December 2023 comprise audit-related
assurance services of $205k (2022: $170k), other assurance services
of $nil
(2022: $990k)
and other
non-audit services of $nil (2022: $3,547k), with the
latter two captions in 2022 relating to reporting accountant
workstreams in relation to the IPO.
8. Other gains and losses
|
2023
|
2022
|
US$'000
|
US$'000
|
Gain/(loss) on financial instruments (note
29)
|
43,059
|
(278)
|
Fair value losses on contingent
consideration (note 25)
|
(8,008)
|
(4,295)
|
Remeasurements of decommissioning
reimbursement receivables
|
5,645
|
-
|
Net foreign exchange
|
(1,673)
|
(4,856)
|
Settlement of historic claim relating to
an acquisition
|
50,068
|
-
|
|
89,091
|
(9,429)
|
On 12 February 2023, the Group reached agreement on the settlement of a historic claim relating to an acquisition. Under the terms of the agreement the Group received $50.1 million.
|
|
|
9. Finance costs and finance income
|
2023
|
2022
|
|
US$'000
|
US$'000
|
Loan interest and
charges
|
(47,494)
|
(58,317)
|
Senior notes interest
|
(58,377)
|
(61,537)
|
Loan fee amortisation
|
(4,508)
|
(6,418)
|
Interest on lease liabilities (note
24)
|
(3,183)
|
(3,852)
|
Interest on related-party loan
(note 31)
|
-
|
(17,924)
|
Accretion
|
(76,162)
|
(56,511)
|
Realised gains on interest derivative
contracts (note 29)
|
-
|
851
|
Total finance costs
|
(189,724)
|
(203,708)
|
|
|
|
Interest income
|
5,688
|
695
|
There was no interest capitalised
into qualifying assets in either the year to 31 December 2023 or
the year to 31 December 2022.
|
|
|
10. Earnings per share
The calculation of basic earnings per share is based on the profit after tax and the weighted average number of ordinary shares in issue during the year. Basic and diluted earnings per share are calculated as follows:
|
2023
US$'000
|
2022
US$'000
|
Earnings
for the
year:
|
|
|
Earnings for the purpose of basic and diluted earnings per
share
|
215,635
|
1,031,532
|
Number of shares
(million)
|
|
|
Weighted average number of ordinary
shares for the purpose of basic earnings per
share1
|
1,006.7
|
1,005.2
|
Dilutive potential ordinary shares
|
12.7
|
5.0
|
Weighted average number of ordinary
shares for the purpose of diluted earnings per
share
|
1,019.4
|
1,010.2
|
Earnings
per share
(cents)
|
|
|
Basic
|
21.4
|
102.6
|
Diluted
|
21.2
|
102.1
|
11. Trade and other receivables
|
|
|
Current
|
2023
US$'000
|
2022
US$'000
|
Trade receivables
|
19,968
|
31,906
|
Other receivables
|
24,369
|
14,210
|
Joint operations receivables
|
91,960
|
99,800
|
Accrued income
|
197,993
|
214,078
|
|
334,290
|
359,994
|
Materially all trade and other
receivables, including receivables from joint operations are not
overdue by more than 90 days. The credit risk associated with trade
receivables, accrued income and other receivables is considered to
be insignificant. No ECL has been
recognised in the current or prior year.
11. Trade and other receivables
continued
|
|
Non-current
|
2023
US$'000
|
2022
US$'000
|
Decommissioning
reimbursements
|
165,064
|
162,710
|
Current
|
2023
US$'000
|
2022
US$'000
|
Decommissioning
reimbursements
|
30,417
|
38,115
|
Movements on decommissiong
reimbursements were as follows:
|
|
|
|
2023
US$'000
|
2022
US$'000
|
At 1 January
|
200,825
|
246,824
|
Accretion
|
7,536
|
5,946
|
Reimbursements received
|
(22,101)
|
(23,418)
|
Change in reimbursement estimates
|
9,221
|
(28,527)
|
At 31 December
|
195,481
|
200,825
|
The decommissioning reimbursements
represent the equal and opposite of decommissioning liabilities
(note 23), net of tax, associated with the Heather and Strathspey
fields and relates to a contractual agreement as part of
the CNSL acquisition. As part of
the terms of the CNSL acquisition, Chevron have the obligation to
provide the security and remain financially responsible for the
decommissioning obligations of CNSL in relation to these
interests. The Group pays the liabilities
in respect of Heather and Strathspey and then receives full
reimbursement from Chevron.
As these payments are virtually
certain they have been accounted for under IAS 37 as a
reimbursement asset.
12. Prepaid expenses and decommissioning
securities
Current
|
2023
US$'000
|
2022
US$'000
|
Prepayments
|
34,355
|
7,415
|
Decommissioning
securities
|
3,323
|
1,640
|
|
37,678
|
9,055
|
13. Inventories
|
|
Current
|
2023
US$'000
|
2022
US$'000
|
Hydrocarbon underlift
|
60,427
|
87,563
|
Materials inventories
|
125,674
|
124,755
|
Provision for obsolete materials
inventory
|
(35,605)
|
(35,437)
|
|
150,496
|
176,881
|
14. Exploration and evaluation
assets
|
|
|
|
|
US$'000
|
At 1 January 2022
|
|
116,355
|
Additions
|
|
42,168
|
Acquisitions (note 17)
|
|
706,558
|
Transfers to development and production
assets (note 15)
|
|
(75,005)
|
Write offs/relinquishments
|
|
(14,303)
|
At 31 December 2022 and 1 January 2023
|
|
775,773
|
Additions
|
|
165,516
|
Transfers to right-of-use operating assets and development and production assets
(note 15)
|
|
(379,301)
|
Write offs/relinquishments
|
|
(13,634)
|
At 31 December 2023
|
|
548,354
|
Following completion of
geotechnical evaluation activity, certain North Sea licences were
declared unsuccessful and certain prospects were declared
non-commercial. This resulted in the carrying value of these
licences being fully written off to $nil
with $13.6 million being expensed in the year to 31 December 2023
(2022: $14.3 million).
The transfers from exploration and
evaluation assets to development and production assets in 2023
relates to the Rosebank development. Transfers in 2022 related to
the Abigail and Jade South wells. Included within additions in the year is equity acquired in the Cambo and Fotla developments
acquired from
Shell U.K.
Limited and
Spirit Energy
Resources Limited
respectively.
The write offs/relinquishments
includes $nil
(2022: $5.3
million) impairment relating
to decommissioning revisions.
The principal component of
exploration and evaluation assets at 31 December 2023 is the Cambo
field with a carrying value of $391 million (2022: Cambo $364
million and Rosebank $315 million) which formed part of the
Siccar acquisition (see note 17).
15. Property, plant and equipment
|
|
|
Right-of-use operating assets
|
Development and production
assets
|
Other fixed assets
|
Total
|
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
Cost
|
|
|
|
|
At 1
January 2022
|
9,210
|
5,838,178
|
40,293
|
5,887,681
|
Additions
|
89,717
|
362,844
|
5,619
|
458,180
|
Acquisitions (note 17)
|
-
|
1,115,023
|
-
|
1,115,023
|
Transfers from exploration
and evaluation assets
(note 14)
|
-
|
75,005
|
-
|
75,005
|
Change in
decommissioning estimates (note
23)
|
-
|
(278,398)
|
-
|
(278,398)
|
At 31 December 2022 and 1 January 2023
|
98,927
|
7,112,652
|
45,912
|
7,257,491
|
Additions
|
26,468
|
358,361
|
1,728
|
386,557
|
Transfers from exploration
and evaluation assets
(note 14)
|
30,774
|
348,527
|
-
|
379,301
|
Change in
decomissioning estimates (note
23)
|
-
|
157,224
|
-
|
157,224
|
At 31 December 2023
|
156,169
|
7,976,764
|
47,640
|
8,180,573
|
|
|
|
|
|
Depletion, depreciation,
amortisation and
impairment
|
|
|
|
|
At 1
January 2022
|
(5,429)
|
(2,909,695)
|
(13,824)
|
(2,928,948)
|
Depletion, depreciation and amortisation charge for the year
|
(37,438)
|
(615,261)
|
(10,248)
|
(662,947)
|
Impairment charge (note 19)
|
-
|
(30,700)
|
-
|
(30,700)
|
At 31 December 2022 and 1 January 2023
|
(42,867)
|
(3,555,656)
|
(24,072)
|
(3,622,595)
|
Depletion, depreciation and amortisation charge for the year
|
(42,648)
|
(693,573)
|
(4,079)
|
(740,300)
|
Impairment charge (note 19)
|
-
|
(559,472)
|
-
|
(559,472)
|
At 31 December 2023
|
(85,515)
|
(4,808,701)
|
(28,151)
|
(4,922,367)
|
|
|
|
|
|
Net book value at 31 December 2022
|
56,060
|
3,556,996
|
21,840
|
3,634,896
|
Net book value at 31 December 2023
|
70,654
|
3,168,063
|
19,489
|
3,258,206
|
The transfers from exploration and
evaluation assets to development and production assets in 2023
relates to the Rosebank development following consent being granted
for the development by the North Sea Transition Authority
(NSTA) on 27 September 2023. Subsequent to this,
environmental campaigners Uplift and Greenpeace UK announced that
they are separately seeking judicial review by the Court of Session
in Edinburgh with respect to the decision by the NSTA and the Secretary of State for Energy to approve the Rosebank development. In 2022 the transfers related
to the
Abigail and
Jade South
wells. At
the point
of transfer
these assets
were tested
for impairment
and none was
found.
Additions to right of use assets
in the year to 31 December 2023 principally relate to modifications
to the Rosebank FPSO and will begin to be depreciated on
commencement of production. The related lease will commence on
delivery of the FPSO to the joint venture
partners at first oil which is currently anticipated to be
2026/27.
Other fixed assets includes buildings,
computer equipment, office
equipment and
furniture and
fittings.
16. Interests
in joint
operations
The contractual agreement for the
licence interests in which the Group has an investment do not
typically convey control of the underlying joint arrangement to any
one party, even where one party has a greater than 50%
equity ownership
of the
area of
interest.
The Group's material joint operations as at 31 December are as follows:
Group
net % interest
Block
|
Licence
|
Field/discovery name
|
Operator
|
2023
|
2022
|
|
9/11c
|
P.979
|
Mariner
|
Equinor UK Limited
|
8.89%
|
8.89%
|
|
9/11b
|
P.726
|
Mariner
|
Equinor UK Limited
|
8.89%
|
8.89%
|
|
30/2c
|
P.672
|
Jade
|
Chrysaor Petroleum Company
UK Limited
|
25.50%
|
25.50%
|
|
22/30c and 29/5c
|
P.666
|
Elgin-Franklin
|
TotalEnergies E&P
UK Limited
|
6.09%
|
6.09%
|
|
15/29b
|
P.590
|
Callanish
|
Chrysaor Production
(UK) Limited
|
20.00%
|
20.00%
|
|
204/25a
|
P.559
|
Schiehallion
|
BP
Exploration Operating Company
Limited
|
35.30%
|
35.30%
|
|
204/19b and 204/20b
|
P.556
|
Suilven
|
Ithaca SP E&P Limited
|
50.00%
|
50.00%
|
|
29/5b
|
P.362
|
Elgin-Franklin
|
TotalEnergies E&P
UK Limited
|
6.09%
|
6.09%
|
|
21/4a
|
P.347
|
Callanish
|
Chrysaor Production
(UK) Limited
|
13.70%
|
13.70%
|
|
16/27b
|
P.345
|
Britannia
|
Ithaca MA
Limited
|
35.75%
|
35.75%
|
|
9/11a
|
P.335
|
Mariner
|
Equinor UK Limited
|
8.89%
|
8.89%
|
|
13/22a
|
P.324
|
Captain
|
Ithaca SP E&P Limited
|
85.00%
|
85.00%
|
|
22/18a
|
P.292
|
Arbroath, Arkwright,
Carnoustie, Wood
|
Repsol
Sinopec Resources UK Limited
|
41.03%
|
41.03%
|
|
22/17s, 22/22a and 22/23a
|
P.291
|
Arbroath, Arkwright, Brechin,
Carnoustie, Cayley, Shaw
|
Repsol
Sinopec Resources UK Limited
|
41.03%
|
41.03%
|
|
23/26b
|
P.264
|
Erskine
|
Ithaca
Energy (UK) Limited
|
50.00%
|
50.00%
|
|
9/11d
and 9/12b
|
P.2508
|
Mariner
|
Equinor UK Limited
|
8.89%
|
8.89%
|
|
22/1b
|
P.2373
|
F
Block (Fotla
and Fortriu)
|
Ithaca Oil and Gas Limited
|
100.00%
|
60.00%
|
|
15/18b
|
P.2158
|
Marigold
|
Ithaca Oil and Gas Limited
|
100.00%
|
100.00%
|
|
9/11g
|
P.2151
|
Mariner
|
Equinor UK Limited
|
8.89%
|
8.89%
|
|
16/26a A-ALB
|
P.213
|
Alba
|
Ithaca Oil and Gas Limited
|
36.67%
|
36.67%
|
|
16/26a B-BRI
|
P.213
|
Britannia
|
Ithaca MA
Limited
|
33.17%
|
33.17%
|
|
16/26a
|
P.213
|
N/A
|
Ithaca Oil and Gas Limited
|
34.50%
|
34.50%
|
|
3/7a
|
P.203
|
Columba E
|
CNR
International (UK) Limited
|
20.00%
|
20.00%
|
|
3/8a and 3/8a
|
P.199
|
Columba B/D
|
CNR
International (UK) Limited
|
5.60%
|
5.60%
|
|
16. Interests in joint operations continued
Group
net % interest
Block
|
Licence
|
Field/discovery name
|
Operator
|
2023
|
2022
|
|
22/30b
|
P.188
|
Elgin-Franklin
|
TotalEnergies E&P UK Limited
|
6.09%
|
6.09%
|
|
21/20a
|
P.185
|
Cook
|
Ithaca SP E&P Limited
|
61.35%
|
61.35%
|
|
8/15a
|
P.1758
|
Mariner
|
Equinor UK Limited
|
8.89%
|
8.89%
|
|
29/10b
|
P.1665
|
Abigail
|
Ithaca SP E&P Limited
|
100.00%
|
100.00%
|
|
30/7b
|
P.1589
|
Jade
|
Chrysaor Petroleum Company
UK Limited
|
25.50%
|
25.50%
|
|
30/1f
|
P.1588
|
Vorlich
|
Ithaca MA
Limited
|
100.00%
|
100.00%
|
|
30/1c
|
P.363
|
Vorlich
|
Ithaca MA
Limited
|
34.00%
|
34.00%
|
|
205/2a
|
P.1272
|
Rosebank
|
Equinor UK Limited
|
20.00%
|
20.00%
|
|
205/1a
|
P.1191
|
Rosebank
|
Equinor UK Limited
|
20.00%
|
20.00%
|
|
15/29a
|
P.119
|
Alder
|
Ithaca
Energy (UK) Limited
|
73.68%
|
73.68%
|
|
15/29a
|
P.119
|
Britannia
|
Ithaca MA
Limited
|
75.00%
|
75.00%
|
|
204/4a and 204/5a
|
P.1189
|
Cambo
|
Ithaca SP E&P Limited
|
100.00%
|
70.00%
|
|
21/3a
|
P.118
|
Brodgar
|
Chrysaor Production
(UK) Limited
|
25.00%
|
25.00%
|
|
23/22a
|
P.111
|
Pierce
|
Enterprise
Oil Limited
|
34.01%
|
34.01%
|
|
15/30a
|
P.103
|
Britannia
|
Chrysaor Production
(UK) Limited
|
33.03%
|
33.03%
|
|
21/5a
|
P.103
|
Enochdhu
|
Chrysaor Production
(UK) Limited
|
50.00%
|
50.00%
|
|
204/9a and 204/10a
|
P.1028
|
Cambo
|
Ithaca SP E&P Limited
|
100.00%
|
70.00%
|
|
213/26b and 213/27a
|
P.1026
|
Rosebank
|
Equinor UK Limited
|
20.00%
|
20.00%
|
|
23/26a
|
P.057
|
Erskine
|
Ithaca
Energy (UK) Limited
|
50.00%
|
50.00%
|
|
22/18n
|
P.020
|
Montrose
|
Repsol
Sinopec Resources UK Limited
|
41.03%
|
41.03%
|
|
22/17n, 22/17s, 22/22a and 22/23a
|
P.019
|
Godwin, Montrose
|
Repsol
Sinopec Resources UK Limited
|
41.03%
|
41.03%
|
|
30/6a and 29/10a
|
P.011
|
Stella/Harrier
|
Ithaca
Energy (UK) Limited
|
100.00%
|
100.00%
|
|
30/11a and 30/12d
|
P.1820
|
Isabella
|
Total Energies E&P North Sea UK Limited
|
10.00%
|
10.00%
|
|
204/8,
204/9c, 204/10c, 204/13, 204/14d
and 204/15
|
P.2403
|
Tornado
|
Ithaca SP E&P Limited
|
50.00%
|
50.00%
|
|
1 Net cash flows relating to the MOGL acquisition includes
a $7 million deposit paid in the year ended 31 December 2021.
17. Business combinations
continued
MOGL
On 4 February 2022, the Group
completed the acquisition of 100% of the issued share capital of
MOGL. The transaction added a further non-operated share in nine
producing field interests (known as MonArb) to the existing
Ithaca portfolio.
Taking into account the interim
period cash flows generated by MOGL since the transaction effective
date of 1 January 2021, the $7 million deposit paid at signing of
the transaction in November 2021 and conventional working
capital adjustments, the price payable at
completion of the acquisition was $108 million. A deferred
consideration of $63 million and risked contingent consideration of
$139 million, discounted at 2.5% were recognised at acquisition,
resulting in a gain on bargain purchase of $620
million.
The contingent consideration
arrangement on MOGL depends on whether various milestones in the
Sale and Purchase Agreement (SPA) are met as follows: set gross
export production volume from Montrose Infill Project Phase
1, set cumulative gross export production
volume following Arbroath well reinstatements, set gross export
production volume from next new well in the Shaw Field and, an
amount payable during the Value Sharing Period (1 January 2022 to
31 December 2024) in relation to sales in excess of a set oil
trigger price. The amount payable in relation to sales in excess of
a set oil trigger price is capped under the terms of the
SPA.
The contingent consideration is
subsequently revalued at each year-end date.
The gain on bargain purchase
arising on the MOGL acquisition was principally a result of
recognising a deferred tax asset arising from tax losses of $745
million, which were not forecast to be utilised by MOGL, as allowed
under IFRS 3 fair value accounting for
business combinations. The gain was also partially attributed to
the extended period from effective date of 1 January 2021 to the
completion date of 4 February 2022 during which time hydrocarbon
prices rose significantly. The gain on bargain purchase of $620 million was credited to income in the year ended 31 December 2022.
Siccar Point Energy
On 30 June 2022, the Group
completed the acquisition of 100% of the issued share capital of
Siccar Point Energy (Holdings) Limited (Siccar Point Energy) and
its UK subsidiaries. The transaction added a further two producing
assets (Mariner 8.89% and Schiehallion
11.75%), an additional 5.57% increase to the Group's existing
equity in Jade, and three development prospects (Rosebank 20%,
Cambo 70% at date of acquisition and Tornado 50%) to the existing
Group portfolio.
Taking into account the interim
period cash flows generated by Siccar since the transaction
effective date of 1 January 2022 and conventional working capital
adjustments, the price payable at completion of the acquisition was
$1.015 billion.
A risked
contingent consideration of $102 million was recognised, resulting in a gain on bargain purchase of $704 million.
The contingent consideration
arrangement on Siccar Point Energy depends on whether various
milestones of the SPA are met as follows: redemption of acquired
bond as at repayment date, Final Investment Decision and the
associated reserves in respect of the
Cambo and Rosebank fields and, an amount paid in relation to sales
in excess of a set floor oil price. The amount payable in relation
to sales in excess of a set oil trigger price is capped under the
terms of the SPA.
The contingent consideration is
subsequently revalued at each year-end date.
17. Business
combinations continued
The gain on bargain purchase
arising on the Siccar Point Energy transaction was principally as a
result of recognising a deferred tax asset arising from tax losses
of $1,334 million as allowed under IFRS 3 fair value
accounting for
business combinations. The
gain on
bargain purchase
of $704
million was
credited to
income in
the year
ended 31
December 2022.
On acquisition of Siccar Point Energy, the Group acquired a $200 million bond. On 28 July 2022 a group of bondholders exercised their right to redeem and subsequently $166.4
million was
paid to
these bondholders. Subsequently,
in September 2022, notes totalling $25.6 milion
were bought back at a premium of 6% by the Group. The remaining
notes totalling $8.0 million were redeemed on 12 October 2022 and
there was no remaining balance at 31 December 2022.
Summit
On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Summit. The transaction added
a further
2.1875% ownership
of the
Elgin Franklin
field interest
within the
existing Group
portfolio.
Taking into account the interim
period cash flows generated by Summit since the transaction
effective date of 1 January 2021, the $10 million deposit paid at
signing of the transaction in February 2022 and conventional
working capital adjustments, the price
payable at completion of the acquisition was $119 million and
goodwill of $62 million was recognised. The goodwill recognised can
be attributed to the increase in the Group's equity interest in the
Elgin Franklin field and the corresponding impact of EPL, which was
announced between effective date and completion, on the fair values
at acquisition.
There are no contingent
consideration arrangements under the Sale and Purchase Agreement of
the Summit assets. No contingent liabilities have been acquired on the business combinations
detailed above.
The fair values of the oil and gas
assets and the intangible assets acquired have been determined
using valuation techniques based on discounted cash flows using
forward curve commodity prices and estimates of long-term
commodity prices reflective of market
conditions at each completion date, a discount rate based on
observable market data and cost and production profiles generally
consistent with the proved and probable reserves acquired with each
asset.
The decommissioning liabilities
recognised have been estimated based on operator cost estimates
with reference to observable market data.
18. Goodwill
|
2023
US$'000
|
2022
US$'000
|
Balance at 1 January
|
783,848
|
722,075
|
Additions (note 17)
|
-
|
61,773
|
Balance at 31 December
|
783,848
|
783,848
|
The goodwill is not tax deductible
on any of the acquisitions.
|
|
|
18. Goodwill continued
The goodwill on acquisition
in the year to 31
December 2022 relates to the Summit
acquisition, as detailed in note
17.
Annual impairment tests were
performed at both 31 December 2023 and 31 December 2022. These
reviews were carried out on a fair value less cost of disposal
basis using risk adjusted cash flow projections from the
approved business plans including the same
commodity prices, life of field cost profiles and production
volumes used for impairment of oil and gas assets (see note 19),
discounted at a post-tax discount rate of 10.3% (2022: 10.9%).
Assumptions and estimates in the Group impairment models are
detailed in note 3. An increase of 1% in the discount rate
assumption would not result in a post-tax impairment of goodwill.
Goodwill is monitored, and tested for impairment, at the operating
segment level, being the North Sea (the entire Group portfolio of
oil and gas assets). This is consistent with the operating segment
view of the business which is presented to the Board and the Chief
Decision Maker.
The Group's activities are
considered to be an individual operating segment due to the uniform
nature of the Group's operations within a single geographical area,
overseen by the same management and subject to the same
regulations. The
fair value
estimate is
categorised as
level 3
in the
fair value
hierarchy.
19. Impairment charge
on oil
and gas
assets
|
2023
US$'000
|
2022
US$'000
|
D&P assets
|
(559,472)
|
(30,700)
|
E&E assets
|
-
|
(1,867)
|
Other movements
|
1,536
|
-
|
Contingent consideration reversal
|
-
|
1,100
|
North Sea oil and gas assets
|
(557,936)
|
(31,467)
|
The impairment charge
on D&P
assets of
$559.5 million
(2022: $30.7
million) primarily relates
to Alba
of $141.3
million and
the Greater
Stella Area
(GSA) of
$373.2 million.
The charge
in 2022
reflected revisions in decommissioning provisions,
principally on fields that are no longer producing.
Estimated production volumes and
cash flows used in impairment reviews are considered up to the date
of cessation of production on a field-by-field basis, including
operating and capital expenditure and are derived from
management approved business
plans.
An impairment review was carried
out at the end of 2023 on the Group's producing assets with the
main triggers being a reduction in future reserves on Alba, a
decrease in short-term forward oil prices against all oil producing
CGUs and a decrease in short-term gas
prices for GSA and other predominantly gas-producing CGUs with
relatively short remaining useful economic lives. The review was
carried out on a fair value less cost of disposal basis using risk
adjusted cash flow projections discounted
at a post-tax discount rate of 10.3%, and represents level 3 in the
fair value hierarchy. The recoverable amount (post tax) for Alba
and GSA was $nil and $29.7 million respectively.
The following assumptions, as
supported by third-party analysis, were used at Q4 2023 in
developing the cash flow model and applied over the expected life
of the respective fields:
|
|
Price
assumptions (nominal)
|
|
|
Post
tax
discount
rate
assumption
|
2024
|
2025
|
2026
|
2027
|
20281
|
|
Oil
|
10.3%
|
$85/bbl
|
$83/bbl
|
$87/bbl
|
$90/bbl
|
$93/bbl
|
|
Gas
|
10.3%
|
101p/therm
|
96p/therm
|
83p/therm
|
85p/therm
|
87p/therm
|
|
1. Post-2028 an annual 2%
increase is applied to the price assumptions.
|
|
|
|
|
|
|
|
With all other assumptions held
constant and supported by third-party analysis, a 20% decrease in
the forecast revenues, illustrating lower commodity prices and/or
production volumes, would result in an additional post-tax
impairment of PP&E of $22 million (2022: $13 million) at 31 December 2023. A 20% increase in forecast revenues would reduce the reported post-tax
impairment by
$26 million.
An increase
or decrease
of 1%
in the
discount rate
assumption would not
result in a material additional post-tax impairment or reversal of
impairment of PP&E.
19. Impairment charge
on oil
and gas
assets continued
The group has also conducted a
sensitivity scenario on the climate-related risk of a reduction in
demand and commodity prices for oil and gas due to changing
consumer preferences and/or government regulations.
Utilising the Climate scenario's average oil
price while maintaining all other parameters in line with the base
case would result in an immaterial effect on additional post-tax
impairment as at 31 December 2023.
To calculate the Climate Scenario
average oil price, the group utilised data from both the
International Energy Agency (IEA) climate scenarios (NZ, STEPS,
APS) and the World Business Council for Sustainable
Development (WBCSD) data catalogue.
Management's base case assumption aligns substantially with
climate-adjusted curves for gas and carbon emission prices; hence,
no supplementary sensitivity analysis has been
presented.
An impairment review was also
carried out at the end of 2022 on the Group's producing assets with
the main trigger being the implementation of the Energy Profits
Levy (EPL) in the second half of 2022. The review demonstrated
that there was no requirement to impair
any of the Group's producing assets. The review was carried out on
a fair value less cost of disposal basis using risk adjusted cash
flow projections discounted at a post-tax discount rate of
10.9%.
The following assumptions, as
supported by third-party analysis, were used at Q4 2022 in
developing the cash flow model and applied over the expected life
of the respective fields:
|
|
Price
assumptions (nominal)
|
|
|
Post
tax
discount
rate
assumption
|
2023
|
2024
|
2025
|
2026
|
20271
|
|
Oil
|
10.9%
|
$89/bbl
|
$84/bbl
|
$83/bbl
|
$83/bbl
|
$83/bbl
|
|
Gas
|
10.9%
|
315p/therm
|
211p/therm
|
99p/therm
|
86p/therm
|
86p/therm
|
|
1. Post 2027 an annual 2% is
applied to the price assumptions.
|
|
|
|
|
|
|
|
Estimated production volumes and
cash flows up to the date of cessation of production on a
field-by-field basis, including operating and capital expenditure,
are derived from the approved business plans and third-party
reports.
20. Borrowings
|
2023
US$'000
|
2022
US$'000
|
Current
|
|
|
Accrued interest costs on borrowings
|
(29,913)
|
-
|
|
(29,913)
|
-
|
Non-current
|
|
|
RBL facility
|
-
|
(600,000)
|
Senior unsecured notes
|
(625,000)
|
(625,000)
|
bp unsecured loan
|
(100,000)
|
-
|
Unamortised long-term bank fees
|
4,555
|
7,591
|
Unamortised long-term senior notes fees
|
2,207
|
3,678
|
Total debt
|
(718,238)
|
(1,213,731)
|
Accrued interest on borrowings has
been reclassed in the current year from accruals (within trade and
other payables) to borrowings, to reflect the current payable in
respect of borrowings. The prior year equivalent of $21.7 million
has not been adjusted for this change as
it is not material and remains within accruals for the year ended
31 December 2022.
Adjusted net debt, which does not include accrued interest on borrowings, lease liabilities
or unamortised
fees, is
set out
in non-GAAP
measures on
pages
76 to
78.
20. Borrowings continued
Reserves Based Lending (RBL) facility
During 2021, the Group completed a refinancing to amend and extend the RBL facility. The RBL commitment was approximately
$1.225 billion
with a
maturity to
2026, and
subject to
interest at
a reference
rate of
SOFR plus
3.5%. At 31
December 2023,
due to
the NPV
cap described
in the
covenants section
below, the
total availability was $725 million (2022: $925 million), of which none (2022: $600 million) was drawn down, leaving an amount of $725 million (2022: $325 million) being available for drawdown. Subsequent
to 31 December 2023, RBL liquidity increased from $725 million to
$836 million.
Loan fees of $15.2 million relating to the RBL were capitalised and are being amortised over the term of the loan, $4.6 million (2022: $7.6 million) remains to be amortised as at 31 December 2023.
The RBL facility is secured by the
assets of the guarantor members of the Group, such security
including share pledges, floating charges and/or debentures. Total
assets pledged as security at 31 December 2023 was $[6,238] million (2022: $6,760
million).
Senior notes
In 2021, the Group completed the
refinancing of its senior unsecured notes with the issuance of $625
million 9% senior unsecured notes due July 2026 and repayment in
full of the notes issued during 2019. Loan fees of $7.4
million relating
to the
new senior
notes were
capitalised and
are being
amortised over
the life
of the
loan, $2.2
million (2022:
$3.7 million)
remains to
be amortised
as at
31 December
2023.
Covenants in relation to these senior notes are detailed below.
On acquisition of Siccar Point Energy on 30 June 2022, the Group acquired their existing $200 million 9% senior unsecured notes due March 2026. The Group also acquired $5.8 million of accrued interest in relation to these senior notes. On 1 August 2022, a settlement was made as a result of the
exercise of the put option on the notes and a combined holding of
$166.4 million exercised the put option. Subsequently, in September
2022, notes totalling $25.6 million were bought back at
a premium
of 6%
by the
Group. The
remaining notes
totalling $8.0
million were
fully redeemed
on 12
October 2022.
bp facility
During the year to 31 December
2023, a new $100 million five-year facility was entered into with
bp which is subject to an interest rate of SOFR plus a commercially
agreed margin. The loan is unsecured, is due for repayment in
2028 and was fully drawn at 31 December
2023 (2022: $nil). Fees of $0.5 million were incurred on
drawdown.
Optional project capital
expenditure facility
During the year to 31 December, a carry arrangement
of up
to $150
million was
entered into
relating to
a field
development. The
carry is
repayable by
instalment expected to be from 2027. Under the terms of the arrangement, interest
is payable at a rate of SOFR (subject to a
minimum of 5%) plus a commercially agreed margin. The carry
arrangement was undrawn at 31 December 2023.
Covenants
The Group is subject to financial and operating covenants
related to
the RBL
facility. Failure
to meet
the terms
of one
or more
of these
covenants may
constitute an
event of
default as
defined in
the facility
agreements, potentially resulting in accelerated
repayment of the debt obligations. The Group was in compliance with
all its relevant quarterly financial and operating covenants during
all periods shown for the RBL facility and acquired senior notes.
There are no
ongoing maintenance or financial covenant
tests associated
with the
$625 million
unsecured notes.
In addition to the below financial
covenants, the Group is subject to restrictive covenants under the
RBL facility and 2026 notes, restricting the Group, to, amongst
other things: make certain payments (including, subject to
certain exceptions, dividends and other
distributions), with respect to outstanding share capital; repay or
redeem subordinated debt or share capital; create or incur certain
liens; make certain acquisitions and investments or loans; sell,
lease or transfer certain assets, including shares of any of the
Group's restricted subsidiaries; incur expenditure on exploration
and appraisal activities in excess of approved levels; guarantee
certain types of the Group's other indebtedness; expand into unrelated businesses;
merge or
consolidate with
other entities;
or enter
into certain
transactions with
affiliates.
20. Borrowings continued
The key financial covenants in the
RBL are:
• The parent shall ensure that as at the end of each Relevant
Period (starting with the Relevant Period ending on 30 November
2021) the ratio of adjusted net debt to adjusted EBITDAX shall be
less than 3.5:1. 'Adjusted net debt' referred to is not an IFRS measure. The Company uses adjusted
net debt as a measure to assess its financial position. Adjusted
net debt comprises amounts outstanding under the Company's RBL
facility, bp facility and senior notes, less cash and cash
equivalents;
• Total projected sources of funds must exceed the total projected uses of funds for the following 12-month period (or a longer period to first production from development, if applicable);
• The ratio of the net present value of cash
flows secured under the
RBL for the
economic life of the fields to the amount drawn
under the facility must not fall below
1.15:1; and
• The ratio of the net present value of cash flows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.
The Group was in compliance with
all financial covenants of the RBL facility in all periods
presented.
21. Changes in liabilities arising from financing activities
Non-cash changes
|
|
1 January 2023
|
Financing cash
flows (i)
|
Additions
|
Imputed interest
|
Fair value
movements
|
Amortisation
|
Debt waiver
|
Other movements (ii)
|
31 December 2023
|
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
Borrowings (note 20)
|
1,213,731
|
(596,642)
|
-
|
-
|
-
|
4,507
|
-
|
126,554
|
748,150
|
Lease liabilities
|
58,858
|
(45,085)
|
3,603
|
-
|
-
|
-
|
-
|
3,183
|
20,559
|
Interest rate derivatives (note
29)
|
(7,125)
|
6,967
|
-
|
-
|
(479)
|
-
|
-
|
-
|
(637)
|
Total liabilities from financing
activities
|
1,265,464
|
(634,760)
|
3,603
|
-
|
(479)
|
4,507
|
-
|
129,737
|
768,072
|
Non-cash changes
|
|
1 January 2022
|
Financing cash
flows (i)
|
Additions
|
Imputed interest
|
Fair value
movements
|
Amortisation
|
Debt waiver
|
Other movements (ii)
|
31 December 2022
|
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
Borrowings (note 20)
|
954,616
|
50,000
|
200,000
|
-
|
-
|
4,508
|
-
|
-
|
1,213,731
|
Parent company debt (note 31)
|
437,076
|
(273,055)
|
-
|
17,924
|
-
|
-
|
(181,945)
|
-
|
-
|
Lease liabilities
|
3,489
|
(38,200)
|
-
|
-
|
-
|
-
|
-
|
93,569
|
58,858
|
Interest rate derivatives (note
29)
|
(133)
|
851
|
-
|
-
|
(7,843)
|
-
|
-
|
-
|
(7,125)
|
Total liabilities from financing
activities
|
1,395,048
|
(260,404)
|
200,000
|
17,924
|
(7,843)
|
4,508
|
(181,945)
|
98,176
|
1,265,464
|
(i) The cash flows from borrowings, Parent Company debt, lease
liabilities and interest rate derivatives make up the net amount of
proceeds from borrowings and repayments of borrowings in the cash
flow statement.
(ii) Other movements include interest accruals and new liabilities in the year.
22. Trade and other payables
|
|
|
2023
US$'000
|
2022
US$'000
|
Trade payables
|
(34,559)
|
(14,917)
|
Hydrocarbon amounts owed to joint operations/overlift
|
(72,486)
|
(124,365)
|
Other payables
|
(68,034)
|
(185,720)
|
Accruals
|
(254,781)
|
(299,604)
|
Deferred income
|
(48,747)
|
(86,806)
|
|
(478,607)
|
(711,412)
|
The Directors consider the
carrying values of trade and other payables to approximate the fair
value. Other payables mainly comprises amounts owed due to
production adjustments and amounts owed to joint operations
partners. Deferred income represents
receipts in advance of deliveries to customers. The prior year
deferred income was recognised in revenue in the current
year.
23. Decommissioning liabilities
|
2023
US$'000
|
2022
US$'000
|
Balance at 1 January
|
(1,720,540)
|
(1,641,489)
|
Business combination additions
|
-
|
(390,530)
|
Accretion
|
(74,621)
|
(52,592)
|
Additions and revisions to
estimates
|
(160,069)
|
298,564
|
Decommissioning
provision utilised
|
95,552
|
65,507
|
Balance at 31 December
|
(1,859,678)
|
(1,720,540)
|
Current
|
|
|
Balance at 1 January
|
(146,829)
|
(94,640)
|
Balance at 31 December
|
(107,026)
|
(146,829)
|
Non-current
|
|
|
Balance at 1 January
|
(1,573,711)
|
(1,546,849)
|
Balance at 31 December
|
(1,752,652)
|
(1,573,711)
|
Additions and revisions to estimates comprise $157,224k
(2022: $(278,398)k) of development and production assets
and $2,845k
(2022: $(20,166)k) of exploration and evaluation assets.
The total future decommissioning
liability represents the estimated cost to decommission, in situ or
by removal, the Group's net ownership interest in all wells,
infrastructure and facilities, based upon forecast timing in future
periods. The Group uses a nominal discount
rate of 4.60% (31 December 2022: 4.25%) and an inflation rate of
2.0% (31 December 2022: 2.0%) over the varying lives of the assets
to calculate the present value of the decommissioning liabilities.
The impact of a change in discount rate is considered in note 3.
Revisions to estimates in the years ended 31 December 2023 and 2022
were due to changes in both cost estimates and discount rate
assumptions.
The estimated 2024 decommissioning
spend of of $107 million (2022: estimated 2023 decommissioning
spend of $147 million) has been treated as a current liability as
at 31 December 2023. Although the Group currently expects to
incur decommissioning costs over the next 40
years, it is estimated that approximately 47% of the
decommissioning liability relates to assets which are expected to
cease production in the next five years and which includes spend
for assets that will be reimbursed (see note 11 for further
details).
24. Lease liabilities
|
|
Current
|
2023
US$'000
|
2022
US$'000
|
Lease liabilities
|
(19,898)
|
(41,637)
|
Non-current
|
2023
US$'000
|
2022
US$'000
|
Lease liabilities
|
(660)
|
(17,221)
|
The following table sets out a
maturity analysis of lease payments, showing the undiscounted lease
payments to be paid after the reporting date. All lease liabilities
are fully payable within two years from 31 December 2023.
|
|
2023
US$'000
|
2022
US$'000
|
Less than
one year
|
(20,152)
|
(44,257)
|
One to two years
|
(669)
|
(17,439)
|
Total undiscounted lease
payments
|
(20,821)
|
(61,696)
|
Future finance charges and other
adjustments
|
263
|
2,838
|
Lease liabilities in the
financial statements
|
(20,558)
|
(58,858)
|
|
2023
US$'000
|
2022
US$'000
|
At 1 January
|
(58,858)
|
(3,489)
|
Additions
|
(3,603)
|
(89,717)
|
Interest
|
(3,183)
|
(3,852)
|
Payments
|
45,086
|
38,200
|
At 31 December
|
(20,558)
|
(58,858)
|
Current
|
(19,898)
|
(41,637)
|
Non-current
|
(660)
|
(17,221)
|
|
(20,558)
|
(58,858)
|
The additions in the year to 31 December 2023 relate to modifications of the Captain Emergency Response
and Recovery
Vehicle lease.
The addition in the year to 31 December 2022 relates to the Pioneer rig lease currently utilised
on the
Captain EOR
project. The
incremental borrowing rate applied to the lease is 6.07%.
If the Company were to terminate
the use of the Pioneer rig early then termination fees would apply,
escalating to 75% of total expected costs if within one month prior
to commencement date of planned works. Remuneration for work
performed up to the date of termination, together
with costs relating to demobilisation of the drilling unit to the
demobilisation port would also be due.
Amounts recognised in profit and
loss related to leases is detailed in notes 6 and 9.
25. Contingent and deferred consideration
|
|
Current
|
2023
US$'000
|
2022
US$'000
|
Contingent consideration
|
(101,669)
|
(101,559)
|
Petrofac deferred consideration
|
-
|
(6,121)
|
|
(101,669)
|
(107,680)
|
Non-current
|
2023
US$'000
|
2022
US$'000
|
Contingent consideration
|
(194,721)
|
(157,337)
|
MOGL deferred consideration
|
(63,979)
|
(61,783)
|
|
(258,700)
|
(219,120)
|
|
2023
US$'000
|
2022
US$'000
|
Cash flows relating
to contingent and
deferred considerations
|
(13,567)
|
(66,132)
|
Movement in contingent consideration consideration
is as
follows:
|
|
|
|
2023
US$'000
|
2022
US$'000
|
At 1 January
|
(258,896)
|
(19,480)
|
Business combinations (note 17)
|
-
|
(241,431)
|
Addition
|
(26,872)
|
-
|
Payments made
|
7,200
|
11,040
|
Reversal
|
-
|
1,100
|
Accretion
|
(9,814)
|
(5,830)
|
Changes in fair value
|
(8,008)
|
(4,295)
|
At 31 December
|
(296,390)
|
(258,896)
|
Movement in deferred consideration
consideration is as follows:
|
|
|
|
2023
US$'000
|
2022
US$'000
|
At 1 January
|
(67,904)
|
(55,610)
|
Business combinations (note 17)
|
-
|
(63,415)
|
Payments made
|
6,367
|
55,156
|
Accretion
|
(2,442)
|
(4,035)
|
At 31 December
|
(63,979)
|
(67,904)
|
25. Contingent and deferred consideration
continued
Cash outflows in the year ended 31 December 2023 of $13.6 million (2022: $66.1 million) are in relation to the consideration
payable on
Petrofac GSA
transaction and
quarterly payments in consideration to the MOGL and Siccar oil price triggers.
MOGL
During the year ended 31 December
2022 the Group acquired MOGL which included elements of
consideration that are payable upon certain events occurring and
contingent considerations have been recognised to reflect
this. Further details regarding the
acquisition and the related contingent terms are set out in note
17. The carrying amount at 31 December 2023, discounted at 4.6% was
$111 million (2022: $128 million using a discount rate of 4.25%).
The total undiscounted potential consideration as at 31 December
2023 is $230 million (2022: $241 million).
The MOGL deferred consideration of $64 million (2022: $62 million) relates to completion of the MOGL transaction in February 2022. It is payable on 1 July 2025 and is discounted to reflect the time value of money.
Siccar
During the year ended 31 December 2022 the Group acquired Siccar Point Energy which included elements of consideration that
are payable
upon certain
events occurring
and contingent
considerations have been recognised to reflect this. Further details regarding the acquisition and
the related contingent terms are set out in note 17. The carrying
amount at 31 December 2023, discounted at 4.6% was $130 million
(2022: $102 million using a discount rate of 4.25%). The total undiscounted
potential consideration as at 31 December 2023 is $362 million (2022: $362 million). As a result of the Rosebank field obtaining FDP approval during 2023, the carrying amount at 31 December 2023 has been increased.
Others
During the year ended 31 December 2023, the Group acquired a further 30% equity in the Cambo field from Shell. The acquisition included
elements of
consideration that are payable upon certain events occurring and contingent consideration has been
recognised to reflect this. The consideration value equates to
$1.50 per barrel of oil equivalent of the P50 resource volumes of
the field, and is payable on the earlier of receipt of proceeds of
any subsequent sale of a working interest
in Cambo by the Group, or first oil. The carrying amount at 31
December 2023 was $12.7 million (2022: $nil).
During the year ended 31 December
2023, the Group acquired 40% equity in the Fotla field from Spirit.
The acquisition included elements of consideration that are payable
upon certain events occurring and contingent consideration
has been recognised to reflect this. The
consideration comprises two capped amounts with approximately
two-thirds payable on final investment decision and one-third on
first production. The carrying amount at 31 December 2023
was $14.2
million (2022:
$nil).
A further $3.0 million (2022: $6.4
million) relates to Yeoman/Marigold, with a remaining unrisked
payment of $11.0 million (2022: $11.0 million) contingent on
achieving FDP and a further $6.0 million (2022: $6.0 million)
unrisked on certain production
criteria being
met.
During the year ended 31 December
2023, further consideration of $5.7 million (2022: $6.4 million)
was recognised as an additional payable due to changes in the
variables in the calculation of the liability, resulting in $25.6
million (2022: $19.9 million) liability on
Strathspey in accordance with the Sale and Purchase Agreement with
Chevron.
Revaluation of contingent consideration in the year to 31 December 2023 resulted in an increase of $8.0 million (2022: increase of $4.3 million).
26. Reserves
(a) Issued share capital
The issued share capital is as
follows:
|
Number of common shares
|
Amount US$'000
|
At 31 December 2022
|
1,006,564,976
|
11,445
|
At 31 December 2023
|
1,014,372,281
|
11,540
|
On 5 October 2023, 7,807,305 ordinary shares of £0.01 each were issue to the Ithaca Energy plc Employee Benefit Trust (EBT) to satisfy the exercise of share options during the year and in future years.
On 26 October 2022 the Company undertook
a share
capital reduction
whereby 114,000,000 issued
A ordinary
shares of
$1.00 each
were cancelled
and extinguished.
In addition
on this
date the
share premium
account as
at 31
December 2021 of
$634,658,000 was cancelled. A number of further steps followed in
preparation for the IPO including the conversion of $1.00 shares to
£0.88 shares, the conversion of £0.88 shares to £0.01 shares, the
issue of bonus shares principally to
existing shareholders and the issue of 105,000,000 new shares on
the IPO. As a result the issued share capital of the Company
immediately after the IPO was 1,005,162,217 ordinary shares of
£0.01 each.
A reconciliation of
the opening
to closing
number of
shares in
the year
to 31
December 2022
is set
out below:
Number of shares
|
A ordinary
|
B1
ordinary
|
B2 ordinary
|
Ordinary
|
Total
|
A ordinary shares of $1.00 each at 1 January
2022
|
1,001
|
-
|
-
|
-
|
1,001
|
Issue of new $0.01 B1 shares and $0.01 B2 shares
|
-
|
100
|
100
|
-
|
200
|
Issue of new $1.00 A ordinary
shares
|
114,000,000
|
-
|
-
|
-
|
114,000,000
|
Cancellation of
$1.00 A
ordinary shares relating to capital reduction
|
(114,000,000)
|
-
|
-
|
-
|
(114,000,000)
|
Conversion of $1.00 A ordinary shares, $0.01 B1
share and 0.01 B2
share to £0.01 A
ordinary shares
|
87,087
|
(12)
|
(12)
|
-
|
87,063
|
Bonus issue of new £0.01 A
shares
|
898,131,843
|
-
|
-
|
-
|
898,131,843
|
Bonus issue of new £0.01 B1 shares
|
-
|
1,401,670
|
-
|
-
|
1,401,670
|
Bonus issue of new £0.01 B2 shares
|
-
|
-
|
420,440
|
-
|
420,440
|
Conversion of £ 0.01
A ordinary shares, £0.01 B1 shares and £0.01 B2 shares to £0.01 ordinary shares
|
(898,219,931)
|
(1,401,758)
|
(420,528)
|
900,042,217
|
-
|
Bonus issues of £0.01 ordinary shares
|
-
|
-
|
-
|
120,000
|
120,000
|
Issue of
new £0.01 ordinary shares on IPO
|
-
|
-
|
-
|
105,000,000
|
105,000,000
|
Issue of
new £0.01 ordinary shares on
exercise of share options
|
-
|
-
|
-
|
1,402,759
|
1,402,759
|
Ordinary shares of £0.01 each at 31 December 2022
|
-
|
-
|
-
|
1,006,564,976
|
1,006,564,976
|
26. Reserves continued
(b) Share premium
|
2023
|
2022
|
US$'000
|
US$'000
|
At 1 January
|
293,712
|
634,658
|
Share premium
cancellation
|
-
|
(634,658)
|
Additions
|
15,133
|
293,712
|
At 31 December
|
308,845
|
293,712
|
The share premium account
represents the cumulative difference between the market share price
and the nominal share value on the issuance of new ordinary shares
multiplied by the number of shares issued. Additions during 2023 represent the difference between the
nominal value per share of £0.01 and the closing share price on the
day before the shares were issued to the EBT multiplied by the
number of shares. During 2022, the additions represent the
difference between the nominal value per share of £0.01 and IPO
price of £2.50 per share multiplied by the number of shares issued
(net of share issues expenses).
(c) Capital contribution
reserve
|
2023
|
2022
|
US$'000
|
US$'000
|
At 1 January
|
181,945
|
114,000
|
Capital reduction
|
-
|
(114,000)
|
Addition
|
-
|
181,945
|
At 31 December
|
181,945
|
181,945
|
During the year to 31 December
2022, the Company settled outstanding loan liabilities (including
interest) of DKL Energy Limited (DKLE) out of IPO proceeds. As per
the terms of the confirmation letter dated 29 November 2022
signed between DKLE and the Company, DKLE
unconditionally and irrevocably released and forever discharged
Ithaca Energy plc from any and all liabilities to the DKLE in
respect of or in connection with the Capital and
Subordinated loan note agreements. The
remaining loan balance of $181.9 million has been capitalised as
Capital Contribution Reserve as per the requirements of IFRS
9.
(d) Own shares
Own shares comprise shares held in
the Ithaca Energy plc EBT which are being used to satisfy the
exercise of employee share options. During the year, 7,807,305
ordinary shares of £0.01 each were issued to the EBT and
1,443,561 ordinary shares were used to
satisfy the exercise of share options. As a result, the EBT held
6,363,744 ordinary shares of £0.01 each at 31 December
2023.
(e) Share-based payment reserve (note 32)
The share-based payment reserve
represents the cumulative charge for share options, as described in
note 32, less the cumulative cost of share option exercises.
27. Taxation
|
|
|
2023
US$'000
|
2022
US$'000
|
Current tax
|
|
|
Current corporation tax charge
|
(39,308)
|
(54,557)
|
Current EPL tax charge
|
(333,425)
|
(131,389)
|
Current corporation tax
(charge)/credit - prior year
|
(17,426)
|
1,839
|
Total current tax
charge
|
(390,159)
|
(184,107)
|
Deferred tax
|
|
|
Adjustment in respect of prior period
|
6,370
|
(641)
|
Group tax
credit/(charge) in consolidated statement of profit or
loss
|
227,360
|
(1,013,817)
|
Group tax charge in consolidated
statement of other comprehensive income
|
(71,700)
|
(200,455)
|
Total deferred tax credit/(charge)
|
162,030
|
(1,214,913)
|
Deferred Petroleum
Revenue Tax
|
|
|
Deferred PRT credit/(charge) in statement of
profit or loss
|
70,037
|
(10,432)
|
Total tax charge through consolidated statement
of profit
or loss
|
(86,392)
|
(1,208,997)
|
27. Taxation continued
The tax on the Group's profit before tax differs from the theoretical amount
that would
arise using
the 40%
statutory rate
of tax
applicable for
UK ring
fence oil
and gas
activities as
follows:
|
2023
|
2022
|
US$'000
|
US$'000
|
Accounting profit before tax
|
302,027
|
2,240,529
|
At tax rate of 40% (2022: 40%)
|
(120,811)
|
(896,211)
|
Non-deductible expense
|
(34,578)
|
(53,548)
|
Recognition of non-taxable gain on bargain purchase
|
-
|
534,069
|
Financing
costs not allowed for SCT
|
(704)
|
(1,958)
|
Ring Fence Expenditure Supplement
|
102,866
|
155,113
|
Deferred tax effect of investment allowance
|
56,930
|
(20,615)
|
Prior year adjustment
|
(11,673)
|
1,198
|
Deferred PRT net of
corporation tax
|
42,022
|
(6,259)
|
Deferred
tax on EPL
|
215,910
|
(766,489)
|
Current
tax on EPL
|
(333,425)
|
(131,389)
|
Prior
year adjustments on acquired entities
|
-
|
(3,165)
|
Share-based payments
|
1,945
|
-
|
Unrecognised tax losses
|
(4,874)
|
(19,743)
|
Total tax
charge recorded in the consolidated
statement of profit or loss
|
(86,392)
|
(1,208,997)
|
The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in both 2023 and 2022, prior to the introduction of the EPL, was 40% (2022: 40%) consisting of a Ring Fence Corporation Tax rate of 30%
and the supplementary charge of 10%. Items affecting the tax charge
include a 10% uplift on ring fence losses, Ring Fence Expenditure
Supplement increasing the losses available to offset future profits
subject to Ring Fence Corporation Tax and
Supplementary Charge. In addition, investment allowance, a 62.5%
uplift on capital expenditure, is available reducing the profits
subject to the supplementary charge only. The credit arising in
2023 of $42.0 million was principally due the impairment of the
Alba field due to forecast future production volumes. Petroleum
Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in
the UK however adjustments to recognised deferred PRT assets are
made to reflect updated expectations of reversal against profits
subject to the 0% PRT rate. The EPL was enacted in July 2022 with
effect from 26 May 2022, at a headline rate of 25% which increased
the effective UK Ring Fenced oil and gas rate to 65% until 2025, resulting in additional current
and deferred
tax charges
in the
year to
31 December
2022. Further
changes to
the EPL
were announced
on 17
November 2022
and enacted
in December
2022 whereby the Levy was increased to 35%
from 1 January 2023 until 31 March 2028, increasing the effective
UK Ring Fenced oil and gas tax rate to 75% resulting in an
additional deferred tax charge during the year to 31 December
2022.
Deferred tax at 31 December relates to the following:
|
2023
|
2022
|
US$'000
|
US$'000
|
Deferred corporation tax liability
|
(1,944,941)
|
(2,258,813)
|
Deferred corporation tax asset
|
2,480,921
|
2,629,548
|
Deferred PRT asset
|
91,759
|
21,721
|
Net deferred tax asset
|
627,738
|
392,456
|
Deferred tax assets primarily
relate to decommissioning liabilities, brought forward tax losses
and accumulated losses and profits related to derivative contracts.
Deferred tax liabilities primarily relate to accelerated capital
allowances on property, plant and
equipment and accumulated losses and profits related to derivative
contracts. Deferred tax balances are presented net as they arise in
the same jurisdiction and the Group has a legally-enforceable right
to offset as well as an intention to
settle on a net basis.
Non-oil and gas losses of $251
million (2022: $156 million), of which there is no expiry date,
have not been recognised for deferred tax purposes as it is not
sufficiently certain that there will be future non-oil and gas
profits to offset these losses.
The net movement on deferred
tax in
the statement of
financial position, including
deferred PRT, is
as follows:
|
2023
US$'000
|
2022
US$'000
|
At 1 January
|
392,456
|
220,918
|
Profit or loss credit/(charge)
|
303,767
|
(1,024,889)
|
Other comprehensive income charge
|
(71,700)
|
(200,455)
|
Deferred tax on
decommissioning reimbursements (note
11)
|
3,214
|
-
|
Business combinations (note 17)
|
-
|
1,396,882
|
At 31 December
|
627,738
|
392,456
|
The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement
of comprehensive
income relates
to the
following:
|
|
|
|
2023
US$'000
|
2022
US$'000
|
Accelerated capital allowances
|
438,359
|
(490,246)
|
Tax losses
|
(216,937)
|
(386,819)
|
Decommissioning
provision
|
52,440
|
(124,598)
|
Deferred PRT
|
(28,015)
|
4,173
|
Hedging
|
(101,744)
|
(226,040)
|
Share schemes
|
3,978
|
-
|
Investment allowances
|
13,950
|
8,617
|
|
162,030
|
(1,214,913)
|
27. Taxation continued
|
|
|
|
|
Deferred corporation tax on
|
Accelerated tax
|
|
Gross deferred corporation tax
liabilities
|
|
Hedges US$'000
|
deferred
PRT
US$'000
|
depreciation
US$'000
|
Total US$'000
|
At 1 January 2022
|
|
-
|
(12,861)
|
(675,279)
|
(688,140)
|
Prior year adjustment
|
|
-
|
-
|
(4,347)
|
(4,347)
|
Reclassification of
decommissioning asset
|
|
-
|
-
|
(436,771)
|
(436,771)
|
Business combinations
|
|
-
|
-
|
(647,743)
|
(647,743)
|
Origination and reversal of temporary differences
|
|
-
|
4,173
|
(485,985)
|
(481,812)
|
At 31 December 2022 and 1 January 2023
|
|
-
|
(8,688)
|
(2,250,125)
|
(2,258,813)
|
Reclass to
deferred corporation tax assets
|
|
(8,678)
|
-
|
-
|
(8,678)
|
Prior year adjustment
|
|
2,721
|
-
|
8,307
|
11,028
|
Origination and reversal of temporary differences
|
|
(101,744)
|
(28,015)
|
441,281
|
311,522
|
At 31 December
2023
|
|
(107,701)
|
(36,703)
|
(1,800,537)
|
(1,944,941)
|
|
Share
schemes
|
Decommissioning
provision
|
Tax losses
|
Hedges
|
Total
|
Gross deferred corporation tax
assets
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
At 1 January 2022
|
-
|
197,666
|
500,282
|
178,956
|
876,904
|
Prior year adjustment
|
-
|
-
|
3,706
|
-
|
3,706
|
Reclassification
of decommissioning asset
|
-
|
436,772
|
-
|
-
|
436,772
|
Business combinations
|
-
|
156,212
|
1,858,706
|
38,406
|
2,053,324
|
Origination and reversal of temporary differences
|
-
|
(124,598)
|
(390,520)
|
(226,040)
|
(741,158)
|
At 31 December 2022 and 1 January 2023
|
-
|
666,052
|
1,972,174
|
(8,678)
|
2,629,548
|
Reclass from deferred corporation
tax liabilities
|
-
|
-
|
-
|
8,678
|
8,678
|
Prior year adjustment
|
177
|
-
|
(4,989)
|
-
|
(4,812)
|
Origination and reversal of temporary differences
|
3,802
|
55,654
|
(211,949)
|
-
|
(152,493)
|
At 31 December
2023
|
3,979
|
721,706
|
1,755,236
|
-
|
2,480,921
|
|
Total
|
Deferred PRT asset
|
US$'000
|
At 1 January 2022
|
32,154
|
Origination and reversal of temporary differences
|
(10,433)
|
At 31 December 2022 and 1 January 2023
|
21,721
|
Origination and reversal of temporary differences
|
70,037
|
At 31 December
2023
|
91,758
|
The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2023 of $536 million and $92 million respectively (2022:
$371 million
and $21
million respectively) are
supported by
estimates of
the Group's future taxable income, based on the
same price and cost assumptions as used for impairment testing. The
Group has undertaken a restructuring exercise to move certain
assets between Group entities which has now been
substantially completed. The recoverability of
the deferred corporation tax asset is supported by this
restructuring. The DTA relating to losses within the Group are
expected to unwind against taxable profits before the end of
2029.
An EPL or 'Levy' was enacted on 14
July 2022 applying a Levy of 25% to the profits of oil and gas
companies until 31 December 2025 or earlier if prices return to
normalised levels. On 17 November 2022, the Levy was increased
to 35% and extended to 31 March 2028
regardless of oil and gas prices. The Levy is charged upon oil and
gas profits calculated on the same basis as Ring Fence Corporation
Tax (RFCT), however, excludes relief for decommissioning and
finance costs. RFCT losses and investment
allowance are not available to offset the EPL. On 9 June 2023 an
Energy Security Investment Mechanism price floor was announced
which would remove the EPL if both average oil and gas prices fall to, or below, $71.40 per barrel for oil and £0.54 per therm for gas, for two consecutive quarters.
It is
not currently
forecast that
this price
floor will
be met
for both
oil and
gas prices
and therefore
there is
currently no
impact from this on tax carrying values.
On 6 March 2024 an extension of the Levy until 31 March 2029 was
announced. If this had been enacted at the balance sheet date, it
is estimated that this would have increased the deferred tax
liability by $112.2 million.
On 20
June 2023, Finance (No. 2) Act 2023 was substantially enacted in
the UK, introducing a global minimum effective tax rate of 15%. The
legislation implements a domestic top-up tax and a multinational
top-up tax, effective for all accounting periods starting on or
after 31 December 2023. The Group does not anticipate that the
adoption of this will have a material impact as the prevailing rate
of tax in the United Kingdom is in excess of the 15% minimum rate.
The Group has applied the exemption under IAS 12 to recognising and
disclosing information about deferred tax assets and liabilities
related to top-up income taxes and therefore there is no impact on
the tax values reported.
28. Commitments and contingencies
|
2023
US$'000
|
2022
US$'000
|
Capital commitments
|
|
|
Capital commitments incurred
jointly with other venturers
(Group's share)
|
506,959
|
52,309
|
The Group's capital expenditure is
driven largely by full phase expenditure on existing producing
fields, new development projects and appraisal and development
activities. As of 31 December 2023, the Group had
commitments for future capital expenditure amounting
to $507
million (2022:
$52.3 million).
The key
component of
this relates
to Rosebank,
following FID
approval in
September 2023.
Additionally, there are commitments in relation to AFEs (authorisations for
expenditure) signed for activities on Captain enhanced oil
extraction.
Contingencies
The Group enters into letters of
credit and surety bonds to provide security for the Group's
obligations under certain field and bi-lateral decommissioning
security agreements, or equivalent, Sullom Voe Terminal Tariff
Agreements and deferred payment obligations. The instruments are either held by the Law Debenture Trust Corporation
P.L.C. under
a trust
deed or
EnQuest Heather
Limited, as
SVT Terminal
Operator. At
31 December
2023 the
Group had
$450 million (31 December 2022: $469 million) in
letters of credit and surety bonds outstanding relating to security
obligations under certain decommissioning and security
agreements.
29.
Financial instruments
To estimate the fair value of financial instruments, the Group uses quoted market prices when available, or industry accepted
third-party models and valuation methodologies
that utilise
observable market
data. In
addition to
market information, the Group incorporates
transaction specific details that market participants would
utilise in
a fair
value measurement, including
the impact
of non-performance risk.
The Group
characterises inputs used in determining fair value using a hierarchy that prioritises inputs
depending on
the degree
to which
they are
observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realised or settled in a current market transaction. The three levels of the fair value
hierarchy are as follows:
•
Level 1 - inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity
derivatives). Active markets are those in which transactions occur
in sufficient
frequency and
volume to
provide pricing
information on
an ongoing
basis.
•
Level 2 - inputs other than quoted prices
included within Level 1 that are observable, either directly or
indirectly, as of the reporting date. Level 2 valuations are based
on inputs, including quoted forward prices for commodities,
market interest rates and volatility factors,
which can
be observed
or corroborated
in the
marketplace. The
Group obtains
information from
sources such
as the
New York
Mercantile Exchange and independent price
publications.
•
Level 3 - inputs that
are less observable, unavailable or where the observable data does
not support the majority of the instrument's fair value.
In forming estimates,
the Group
utilises the
most observable
inputs available
for valuation
purposes. If
a fair
value measurement
reflects inputs
of different
levels within
the hierarchy,
the measurement
is categorised
based upon
the lowest level of input that is
significant to the fair value measurement. The valuation of
over-the-counter financial swaps and collars is based on similar
transactions observable in active markets or industry standard
models that primarily rely on market observable inputs.
Substantially all
of the
assumptions for
industry standard
models are
observable in
active markets
throughout the
full term
of the
instrument. These
are categorised
as Level
2.
Gains or losses on financial instruments, that
are not
hedge accounted
for, are
recorded through
the 'other
gains and
losses' line
in the
consolidated statement of profit or loss. Credit valuation adjustments
(CVA) and
debit valuation
adjustments (DVA)
are calculated
for each
trade using
two key
inputs, being
future exposures
and credit
spreads (incorporating both
probability of
default and
loss given
default). Future
exposures have
been estimated
using an
expected exposure-based approach
over the
lifetime of
the trades.
For the
risk associated
with counterparties, the
credit spread
is calculated
using market
observable credit
default spreads.
For the
own credit
risk, the
credit spread
is calculated
using reference
to a senior unsecured quoted publicly traded bond of the parent entity using appropriate
tenor adjustments, except
for out-of-the-money derivatives
with counterparties which
are in
the Group's
RBL. These
derivatives rank
higher than
those with
other counterparties as
they are
fully secured
as part
of the
RBL agreement.
Therefore for
the own
risk credit
risk adjustment
(DVA) it
has been
estimated that
the loss
given default
is zero
and hence
there is
no DVA
recognised for
those derivatives
which are
with counterparties of
the RBL.
All of the Group's assets are pledged as security
against borrowings.
The accounting classification
of each
category of
financial instruments and their carrying amounts as at 31 December 2023 are set out below:
|
Measured at amortised
cost
|
Mandatorily
measured at fair value
through
profit or loss
|
Derivatives
designated
in hedge
relationships
|
Total
carrying
amount
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
Financial assets
|
|
|
|
|
Cash and cash equivalents
|
153,215
|
-
|
-
|
153,215
|
Trade and other receivables
|
330,351
|
-
|
-
|
330,351
|
Derivative financial instruments
|
-
|
2,782
|
154,525
|
157,307
|
Financial liabilities
|
|
|
|
|
Borrowings
|
(748,151)
|
-
|
-
|
(748,151)
|
Trade and other payables
|
(343,279)
|
-
|
-
|
(343,279)
|
Lease liability
|
(20,559)
|
-
|
-
|
(20,559)
|
Contingent and deferred consideration
|
(63,979)
|
(296,390)
|
-
|
(360,369)
|
Derivative financial instruments
|
-
|
(10,373)
|
(3,335)
|
(13,708)
|
|
|
|
|
(845,193)
|
The accounting classification of
each category
of financial
instruments and
their carrying
amounts as
at 31
December 2022
are set
out below:
|
|
|
Measured
at
|
Mandatorily measured at fair value
through
|
Derivatives designated
in hedge
|
Total carrying
|
|
amortised cost
US$'000
|
profit
or loss
US$'000
|
relationships
US$'000
|
amount US$'000
|
Financial assets
|
|
|
|
|
Cash and cash equivalents
|
253,822
|
-
|
-
|
253,822
|
Trade and other receivables
|
359,994
|
-
|
-
|
359,994
|
Derivative financial instruments
|
-
|
7,125
|
164,924
|
172,049
|
Financial liabilities
|
|
|
|
|
Borrowings
|
(1,213,731)
|
-
|
-
|
(1,213,731)
|
Trade and other payables
|
(618,460)
|
-
|
-
|
(618,460)
|
Lease liability
|
(58,858)
|
-
|
-
|
(58,858)
|
Contingent and deferred consideration
|
(67,904)
|
(258,896)
|
-
|
(326,800)
|
Derivative financial instruments
|
-
|
(57,546)
|
(106,563)
|
(164,109)
|
|
|
|
|
(1,596,093)
|
The following table presents the Group's material financial instruments
measured at
fair value
for each
hierarchy level
as at
31 December
2023:
|
|
|
|
|
|
Level 1
|
Level 2
|
Level 3
|
Total Fair
Value
|
|
US$'000
|
US$'000
|
US$'000
|
US$'000
|
Contingent consideration
(note 25)
|
-
|
(24,039)
|
(272,351)
|
(296,390)
|
Derivative financial instrument
asset
|
-
|
157,307
|
-
|
157,307
|
Derivative financial instrument
liability
|
-
|
(13,708)
|
-
|
(13,708)
|
Movements in level 3 financial instruments in the 12 months to 31 December 2023 were as follows:
|
|
|
|
|
|
|
|
|
US$'000
|
At 1 January 2023
|
|
|
|
(223,246)
|
Additions
|
|
|
|
(26,872)
|
Cash settlement
|
|
|
|
-
|
Accretion
|
|
|
|
(8,799)
|
Changes in fair value
|
|
|
|
(13,434)
|
At 31 December 2023
|
|
|
|
(272,351)
|
Management has considered alternative scenarios
to assess
the valuation
of the
contingent consideration including,
but not
limited to,
the key
accounting estimate relating
to the
oil price.
A reduction
or increase
in the
price assumptions
of 20%
are considered
to be
reasonably possible changes.
A 20%
reduction in
the oil
price would
result in
a decrease
in contingent
consideration of
$23.3 million
(2022: $36.4
million). A
20% increase
in the
oil price
would lead
to an
increase in contingent consideration of $41.0
million (2022: $26.4 million).
The level three contingent consideration
is valued
based on
the probability
of the
events occurring
("trigger events") as set out in note 17. The forecast cash flows in the event of the trigger event occurring are discounted at a rate of 4.6% (2022: 4.25%).
The following table summarises the sensitivity of 20% change in probability of trigger event occurring and conditions being met for payment of contingent consideration, with
all other
variables held
constant, of
the Group's
profit before
tax due
to changes
in the
carrying value
of level
3 financial
instruments at
the reporting
date. The
impact on
equity is
the same
as the
impact on
profit before
tax.
Change in probability
|
2023
US$'000
|
2022
US$'000
|
20% decrease in
probability
|
97,119
|
87,080
|
20% increase in probability
|
(84,086)
|
(83,612)
|
The following table summarises the sensitivity of 1% decrease in discount rate, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date. The impact on equity is the same as the impact on profit before tax.
Change in discount rate
|
2023
US$'000
|
2022
US$'000
|
1% decrease in discount rate
|
(5,284)
|
(4,374)
|
A 1% increase in discount rate would
have the equal
but opposite effect to the amounts shown above, on the
basis that all
other variables remain
constant.
|
|
|
Financial instruments of the Group
consist mainly of cash and cash equivalents, receivables, payables,
loans and financial derivative contracts, all of which are included
in the financial statements. At 31 December 2023 and 31
December 2022, financial instruments and the carrying amounts
reported on the balance sheet approximates the fair values with the
exception of borrowings. The carrying amount of borrowing is at
amortised cost of $748.2 million (2022: $1,213.7 million)
and the
equivalent fair
value is
$781.4 million
(2022: $1,257.9
million) per
level 1
of the
fair value
hierarchy.
The table below presents the total gain on financial
instruments that has been disclosed through the consolidated
statement of profit or loss:
Cash flow hedge reserve
The table below presents the movement in financial
instruments that has been disclosed through the statement of
comprehensive income relating to the cash flow hedge reserve:
29. Financial
instruments continued
Cost of hedging
reserve
The table below presents the movement in financial
instruments that has been disclosed through the statement of
comprehensive income relating to the cost of hedging reserve:
The Group has identified that it is exposed
principally to these areas of market risk.
i) Commodity risk
Commodity price risk related to crude oil prices is the Group's most significant market risk exposure. Crude oil prices and quality differentials are
influenced by
worldwide factors
such as
OPEC actions,
political events
and supply and
demand fundamentals. The Group is also exposed to natural gas price
movements on uncontracted gas sales. Natural gas prices, in
addition to the worldwide factors noted above, can also be
influenced by local market conditions. The
Group's expenditures are subject to the effects of inflation, and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. The Group may periodically use different types of derivative instruments to manage its exposure to price volatility,
thus mitigating
fluctuations in
commodity-related cash flows.
In all periods presented the Group has designated certain
commodity options
as a cash flow hedge of highly probable sales. Because the critical terms (i.e. the quantity, maturity and underlying price)
of the
commodity option
and their
corresponding hedged items are the same, the Group performs a qualitative assessment of effectiveness and
it is
expected that
the intrinsic
value of
the commodity
option and
the value
of the
corresponding hedged items will systematically
change in
opposite direction in response to movements in the price of underlying commodity if the price of the commodity increases
above the
strike price
of the
derivative. The
main source
of hedge
ineffectiveness in these hedge relationships
is the
effect of
the counterparty
and the
Group's own
credit risk
on the
fair value
of the
option contracts,
which is
not reflected
in the
fair value
of the
hedged item
and if
the forecast
transaction will
happen earlier
or later
than originally
expected. There
was no
hedge ineffectiveness in
the current
or prior
year.
The Group's target is to hedge oil and gas prices up to a maximum of 75% of the next 12 months' production on a rolling annual basis, up to 50% in the following 12-month period and 25% in the subsequent 12-month
period. On
a rolling
12-month period
under the
RBL, the
Group is
required to
hedge a
minimum of
70% of
volumes of
net RBL
entitlement production expected
to be
produced in
the next
12 months,
and 50%
of volumes
of net
RBL entitlement
produced for
the following
12 months
on a best-effort basis.
The below represents total commodity hedges in place at the 2023 year-end:
Derivative
|
Term
|
Volume
|
|
Average price
|
Oil swaps
|
Jan 24 - Dec 24
|
1,931,500
|
bbls
|
$82/bbl
|
Oil collars
|
Jan 24 - Dec 24
|
2,744,000
|
bbls
|
$75/bbl floor
-
$87/bbl ceiling
|
Gas swaps
|
Jan 24 - Dec 24
|
53,175,000
|
therms
|
140p/therm
|
Gas swaps
|
Jan 25 - Sep 25
|
18,225,000
|
therms
|
120p/therm
|
Gas collars
|
Jan 24 - Dec 24
|
123,350,000
|
therms
|
135p/therm floor - 210p/therm ceiling
|
Gas collars
|
Jan 25 - Mar 25
|
9,000,000
|
therms
|
130/therm floor
-
185p/therm ceiling
|
The below represents total commodity hedges in place at the 2022 year-end:
|
|
Derivative
|
Term
|
Volume
|
|
Average price
|
Oil swaps
|
Jan 23 - Jun 24
|
3,390,500
|
bbls
|
$70/bbl
|
Oil collars
|
Jan 23 - Dec 23
|
4,560,000
|
bbls
|
$68/bbl floor -
$91/bbl ceiling
|
Gas swaps
|
Jan 23 - Jun 24
|
104,585,000
|
therms
|
188p/therm
|
Gas puts
|
Apr 23 - Sep 23
|
9,150,000
|
therms
|
220p/therm
|
Gas collars
|
Jan 23 - Mar 24
|
100,200,000
|
therms
|
244p/therm floor - 479p/therm ceiling
|
The following table summarises the sensitivity of 20% decrease in realised commodity prices,
with all
other variables
held constant,
of the
Group's profit
before tax
due to
changes in
the carrying
value of
monetary assets
and liabilities
at the reporting date.
The impact on equity is the same as the impact on profit before
tax.
Change in realised commodity
price
|
2023
US$'000
|
2022
US$'000
|
20% decrease in realised oil
price
|
(177,151)
|
(246,914)
|
20% decrease in realised gas price
|
(146,794)
|
(330,285)
|
A 20% increase in realised commodity prices would
have the equal but opposite effect to the amounts shown above, on
the basis that all other variables remain constant.
ii) Interest risk
The calculation of interest
payments for the RBL facility and bp unsecured loan incorporate
SOFR. The Group is therefore exposed to interest rate risk to the
extent that SOFR may fluctuate. The Group mitigates the risk of
SOFR fluctuations by entering into interest rate swaps on floating rates.
There were no material
interest rate financial
instruments in place at 31 December 2023.
The below represents interest rate
financial instruments in place at the 2022 year end:
Derivative
|
Term
|
Value
|
Rate
|
Interest rate swap (floating to
fixed)
|
Jan 22 -
Dec 23
|
$150 million
|
0.398%
|
The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date.
Increase of 250 basis
points
(22,370)
(11,126)
A decrease in 250 basis points in interest rates
would have the equal but opposite effect to the amounts shown
above, on the basis that all other variables remain constant.
iii)
Foreign exchange
rate risk
The Group is exposed to foreign exchange risks to the extent it transacts in various currencies, while
measuring and
reporting its
results in
US Dollars.
Since time
passes between
the recording
of a receivable or payable transaction
and its
collection or payment, the Group is exposed to
gains or losses on non-US Dollar amounts and on balance sheet
translation of monetary accounts denominated in non-US Dollar
amounts upon spot rate fluctuations from year-to-year.
29. Financial
instruments continued
As at 31 December 2023 the Group had an average of £10.2 million per quarter hedged at an average forward rate of $1.219:£1 for the period January to December 2024. As at 31 December 2023 the Group had an average of £30.3 million per quarter hedged at
an average collar floor of $1.200:£1 and average collar ceiling of
$1.230:£1 for the period January to December 2024.
As at 31 December 2022 the Group had an average of £5.5 million per quarter hedged at an average forward rate of $1.265:£1 for the period January to December 2023. As at 31 December 2022 the Group had no open FX collars.
The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax. The Group's exposure to foreign currency changes for all other currencies is not material.
Change in Sterling foreign
exchange rate
10% weakening
of Sterling
against the
US Dollar
(123,033)
(139,633)
A 10% strengthening of Sterling against the US
Dollar would have had the equal but opposite effect to the amounts
shown above, on the basis that all other variables remain
constant.
iv) Credit risk
The majority of the Group's trade and other receivables
are with
customers in
the oil
and gas
industry are
subject to
normal industry
credit risks
and are
unsecured. Customers of the Group are mainly oil and gas majors with good credit ratings and low credit risk.
Oil production from Stella, Vorlich, Jade and Abigail fields is
sold to ENI, Columba is sold to Repsol, Mariner to Equinor ASA,
Pierce to Shell International Trading, and Captain, Alba, Cook,
Forties (including MonArb) and
Schiehallion fields to BP Oil International. Forties fields
(including MonArb), Stella, Vorlich, Jade and Abigail gas is sold
to BP Gas Marketing. Cook gas is sold to Shell International
Trading and Esso Exploration,
and Schiehallion to EnQuest.
The Group assesses partners' creditworthiness
before entering
into farm-in
or joint
venture agreements. In the past, the Group has not experienced credit
loss in
the collection
of accounts
receivable. As
the Group's
exploration, drilling and development activities
expand with
existing and
new joint
venture partners,
the Group
will assess
and continuously
update its
management of
associated credit
risk and
related procedures.
The Group regularly monitors all customer receivable
balances outstanding in excess of 90 days for ECLs. As at 31 December 2023, substantially
all accounts
receivables are
current, being
defined as
less than
90 days.
The Group
has no
allowance for
doubtful accounts
as at
31 December
2023 (31
December 2022:
$nil).
The Group may be exposed to certain losses in the event that counterparties
to derivative
financial instruments are unable to meet the terms of the contracts. The Group's exposure is limited to those counterparties
holding derivative contracts
with positive
fair values
at the
reporting date
and these
counterparties represent a very low risk of default. As at 31 December 2023, the Group's exposure is $nil (31 December 2022: $nil).
Credit valuation adjustments
(CVA) and
debit valuation
adjustments (DVA)
are calculated
for each
trade using
two key
inputs, being
future exposures
and credit
spreads (incorporating both
probability of
default and
loss-given default). Future exposures have been estimated using an expected exposure-based
approach over
the lifetime
of the
trades. For
the risk
associated with
counterparties, the credit spread is calculated using market observable
credit default
spreads. For
the own
credit risk,
the credit
spread is
calculated using
reference to
a senior
unsecured quoted
publicly traded
bond of
the parent
entity using
appropriate tenor
adjustments, except for out-of-the-money derivatives
with counterparties which
are in
the Group's
RBL. These
derivatives rank
higher than
those with
other counterparties as
they are
fully secured
as part
of the
RBL agreement.
Therefore for
the own
risk credit
risk adjustment
(DVA) it
has been
estimated that
the loss
given default
is zero
and hence
there is
no DVA
recognised for
those derivatives
which are
with counterparties of
the RBL.
The Group also has credit risk arising from cash and
cash equivalents held with banks and financial institutions. The
maximum credit exposure associated with financial assets is the
carrying values.
v) Liquidity risk
Liquidity risk includes the risk that as a result of its operational liquidity
requirements the
Group will
not have
sufficient funds
to settle
a transaction
on the
due date.
The Group
manages liquidity
risk by
maintaining adequate cash reserves, banking
facilities, and
by considering
medium and
future requirements by continuously monitoring
forecast and
actual cash
flows. The
Group considers
the maturity
profiles of
its financial
assets and
liabilities. As
at 31
December 2022
and 2023
substantially all
accounts payable
are current.
The following table shows the timing of cash
outflows, including future interest, relating to financial
liabilities, excluding derivatives, at 31 December 2023:
The following table details the Group's liquidity
analysis for
its derivative
financial instruments based
on contractual
maturities. The
table has
been drawn
up based
on the
undiscounted net
cash inflows
and outflows
on derivative
instruments that settle on a net basis, and the undiscounted gross
inflows and outflows on those derivatives that require gross
settlement. When the amount payable or receivable is not fixed, the
amount disclosed has been determined by reference
to the projected interest rates as illustrated by the yield curves
existing at the reporting date.
At 31 December 2023
|
US$'000
|
US$'000
|
$'000
|
Net-settled (derivative
liabilities):
|
|
|
|
Commodity options
|
(2,290)
|
-
|
(2,290)
|
|
|
|
|
Gross-settled:
|
|
|
|
Foreign exchange forwards
- gross outflows
|
(113,342)
|
-
|
(113,342)
|
Foreign exchange
collars - gross
outflows
|
(155,071)
|
-
|
(155,071)
|
|
(270,703)
|
-
|
(270,703)
|
|
|
Within 1 year
Within 2 to 5 years
Total
29. Financial
instruments continued
At 31 December 2022
|
Within1
Year US$'000
|
Within
2to 5 years
US$'000
|
Total
$'000
|
Net-settled (derivative
liabilities):
|
|
|
|
Commodity options
|
(51,654)
|
(15,402)
|
(67,056)
|
|
|
|
|
Gross-settled:
|
|
|
|
Foreign exchange forwards
- gross outflows
|
(83,529)
|
(107,235)
|
(190,764)
|
Foreign exchange
collars - gross
outflows
|
-
|
-
|
-
|
|
(135,183)
|
(122,637)
|
(257,820)
|
vi) Capital management
The Group's objectives
when managing
capital are
to safeguard
the Group's
ability to
continue as
a going
concern in
order to
provide returns
to shareholders
and benefits
for other
stakeholders and
to maintain
an optimal
capital structure
to reduce
the cost
of capital.
The Group
regularly monitors the capital requirements
of the
business over
the short,
medium and
long-term, in
order to
enable it
to foresee
when additional
capital will
be required.
The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates eroding the Group's financial results.
30. Derivative financial
instruments
The net carrying amount of each category of
derivative is set out below:
|
2023
US$'000
|
2022
US$'000
|
Oil swaps - cash flow hedge
|
9,913
|
(28,685)
|
Oil swaps - non-cash flow
hedge
|
-
|
(15,027)
|
Oil collars - cash flow
hedge
|
7,434
|
(21,983)
|
Gas swaps - cash flow hedge
|
47,232
|
19,797
|
Gas swaps - non-cash flow
hedge
|
(2,290)
|
(29,271)
|
Gas puts - cash flow hedge
|
-
|
9,746
|
Gas collars - cash flow
hedge
|
89,944
|
79,489
|
Interest rate swaps
- non-cash
flow hedge
|
637
|
7,125
|
FX forwards - non-cash flow
hedge
|
(3,961)
|
(13,250)
|
FX collars - cash flow
hedge
|
(3,335)
|
-
|
FX collars - non-cash flow
hedge
|
(1,975)
|
-
|
|
143,599
|
7,941
|
30. Derivative
financial instruments
continued
|
|
|
Maturity analysis of derivative
financial instruments
|
2023
US$'000
|
2022
US$'000
|
Non-current assets
|
17,810
|
21,191
|
Current assets
|
139,497
|
150,858
|
Non-current liabilities
|
-
|
(27,440)
|
Current liabilities
|
(13,708)
|
(136,668)
|
|
143,599
|
7,941
|
The fair value of commodity derivatives is estimated using a net present value model (commodity swaps) or an appropriate option valuation model (options and collars). These contracts are valued using observable market pricing data including volatilities. A 20% reduction in future commodity prices,
with all
other assumptions
held constant,
would result
in a decrease in the fair value of derivatives of $113 million (2022: $179 million). A 20% increase in future commodity prices,
with all
other assumptions
held constant,
would result
in an
increase in
the intrinsic
value of
option derivative
instruments at
31 December
2023 of
$88 million
(2022: $188
million).
Derivative financial instruments
that are
with counterparties included
within the
RBL are
subject to
Master Netting
Agreements, this
includes the
majority of
the Group's
derivative financial instruments as at
31 December 2023 and 2022.
Financial instruments subject to enforceable master
netting agreements and similar agreements at 31 December 2023 are
detailed below:
|
Amount recognised in balance
sheet
|
Related amounts not set off
in balance
sheet
|
Net amount
|
$'000
|
$'000
|
$'000
|
Derivative assets
|
157,306
|
(4,436)
|
152,870
|
Derivative liabilities
|
(13,708)
|
4,436
|
(9,272)
|
Financial instruments subject to enforceable master
netting agreements and similar agreements at 31 December 2022 are
detailed below:
|
Amount recognised in balance
sheet
|
Related amounts not set off
in balance
sheet
|
Net amount
|
$'000
|
$'000
|
$'000
|
Derivative assets
|
172,049
|
(33,117)
|
138,932
|
Derivative liabilities
|
(164,109)
|
33,117
|
(130,992)
|
31. Related-party transactions
The immediate parent undertaking
is DKL Energy Limited (incorporated in Jersey) who owns 88.55% of
the issued share capital of Ithaca Energy plc. The registered
office address of the DKL Energy Limited is 47 Esplanade, St
Helier, Jersey, JE1 0BD.
The ultimate parent of the Group is Delek Group Limited (incorporated
in Israel),
an independent
E&P company
listed on
the Tel
Aviv Stock
Exchange. The
Group and
Delek's ultimate
controlling party
is Mr
Itshak Sharon
Tshuva.
31. Related-party
transactions continued
The consolidated financial statements include the
financial information of the Group, which comprises the Company and
the subsidiaries listed in the following table:
% equity
interest at 31 December
|
Registered office
|
Country of incorporation
|
2023
|
2022
|
|
Ithaca Energy (E&P) Limited
|
1
|
Jersey
|
100%
|
100%
|
|
Ithaca
Energy (UK) Limited
|
2
|
Scotland
|
100%
|
100%
|
|
Ithaca
Minerals (North Sea) Limited
|
2
|
Scotland
|
100%
|
100%
|
|
Ithaca
Energy (Holdings) Limited
|
3
|
Bermuda
|
100%
|
100%
|
|
Ithaca Energy Holdings (UK) Limited
|
2
|
Scotland
|
100%
|
100%
|
|
Ithaca Energy (North Sea) PLC
|
2
|
Scotland
|
100%
|
100%
|
|
Ithaca Oil and Gas Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca Petroleum Ltd
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca Causeway Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca
Gamma Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca Alpha (NI) Limited
|
5
|
Northern Ireland
|
100%
|
100%
|
|
Ithaca
Epsilon Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca Exploration
Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca Petroleum EHF
|
6
|
Iceland
|
100%
|
100%
|
|
Ithaca Dorset Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca SP
UK Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca GSA
Holdings Limited
|
1
|
Jersey
|
100%
|
100%
|
|
Ithaca GSA
Limited
|
1
|
Jersey
|
100%
|
100%
|
|
Ithaca Energy Developments
UK Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
FPF-1 Limited
|
7
|
Jersey
|
100%
|
100%
|
|
Ithaca MA
Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca SP
Bonds PLC
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca SP
Finance Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca SP (Holdings) Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca SP (E&P) Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca SP (O&G) Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca SPE Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
Ithaca Zeta
Limited
|
4
|
England and Wales
|
100%
|
100%
|
|
31. Related
party transactions
continued
Transactions between subsidiaries
are eliminated
on consolidation.
1. 47 Esplanade, St Helier, Jersey, JE1
0BD
2. 13 Queen's Road, Aberdeen, Scotland AB15 4YL
3. Canon's Court, 22 Victoria Street, Hamilton HM 12, Bermuda
4. Pinsent Masons LLP, 1 Park Row, Leeds, England, LS1 5AB
5. Pinsent Masons LLP, The Soloist, 1 Lanyon Place, Belfast, BT1 3LP
6. Borgartúni 26, 105 Reykjavík, Iceland
7. 26 New
Street, St Helier, Jersey, JE2 3RA
Amounts owed to Delek Group Limited
An outstanding interest
amount of
$29 million
with respect
to a historic related party loan with Delek Group Limited was repaid in full on 4 October 2022.
The movement in capital loan notes during the year ended 31 December 2022 related to imputed interest of $18 million on the unwind of the capital contribution
and subsequent
settlement of
the $392
million balance
under a waiver agreement.
On 8 November 2022, a waiver agreement was signed by DKL Energy Limited, the immediate parent company of Ithaca Energy plc at that time, to partially waive a capital note balance and a subordinated loan
balance (including interest)
totalling $469
million, such
that, post-IPO
these balances
would no
longer be
due from
Ithaca Energy
plc.
A loan waiver of $181.9 million was recognised as a
Capital Contribution on equity in the year to 31 December
2022.
Key management personnel
The following table provides remuneration to key
management personnel, being persons having direct or indirect
authority or responsibility of the Group, for the periods ended 31
December 2023 and 2022:
Key management personnel
|
2023
US$'000
|
2022
US$'000
|
Salaries and short-term employee
benefits
|
5,741
|
4,590
|
Payments made in lieu of pension contributions
|
249
|
229
|
Company pension contributions
|
106
|
106
|
Share-based payment
|
5,863
|
12,623
|
|
11,959
|
17,548
|
Further detail regarding share-based payments
received by key management personnel is set out below.
32. Share-based payments
The charge for share-based payment
transactions in
the year
to 31
December 2023
was $16.4
million (2022:
$14.1 million).
Like other
elements of
compensation, this charge is processed through the time-writing system
which allocates
costs, based
on time
spent by
individuals, to
various activities within
the Ithaca
Energy plc
Group. Part
of this
cost is
therefore capitalised as directly attributable
to capital
projects and
part is
charged to
the statement
of profit
or loss
as operating costs of
hydrocarbon activities, pre-licence exploration costs or
administrative expenses.
32. Share-based
payments continued
Long-Term Incentive Plans (LTIPs)
Outstanding share options under LTIPs were as follows:
All LTIP awards are nil-cost
options. There are no performance conditions attaching to the
Heritage and At-IPO awards. Details of the performance conditions
of the 2022 LTIP are set out in the Directors' remuneration
report. The fair values of all the LTIP awards were determined based on the share price on date of award. The Heritage awards vested over the period to 14 November 2023, the At-IPO awards vest in three equal tranches over the period to
14 November 2025 and the 2022 LTIP awards vest over the period to 1 April 2026. It is anticipated that future exercises of LTIP awards will be settled by equity. The total charge for LTIP share options in the year to 31 December 2023 was $12.9 million (2022: $0.6 million).
IPO-related share options
Under the terms section 11.6 of
the Prospectus, the Executive Chairman, Gilad Myerson (GM) and the
former Chief Executive Officer, Alan Bruce (AB) were entitled to an
award of share options worth 0.2% of the value of the
Group immediately
on IPO
which valued
these awards
at $5.0
million or
2,337,931 share
options each.
There are
no performance
conditions attaching to these share options. The exercise price of each of the share options is £0.01. Mr Myerson's share options vested immediately
on IPO
and Mr
Bruce's share
options were
vesting equally
over the
period 21
July 2021
to 20
July 2026.
During the
year to
31 December
2022 Mr
Myerson exercised
1,402,759 share
options. The
total charge
for IPO-related
share options
in the
year to
31 December
2023 was
$0.5 million
(2022: $7.3
million).
|
GM options
|
AB options
|
Total
|
Balance at 1 January 2023
|
935,172
|
2,337,931
|
3,273,103
|
Exercised during
the year
|
-
|
-
|
-
|
Balance at 31 December 2023
|
935,172
|
2,337,931
|
3,273,103
|
Exercisable at 31 December
2023
|
935,172
|
935,172
|
1,870,344
|
Share option exercise price
|
£0.01
|
£0.01
|
N/A
|
Weighted average remaining
life
|
N/A
|
N/A
|
N/A
|
Mr Bruce left the business on 4 January 2024 and, as part of his termination arrangements, retained
his 935,172
share options
which had
already vested.
|
|
|
|
32. Share-based
payments continued
Management Equity Plan
(MEP)
During the year to 31 December
2022, Mr Myerson was also awarded share options under a Management
Incentive Agreement (MIA) and Share Subscription and Bonus
Agreement (SSBA), comprising 100 B1 shares of $0.01 each
and 100
B2 shares
of $0.01
each. Following
the changes
in the
issued share
capital, as
detailed in
note 26,
in the
run up
to the
IPO, on
9 November
2022 these
share options
equated to
1,401,759 B1
shares of
£0.01 each
and 420,528
B2 shares of £0.01 each. Following the IPO Mr
Myerson elected to retain these options but in so doing did not
waive his right to receive the Aggregate Guaranteed Payment (AGP)
of $10.0 million less any special bonus payments since
September 2021.
During the year to 31 December
2023, Mr Myerson elected to receive the AGP and $8.0 million (AGP
of $10.0 million less special bonuses of $2.0 million) was paid to
him on 1 December 2023. As a result, the MEP share options,
which would otherwise have vested over the period
to 30 September 2026, were transferred back to the Company for nil
payment.
There were no performance conditions attaching to
either the MEP share options or the AGP.
The total share-based
payment charge
for MEP
arrangements in
the year
to 31
December 2023
was $3.0
million (2022:
$6.2 million).
The share-based payment reserve of
$15.5 million (2022: $4.9 million) reflects the opening balance of
$4.9 million (2022: $nil) plus the charge of $12.9 million (2022:
$0.6 million) for LTIPs plus the charge of $0.5 million
(2022: $7.3
million) for
IPO-related share
options less
the cost
of satisfying
exercises during
the year
of $2.8
million (2022:
$3.0 million).
33. Dividends
|
2023
US$'million
|
2022
US$'million
|
First interim dividend of $0.132 per ordinary share announced 16
February 2023 and paid 9 March 2023
|
133.0
|
-
|
Second interim dividend of $0.132 per ordinary share announced 23 August 2023 and paid 29 September 2023
|
133.0
|
-
|
Total dividends paid during
year ended 31
December 2023
|
266.0
|
-
|
Third interim dividend of $0.132 per ordinary share announced 21 March 2024 and payable in April 2024 (not accrued in the 2023 results)
|
134.0
|
-
|
Total dividends paid or
payable
relating to year
ended
31 December 2023
|
400.0
|
-
|
34. Subsequent
events
On 6 March 2024 it was announced that EPL will be extended by a further year to 31 March 2029. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million.
On 19 March 2024, the North Sea Transition Authority
sanctioned the
extension of
the licence
on the
Cambo field
to 31
March 2026.
On 26 March 2024, the Group signed an exclusivity agreement between ENI and Ithaca Energy covering substantially
all of ENI's UK upstream assets, excluding ENI CCUS and Irish sea assets, under which ENI has granted Ithaca exclusivity whilst a potential business
combination is
pursued. Under
the terms
of the
proposed business
combination ENI
is anticipated
to hold
between 38%
and 39%
of the
enlarged issued
share capital
of Ithaca
Energy following
completion. If this progresses further, it will
be subject to the issuance of both a Circular and a Prospectus and
the related shareholder approvals and will also be subject
to,amongst other things, regulatory approvals.
Alternative Performance
Measures
Non-GAAP measures
The Group uses certain performance
metrics that
are not
specifically defined under United Kingdon adopted International
Financial Reporting Standards
or other
generally accepted accounting
principles. These
measures are
considered to
be important
as they
track both
operational and
financial performance and are used to manage the business and to provide an objective comparison
to Ithaca
Energy's peer
group. These
non-GAAP measures
which are
presented in
the Annual
Report and
Accounts are
defined below:
Adjusted EBITDAX: earnings before interest, tax, put premiums on oil and gas derivative instruments,
revaluation of
derivative contracts, depletion
depreciation and
amortisation, impairment (charge)/reversal,
exploration and
evaluation expenditure, remeasurements of decommissioning
reimbursement receivables, fair value losses on contingent
consideration, gain on bargain purchase, transaction costs and
historic claims relating to acquisitions. The Group believes that adjusted EBITDAX is a useful measure for stakeholders because it is a measure closely tracked by management to evaluate the Group's operating
performance and
to make
financial, strategic and operating decisions
and because
it may
help stakeholders
to better
understand and
evaluate, in
the same
manner as
management, the
underlying trends
in the
Group's operational performance
on a a comparable basis, period-on-period.
Adjusted EBITDAX is reconciled to profit after tax as follows:
|
2023
|
2022
|
$m
|
$m
|
Profit after tax
|
215.6
|
1,031.5
|
Taxation charge
|
86.4
|
1,209.0
|
Gain on
bargain purchase
|
-
|
(1,335.2)
|
Depletion, depreciation and amortisation
|
740.3
|
662.9
|
Impairment charges
|
557.9
|
31.5
|
Net finance costs
|
184.0
|
203.0
|
Oil and gas put premiums
|
15.4
|
56.9
|
Revaluation of derivative
contracts
|
(42.8)
|
(16.8)
|
Transaction costs
|
-
|
60.1
|
Exploration and evaluation expenses
|
13.6
|
9.0
|
Historic claim relating to an
acquisition
|
(50.1)
|
-
|
Remeasurements of decommissioning
reimbursement receivables
|
(5.6)
|
-
|
Fair value losses on contingent consideration
|
8.0
|
4.3
|
Adjusted EBITDAX
|
1,722.7
|
1,916.2
|
Adjusted net
income: profit after tax excluding non-cash bargain purchase credits,
material impairment charges
or reversals,
the tax
effects of
these items
where applicable
and non-cash
deferred tax
charges on
initial application of EPL. Adjusted net
income, which is presented as it eliminates items which distort
year-on-year comparisons, is reconciled to profit after tax as
follows:
|
2023
$m
|
2022
$m
|
Profit after tax
|
215.6
|
1,031.5
|
Gain on
bargain purchase
|
-
|
(1,335.2)
|
Impairment charges
|
557.9
|
-
|
Tax credit on impairment charges
|
(403.9)
|
-
|
EPL deferred tax charge
|
-
|
766.5
|
Adjusted net
income
|
369.6
|
462.8
|
Alternative Performance Measures continued
Adjusted earnings per share
(EPS): Adjusted
net income
divided by
average shares
for the
year of
1,006.7 million
(2022: 1,005.2
million)
Adjusted net debt: consists of amounts outstanding
under RBL
facility, senior
unsecured loan
notes and
bp unsecured
loan less
cash and
cash equivalents
and excludes
intragroup debt
arrangements or
liabilities represented by letters of credit and surety bonds. Adjusted net debt, which excludes
accrued interest on borrowings, lease liabilities and unamortised
fees, comprises:
|
2023
$m
|
2022
$m
|
RBL drawn facility
|
-
|
(600.0)
|
Senior unsecured notes
|
(625.0)
|
(625.0)
|
bp unsecured loan
|
(100.0)
|
-
|
Cash and cash equivalents
|
153.2
|
253.8
|
Adjusted net
debt
|
(571.8)
|
(971.2)
|
Leverage ratio:
adjusted net
debt at the end of the year divided by adjusted EBITDAX for the year then ended. The calculations are as follows:
|
|
|
|
2023
|
2022
|
Adjusted net debt
($m)
|
571.8
|
971.2
|
Adjusted EBITDAX ($m)
|
1,722.7
|
1,916.2
|
Leverage ratio
|
0.33x
|
0.51x
|
Available liquidity:
the sum
of cash
and cash
equivalents on
the balance
sheet and
the undrawn
amounts available
to the
Group using
existing approved
third-party facilities. Available
liquidity comprises:
|
|
|
|
2023
$m
|
2022
$m
|
Cash and cash equivalents
|
153.2
|
253.8
|
Undrawn borrowing facilities
|
725.0
|
325.0
|
Undrawn optional project capital expenditure
facility
|
150.0
|
-
|
Available liquidity
|
1,028.2
|
578.8
|
Subsequent to 31
December RBL
liquidity increased from $725.0 million to $836.0 million.
|
|
|
Group free cash flow: net cash flow from operating activities
less cash
used in
investing activities, adding
back acquisition
of subsidiaries
net of
cash acquired,
less bank
interest and
interest rate
swaps. This
measure is
considered a
useful indicator
of the
Group's ability
to make
strategic investments, repay
the Group's
debt and
meet other
payment obligations. Group
free cash
flow reconciles
to net
cash flow
from operating
activities as
follows:
|
2023
$m
|
2022
$m
|
Net cash flow from operating activities
|
1,290.8
|
1,723.3
|
Net cash
used in investing activities
|
(492.4)
|
(1,404.2)
|
Add back acquisitions
|
-
|
957.5
|
Bank interest and
charges
|
(99.8)
|
(142.8)
|
Interest rate swaps
|
7.0
|
0.8
|
Group free cash flow
|
705.6
|
1,134.6
|
Unit operating expenditure: operating costs (excluding over/underlift)
including tariff
expense, tariff
income and
tanker costs
divided by
net production
for the
year. This
measure is
considered a
useful indicator
of ongoing
operating costs
and is
also used
to compare
performance between assets. Operating costs for this calculation reconcile
to note
6 as follows:
DD&A rate
per
barrel: depletion,
depreciation and
amortisation charge for the year divided by net production for the year.
Other key performance
indicators
Total production: historic production
boe/d include
volumes from
date of
acquisition of
MOGL on
4 February
2022 and
Siccar Point
Energy and
Summit on
30 June
2022.
Tier 1 process
safety events:
process safety
incidents as defined by API 465 Process Safety-Recommended Practice
On Key
Performance Indicators.
Serious injury
and
fatality frequency:
the number
of serious
injuries resulting in permanent impairment,
as defined
by IOGP,
per million
hours worked.