REG - Ithaca Energy PLC Delek Group - DLEKG - Full Year 2023 Results
27/03/2024 08:15
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RNS Number : 4834I Ithaca Energy PLC 27 March 2024
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 EBITDAX(1) ($m) 1,722.7 1,916.2
Net cash flow from operating activities ($m) 1,290.8 1,723.3
Available liquidity(1) ($m) 1,028.2 578.8
Statutory net income ($m) 215.6 1,031.5
Unit operating expenditure(1) ($/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 (tCO2e(3)) 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 2023(1 (#_bookmark0) )
· 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 production(2 (#_bookmark1) )
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 fields(3 (#_bookmark2) )
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/ (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
Ithaca Energy
Kathryn Reid - Head of Investor Relations, Corporate Affairs & kathryn.reid@ithacaenergy.com (mailto:kathryn.reid@ithacaenergy.com)
Communications
FTI Consulting (PR Advisers to Ithaca Energy) +44 (0)203 727 1000
Ben Brewerton / Nick Hennis / Rosie Corbett ithaca@fticonsulting.com (mailto:ithaca@fticonsulting.com)
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 2023
$m $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 2023
$m $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 2023
$m $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
2023 2022
Note US$'000 US$'000
Revenue 5 2,319,811 2,598,482
Cost of sales (1,317,010) (1,352,324)
6
Gross profit 1,002,801 1,246,158
Impairment charges on development and production assets 19 (557,936) (31,467)
Exploration and evaluation expenses (13,634) (9,040)
14
Administrative expenses (34,259) (87,851)
7
Other gains/(losses) 89,091 (9,429)
8
Gain on bargain purchase - 1,335,171
17
Profit from operations before tax, finance income and finance costs 486,063 2,443,542
Finance income 9 5,688 695
Finance costs (189,724) (203,708)
9
Profit before tax 302,027 2,240,529
Income tax 27 (86,392) (1,208,997)
Profit for the year 215,635 1,031,532
Earnings per share 2023 2022
Note Cents Cents
Basic 10 21.4 102.6
Diluted 10 21.2 102.1
The results above are entirely derived from continuing operations.
The accompanying notes on pages 23 to 75 are an integral part of the financial
statements.
Consolidated statement of comprehensive income
For the year ended 31 December
2023 2022
Note US$'000 US$'000
Profit for the year 215,635 1,031,532
Items that may be reclassified to profit and loss
Fair value gains on cash flow hedges 29 92,484 453,862
Fair value gains on cost of hedging 3,116 14,231
Deferred tax charge on cash flow hedges and cost of hedging 27 (71,700) (200,455)
Other comprehensive income 23,900 267,638
Total comprehensive income for the year 239,535 1,299,170
The accompanying notes on pages 23 to 75 are an integral part of the financial
statements.
Consolidated statement of financial position
as at 31 December
2023 2022
Note US$'000 US$'000
Assets
Current assets
Cash and cash equivalents 153,215 253,822
Trade and other receivables 11 334,290 359,994
Decommissioning reimbursements 30,417 38,115
11
Prepaid expenses and decommissioning securities 37,678 9,055
12
Inventories 150,496 176,881
13
Derivative financial instruments 139,497 150,858
30
845,593 988,725
Non-current assets
Decommissioning reimbursements 11 165,064 162,710
Exploration and evaluation assets 548,354 775,773
14
Property, plant and equipment 3,258,206 3,634,896
15
Deferred tax assets 627,738 392,456
27
Derivative financial instruments 17,810 21,191
30
Goodwill 783,848 783,848
18
5,401,020 5,770,874
Total assets 6,246,613 6,759,599
Liabilities and equity
Current liabilities
Borrowings 20 (29,913) -
Trade and other payables (478,607) (711,412)
22
Current tax payable (321,116) (106,678)
27
Decommissioning liabilities (107,026) (146,829)
23
Lease liability (19,898) (41,637)
24
Contingent and deferred consideration (101,669) (107,680)
25
Derivative financial instruments (13,708) (136,668)
30
(1,071,937) (1,250,904)
Consolidated Statement of financial position continued
As at 31 Deember
2023 2022
Note US$'000 US$'000
Non-current liabilities
Borrowings 20 (718,238) (1,213,731)
Decommissioning liabilities 23 (1,752,652) (1,573,711)
Lease liability 24 (660) (17,221)
Contingent and deferred consideration 25 (258,700) (219,120)
Derivative financial instruments 30 - (27,440)
(2,730,250) (3,051,223)
Total liabilities (3,802,187) (4,302,127)
Net assets 2,444,426 2,457,472
Shareholders' equity
Share capital 26 11,540 11,445
Share premium 26 308,845 293,712
Capital contribution reserve 26 181,945 181,945
Own shares 26 (12,412) -
Share-based payment reserve 26 15,494 4,920
Cash flow hedge reserve 29 39,818 16,710
Cost of hedging reserve 29 4,068 3,275
Retained earnings 1,895,128 1,945,465
Total equity 2,444,426 2,457,472
The accompanying notes on pages 23 to 75 are an integral part of the financial
statements.
Approved on behalf of the Board on 26 March 2024:
Iain C S Lewis
Director
Consolidated statement of changes in equity
For the year ended 31 December
Capital contribution
Share Share Share-based Cash flow Cost of
capital premium reserve Own Shares payment reserve hedge reserve hedging reserve Retained earnings Total
Note US$'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) - - - - - -
26 (114,000) (634,658) - - - - - 748,658 -
Reduction in capital
26 11,444 293,712 - - (3,004) - - (10,228) 291,924
Issuance of shares
26 - - 181,945 - - - - - 181,945
Capital contribution through debt cancellation
26 - - - - 7,924 - - - 7,924
Share-based payments
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)
26 95 15,133 - (15,228) - - - - -
Issuance of shares
26 - - - 2,816 10,574 - - - 13,390
Share-based payments
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
2023 2022
Note US$'000 US$'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 13,634 9,040
14
Impairment charges on development and production assets 557,936 31,467
19
Increase in contingent/deferred consideration 8,008 4,295
Loan fee amortisation 9 4,508 6,418
Fair value gains on derivatives (43,059) (16,787)
29
Gain on bargain purchase - (1,335,170)
Hedging resets1 - (39,680)
Accretion 9 76,162 56,511
Finance costs 109,054 122,163
9
Interest income (5,688) -
9
Interest on related-party loan - 17,924
9
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
2023 2022
Note US$'000 US$'000
Investing activities
Capital expenditure (478,838) (380,640)
Acquisition of subsidiaries net of cash acquired 17 - (957,452)
Deferred consideration payments (6,367) (55,092)
25
Contingent consideration payments (7,200) (11,040)
25
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 CO(2) 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 CO(2)e. 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 $391 million
and has concluded that due to the recent licence extension to 31 March 2026
and the detailed plans in place for final investment decision (FID), there are
currently no indicators of impairment. The Group is actively engaging with
potential farm-in partners to secure an aligned joint venture partnership that
would progress the project towards FID and assist in obtaining the additional
funding required for the project. The Group is also mindful that the outcome
of the 2024 General Election could have implications for the project as well
as the wider fiscal uncertainties on oil and gas investment in general.
Details of contingent consideration in respect of Cambo are set out in note 17
and note 25.
Notes to the consolidated financial statements continued
4. Segmental reporting
The Group operates a single class of business being oil and gas exploration,
development and production and related activities in a single geographical
area, presently being the North Sea. The Group's segmental reporting structure
remained in place for all periods presented and is consistent with the way in
which the Group's activities are reported to the Board and Chief Decision
Making Officer. The Group's activities are considered to be an individual
operating segment due to the nature of the Group's operations being
consistent, and such operations existing in a single geographical region that
is covered by the same regulations.
5. Revenue
2023 2022
US$'000 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$'000
Movement in oil and gas inventory (including underlift/overlift) 20,582 (130,295)
Operating costs of hydrocarbon activities (576,660) (547,795)
Materials inventory provision (16,268) -
Royalties (4,364) (11,287)
Depreciation on right-of-use assets (note 15) (42,648) (37,438)
Depletion, depreciation and amortisation (note 15) (697,652) (625,509)
(1,317,010) (1,352,324)
Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the
original licence holders. Ithaca holds a 100% interest in the Stella and
Harrier fields.
7. Administrative expenses
2023 2022
US$'000 US$'000
Administrative expenses excluding transaction costs (34,259) (41,762)
Transaction costs - (46,089)
(34,259) (87,851)
Transactions costs in 2022 relate to the acquisitions of Marubeni Oil &
Gas Limited (MOGL), Summit Exploration and Production Limited (Summit) and
Siccar Point Energy entities, and costs incurred in connection to the IPO.
Further details on the acquisitions can be found in note 17.
The total employee benefit expenses which are either capitalised or included
in cost of sales, pre-licence exploration and evaluation expenses and
administrative expenses are noted below.
2023 2022
Employee benefit expenses US$'000 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 1,286 1,095
statements
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$'000
Loan interest and charges (47,494) (58,317)
Senior notes interest (58,377) (61,537)
Loan fee amortisation (4,508) (6,418)
Interest on lease liabilities (note 24) (3,183) (3,852)
Interest on related-party loan (note 31) - (17,924)
Accretion (76,162) (56,511)
Realised gains on interest derivative contracts (note 29) - 851
Total finance costs (189,724) (203,708)
Interest income 5,688 695
There was no interest capitalised into qualifying assets in either the year to
31 December 2023 or the year to 31 December 2022.
10. Earnings per share
The calculation of basic earnings per share is based on the profit after tax
and the weighted average number of ordinary shares in issue during the year.
Basic and diluted earnings per share are calculated as follows:
2023 2022
US$'000 US$'000
Earnings for the year:
Earnings for the purpose of basic and diluted earnings per share 215,635 1,031,532
Number of shares (million)
Weighted average number of ordinary shares for the purpose of basic earnings 1,006.7 1,005.2
per share1
Dilutive potential ordinary shares 12.7 5.0
Weighted average number of ordinary shares for the purpose of diluted earnings 1,019.4 1,010.2
per share
Earnings per share (cents)
Basic 21.4 102.6
Diluted 21.2 102.1
11. Trade and other receivables
2023 2022
Current US$'000 US$'000
Trade receivables 19,968 31,906
Other receivables 24,369 14,210
Joint operations receivables 91,960 99,800
Accrued income 197,993 214,078
334,290 359,994
Materially all trade and other receivables, including receivables from joint
operations are not overdue by more than 90 days. The credit risk associated
with trade receivables, accrued income and other receivables is considered to
be insignificant. No ECL has been recognised in the current or prior year.
11. Trade and other receivables continued
2023 2022
Non-current US$'000 US$'000
Decommissioning reimbursements 165,064 162,710
2023 2022
Current US$'000 US$'000
Decommissioning reimbursements 30,417 38,115
Movements on decommissiong reimbursements were as follows:
2023 2022
US$'000 US$'000
At 1 January 200,825 246,824
Accretion 7,536 5,946
Reimbursements received (22,101) (23,418)
Change in reimbursement estimates 9,221 (28,527)
At 31 December 195,481 200,825
The decommissioning reimbursements represent the equal and opposite of
decommissioning liabilities (note 23), net of tax, associated with the Heather
and Strathspey fields and relates to a contractual agreement as part of
the CNSL acquisition. As part of the terms of the CNSL acquisition, Chevron
have the obligation to provide the security and remain financially responsible
for the decommissioning obligations of CNSL in relation to these interests.
The Group pays the liabilities in respect of Heather and Strathspey and then
receives full reimbursement from Chevron.
As these payments are virtually certain they have been accounted for under IAS
37 as a reimbursement asset.
12. Prepaid expenses and decommissioning securities
Current 2023 2022
US$'000 US$'000
Prepayments 34,355 7,415
Decommissioning securities 3,323 1,640
37,678 9,055
13. Inventories
2023 2022
Current US$'000 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 (379,301)
assets (note 15)
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 362,844 5,619 458,180
89,717
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 358,361 1,728 386,557
26,468
Transfers from exploration and evaluation assets (note 14) 348,527 - 379,301
30,774
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 (615,261) (10,248) (662,947)
(37,438)
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 (693,573) (4,079) (740,300)
(42,648)
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 P.2403 Tornado Ithaca SP E&P Limited 50.00% 50.00%
and 204/15
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 $62 million was recognised. The goodwill
recognised can be attributed to the increase in the Group's equity interest in
the Elgin Franklin field and the corresponding impact of EPL, which was
announced between effective date and completion, on the fair values at
acquisition.
There are no contingent consideration arrangements under the Sale and Purchase
Agreement of the Summit assets. No contingent liabilities have been acquired
on the business combinations detailed above.
The fair values of the oil and gas assets and the intangible assets acquired
have been determined using valuation techniques based on discounted cash flows
using forward curve commodity prices and estimates of long-term commodity
prices reflective of market conditions at each completion date, a discount
rate based on observable market data and cost and production profiles
generally consistent with the proved and probable reserves acquired with each
asset.
The decommissioning liabilities recognised have been estimated based on
operator cost estimates with reference to observable market data.
18. Goodwill
2023 2022
US$'000 US$'000
Balance at 1 January 783,848 722,075
Additions (note 17) - 61,773
Balance at 31 December 783,848 783,848
The goodwill is not tax deductible on any of the acquisitions.
18. Goodwill continued
The goodwill on acquisition in the year to 31 December 2022 relates to the
Summit acquisition, as detailed in note 17.
Annual impairment tests were performed at both 31 December 2023 and 31
December 2022. These reviews were carried out on a fair value less cost of
disposal basis using risk adjusted cash flow projections from the approved
business plans including the same commodity prices, life of field cost
profiles and production volumes used for impairment of oil and gas assets (see
note 19), discounted at a post-tax discount rate of 10.3% (2022: 10.9%).
Assumptions and estimates in the Group impairment models are detailed in note
3. An increase of 1% in the discount rate assumption would not result in a
post-tax impairment of goodwill. Goodwill is monitored, and tested for
impairment, at the operating segment level, being the North Sea (the entire
Group portfolio of oil and gas assets). This is consistent with the operating
segment view of the business which is presented to the Board and the Chief
Decision Maker.
The Group's activities are considered to be an individual operating segment
due to the uniform nature of the Group's operations within a single
geographical area, overseen by the same management and subject to the same
regulations. The fair value estimate is categorised as level 3 in the fair
value hierarchy.
19. Impairment charge on oil and gas assets
2023 2022
US$'000 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 2024 2025 2026 2027 20281
discount rate
assumption
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 2023 2024 2025 2026 20271
discount rate
assumption
Oil 10.9% $89/bbl $84/bbl $83/bbl $83/bbl $83/bbl
Gas 10.9% 315p/therm 211p/therm 99p/therm 86p/therm 86p/therm
1. Post 2027 an annual 2% is applied to the price assumptions.
Estimated production volumes and cash flows up to the date of cessation of
production on a field-by-field basis, including operating and capital
expenditure, are derived from the approved business plans and third-party
reports.
20. Borrowings
2023 2022
US$'000 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
Financing cash Fair value movements Other movements (ii)
1 January 2023 flows (i) Additions Imputed interest Amortisation Debt waiver 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 (45,085) 3,603 - - - - 3,183 20,559
58,858
Interest rate derivatives (note 29) 6,967 - - (479) - - - (637)
(7,125)
Total liabilities from financing activities 1,265,464 (634,760) 3,603 - (479) 4,507 - 129,737 768,072
Non-cash changes
Financing cash Fair value movements Other movements (ii)
1 January 2022 flows (i) Additions Imputed interest Amortisation Debt waiver 31 December 2022
US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000
Borrowings (note 20) 954,616 50,000 200,000 - - 4,508 - - 1,213,731
Parent company debt (note 31) (273,055) - 17,924 - - (181,945) - -
437,076
Lease liabilities (38,200) - - - - - 93,569 58,858
3,489
Interest rate derivatives (note 29) 851 - - (7,843) - - - (7,125)
(133)
Total liabilities from financing activities 1,395,048 (260,404) 200,000 17,924 (7,843) 4,508 (181,945) 98,176 1,265,464
(i) The cash flows from borrowings, Parent Company debt, lease liabilities
and interest rate derivatives make up the net amount of proceeds from
borrowings and repayments of borrowings in the cash flow statement.
(ii) Other movements include interest accruals and new liabilities in the
year.
22. Trade and other payables
2023 2022
US$'000 US$'000
Trade payables (34,559) (14,917)
Hydrocarbon amounts owed to joint operations/overlift (72,486) (124,365)
Other payables (68,034) (185,720)
Accruals (254,781) (299,604)
Deferred income (48,747) (86,806)
(478,607) (711,412)
The Directors consider the carrying values of trade and other payables to
approximate the fair value. Other payables mainly comprises amounts owed due
to production adjustments and amounts owed to joint operations partners.
Deferred income represents receipts in advance of deliveries to customers. The
prior year deferred income was recognised in revenue in the current year.
23. Decommissioning liabilities
2023 2022
US$'000 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 $147 million) has been treated as a current
liability as at 31 December 2023. Although the Group currently expects to
incur decommissioning costs over the next 40 years, it is estimated that
approximately 47% of the decommissioning liability relates to assets which are
expected to cease production in the next five years and which includes spend
for assets that will be reimbursed (see note 11 for further details).
24. Lease liabilities
2023 2022
Current US$'000 US$'000
Lease liabilities (19,898) (41,637)
2023 2022
Non-current US$'000 US$'000
Lease liabilities (660) (17,221)
The following table sets out a maturity analysis of lease payments, showing
the undiscounted lease payments to be paid after the reporting date. All lease
liabilities are fully payable within two years from 31 December 2023.
2023 2022
US$'000 US$'000
Less than one year (20,152) (44,257)
One to two years (669) (17,439)
Total undiscounted lease payments (20,821) (61,696)
Future finance charges and other adjustments 263 2,838
Lease liabilities in the financial statements (20,558) (58,858)
2023 2022
US$'000 US$'000
At 1 January (58,858) (3,489)
Additions (3,603) (89,717)
Interest (3,183) (3,852)
Payments 45,086 38,200
At 31 December (20,558) (58,858)
Current (19,898) (41,637)
Non-current (660) (17,221)
(20,558) (58,858)
The additions in the year to 31 December 2023 relate to modifications of the
Captain Emergency Response and Recovery Vehicle lease.
The addition in the year to 31 December 2022 relates to the Pioneer rig lease
currently utilised on the Captain EOR project. The incremental borrowing rate
applied to the lease is 6.07%.
If the Company were to terminate the use of the Pioneer rig early then
termination fees would apply, escalating to 75% of total expected costs if
within one month prior to commencement date of planned works. Remuneration for
work performed up to the date of termination, together with costs relating to
demobilisation of the drilling unit to the demobilisation port would also be
due.
Amounts recognised in profit and loss related to leases is detailed in notes 6
and 9.
25. Contingent and deferred consideration
2023 2022
Current US$'000 US$'000
Contingent consideration (101,669) (101,559)
Petrofac deferred consideration - (6,121)
(101,669) (107,680)
2023 2022
Non-current US$'000 US$'000
Contingent consideration (194,721) (157,337)
MOGL deferred consideration (63,979) (61,783)
(258,700) (219,120)
2023 2022
US$'000 US$'000
Cash flows relating to contingent and deferred considerations (13,567) (66,132)
Movement in contingent consideration consideration is as follows:
2023 2022
US$'000 US$'000
At 1 January (258,896) (19,480)
Business combinations (note 17) - (241,431)
Addition (26,872) -
Payments made 7,200 11,040
Reversal - 1,100
Accretion (9,814) (5,830)
Changes in fair value (8,008) (4,295)
At 31 December (296,390) (258,896)
Movement in deferred consideration consideration is as follows:
2023 2022
US$'000 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, $0.01 B1 share and 0.01 B2 share to (12) (12) -
£0.01 A ordinary shares
87,087 87,063
Bonus issue of new £0.01 A shares - - -
898,131,843 898,131,843
Bonus issue of new £0.01 B1 shares 1,401,670 - -
- 1,401,670
Bonus issue of new £0.01 B2 shares - 420,440 -
- 420,440
Conversion of £ 0.01 A ordinary shares, £0.01 B1 shares and £0.01 B2 shares (1,401,758) (420,528) 900,042,217
to £0.01 ordinary shares
(898,219,931) -
Bonus issues of £0.01 ordinary shares - - 120,000
- 120,000
Issue of new £0.01 ordinary shares on IPO - - 105,000,000
- 105,000,000
Issue of new £0.01 ordinary shares on exercise of share options - - 1,402,759
- 1,402,759
Ordinary shares of £0.01 each at 31 December 2022 - - - 1,006,564,976 1,006,564,976
26. Reserves continued
(b) Share premium 2023 2022
US$'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 $181.9 million has been
capitalised as Capital Contribution Reserve as per the requirements of IFRS 9.
(d) Own shares
Own shares comprise shares held in the Ithaca Energy plc EBT which are being
used to satisfy the exercise of employee share options. During the year,
7,807,305 ordinary shares of £0.01 each were issued to the EBT and 1,443,561
ordinary shares were used to satisfy the exercise of share options. As a
result, the EBT held 6,363,744 ordinary shares of £0.01 each at 31 December
2023.
(e) Share-based payment reserve (note 32)
The share-based payment reserve represents the cumulative charge for share
options, as described in note 32, less the cumulative cost of share option
exercises.
27. Taxation
2023 2022
US$'000 US$'000
Current tax
Current corporation tax charge (39,308) (54,557)
Current EPL tax charge (333,425) (131,389)
Current corporation tax (charge)/credit - prior year (17,426) 1,839
Total current tax charge (390,159) (184,107)
Deferred tax
Adjustment in respect of prior period 6,370 (641)
Group tax credit/(charge) in consolidated statement of profit or loss 227,360 (1,013,817)
Group tax charge in consolidated statement of other comprehensive income (71,700) (200,455)
Total deferred tax credit/(charge) 162,030 (1,214,913)
Deferred Petroleum Revenue Tax
Deferred PRT credit/(charge) in statement of profit or loss 70,037 (10,432)
Total tax charge through consolidated statement of profit or loss (86,392) (1,208,997)
27. Taxation continued
The tax on the Group's profit before tax differs from the theoretical amount 2023 2022
that would arise using the 40% statutory rate of tax applicable for UK ring
fence oil and gas activities as follows:
US$'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: $156 million), of which there is
no expiry date, have not been recognised for deferred tax purposes as it is
not sufficiently certain that there will be future non-oil and gas profits to
offset these losses.
The net movement on deferred tax in the statement of financial position,
including deferred PRT, is as follows:
2023 2022
US$'000 US$'000
At 1 January 392,456 220,918
Profit or loss credit/(charge) (1,024,889)
303,767
Other comprehensive income charge (200,455)
(71,700)
Deferred tax on decommissioning reimbursements (note 11) -
3,214
Business combinations (note 17) 1,396,882
-
At 31 December 627,738 392,456
The net movement on deferred tax through the consolidated statement of profit
or loss and consolidated statement of comprehensive income relates to the
following:
2023 2022
US$'000 US$'000
Accelerated capital allowances 438,359 (490,246)
Tax losses (386,819)
(216,937)
Decommissioning provision (124,598)
52,440
Deferred PRT 4,173
(28,015)
Hedging (226,040)
(101,744)
Share schemes -
3,978
Investment allowances 8,617
13,950
162,030 (1,214,913)
27. Taxation continued
Deferred corporation tax on
Accelerated tax
Gross deferred corporation tax liabilities Hedges US$'000 deferred PRT depreciation Total US$'000
US$'000 US$'000
At 1 January 2022 - (12,861) (675,279) (688,140)
Prior year adjustment - - (4,347) (4,347)
Reclassification of decommissioning asset - - (436,771) (436,771)
Business combinations - - (647,743) (647,743)
Origination and reversal of temporary differences - 4,173 (485,985) (481,812)
At 31 December 2022 and 1 January 2023 - (8,688) (2,250,125) (2,258,813)
Reclass to deferred corporation tax assets (8,678) - - (8,678)
Prior year adjustment 2,721 - 8,307 11,028
Origination and reversal of temporary differences (101,744) (28,015) 441,281 311,522
At 31 December 2023 (107,701) (36,703) (1,800,537) (1,944,941)
Decommissioning
Share schemes provision Tax losses Hedges Total
Gross deferred corporation tax assets US$'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 38,406 2,053,324
1,858,706
Origination and reversal of temporary differences - (124,598) (226,040) (741,158)
(390,520)
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 - - (4,812)
(4,989)
Origination and reversal of temporary differences 3,802 55,654 - (152,493)
(211,949)
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 $112.2 million.
On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK,
introducing a global minimum effective tax rate of 15%. The legislation
implements a domestic top-up tax and a multinational top-up tax, effective for
all accounting periods starting on or after 31 December 2023. The Group does
not anticipate that the adoption of this will have a material impact as the
prevailing rate of tax in the United Kingdom is in excess of the 15% minimum
rate. The Group has applied the exemption under IAS 12 to recognising and
disclosing information about deferred tax assets and liabilities related to
top-up income taxes and therefore there is no impact on the tax values
reported.
28. Commitments and contingencies
2023 2022
US$'000 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:
Mandatorily Derivatives
Measured at amortised cost measured at fair value through designated in hedge Total carrying
profit or loss relationships amount
US$'000 US$'000 US$'000 US$'000
Financial assets
Cash and cash equivalents 153,215 - - 153,215
Trade and other receivables 330,351 - - 330,351
Derivative financial instruments - 2,782 154,525 157,307
Financial liabilities
Borrowings (748,151) - - (748,151)
Trade and other payables (343,279) - - (343,279)
Lease liability (20,559) - - (20,559)
Contingent and deferred consideration (63,979) (296,390) - (360,369)
Derivative financial instruments - (10,373) (3,335) (13,708)
(845,193)
The accounting classification of each category of financial instruments and
their carrying amounts as at 31 December 2022 are set out below:
Mandatorily measured at fair value through Derivatives designated in hedge
Measured at Total carrying
amortised cost profit or loss relationships amount US$'000
US$'000 US$'000 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: $26.4 million).
The level three contingent consideration is valued based on the probability of
the events occurring ("trigger events") as set out in note 17. The forecast
cash flows in the event of the trigger event occurring are discounted at a
rate of 4.6% (2022: 4.25%).
The following table summarises the sensitivity of 20% change in probability of
trigger event occurring and conditions being met for payment of contingent
consideration, with all other variables held constant, of the Group's profit
before tax due to changes in the carrying value of level 3 financial
instruments at the reporting date. The impact on equity is the same as the
impact on profit before tax.
Change in probability 2023 2022
US$'000 US$'000
20% decrease in probability 97,119 87,080
20% increase in probability (84,086) (83,612)
The following table summarises the sensitivity of 1% decrease in discount
rate, with all other variables held constant, of the Group's profit before tax
due to changes in the carrying value of level 3 financial instruments at the
reporting date. The impact on equity is the same as the impact on profit
before tax.
Change in discount rate 2023 2022
US$'000 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 - $91/bbl ceiling
Gas swaps Jan 23 - Jun 24 104,585,000 therms 188p/therm
Gas puts Apr 23 - Sep 23 9,150,000 therms 220p/therm
Gas collars Jan 23 - Mar 24 100,200,000 therms 244p/therm floor - 479p/therm ceiling
The following table summarises the sensitivity of 20% decrease in realised
commodity prices, with all other variables held constant, of the Group's
profit before tax due to changes in the carrying value of monetary assets and
liabilities at the reporting date. The impact on equity is the same as the
impact on profit before tax.
Change in realised commodity price 2023 2022
US$'000 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 $150 million 0.398%
The following table summarises the sensitivity of an increase of 250 basis
points in interest rate, with all other variables held constant, of the
Group's profit before tax due to changes in the carrying value of monetary
assets and liabilities at the reporting date.
Change in interest rate
2023 2022
US$'000 US'000
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 $1.265:£1 for the period January to
December 2023. As at 31 December 2022 the Group had no open FX collars.
The following table summarises the sensitivity to a reasonably possible change
in the US Dollar to Sterling foreign exchange rate, with all other variables
held constant, of the Group's profit before tax due to changes in the carrying
value of monetary assets and liabilities at the reporting date. The impact on
equity is the same as the impact on profit before tax. The Group's exposure to
foreign currency changes for all other currencies is not material.
Change in Sterling foreign exchange rate
2023 2022
US$'000 US'000
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 Total
US$'000 $'000
Net-settled (derivative liabilities):
Commodity options (51,654) (15,402) (67,056)
Gross-settled:
Foreign exchange forwards - gross outflows (83,529) (107,235) (190,764)
Foreign exchange collars - gross outflows - - -
(135,183) (122,637) (257,820)
vi) Capital management
The Group's objectives when managing capital are to safeguard the Group's
ability to continue as a going concern in order to provide returns to
shareholders and benefits for other stakeholders and to maintain an optimal
capital structure to reduce the cost of capital. The Group regularly monitors
the capital requirements of the business over the short, medium and long-term,
in order to enable it to foresee when additional capital will be required.
The Group has approval from management to hedge external risks, commodity
prices, interest rates and foreign exchange risk. This is designed to reduce
the risk of adverse movements in market prices, interest rates and exchange
rates eroding the Group's financial results.
30. Derivative financial instruments
The net carrying amount of each category of derivative is set out below:
2023 2022
US$'000 US$'000
Oil swaps - cash flow hedge 9,913 (28,685)
Oil swaps - non-cash flow hedge - (15,027)
Oil collars - cash flow hedge 7,434 (21,983)
Gas swaps - cash flow hedge 47,232 19,797
Gas swaps - non-cash flow hedge (2,290) (29,271)
Gas puts - cash flow hedge - 9,746
Gas collars - cash flow hedge 89,944 79,489
Interest rate swaps - non-cash flow hedge 637 7,125
FX forwards - non-cash flow hedge (3,961) (13,250)
FX collars - cash flow hedge (3,335) -
FX collars - non-cash flow hedge (1,975) -
143,599 7,941
30. Derivative financial instruments continued
2023 2022
Maturity analysis of derivative financial instruments US$'000 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 Net amount
sheet
$'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 Net amount
sheet
$'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 $181.9 million was recognised as a Capital Contribution on
equity in the year to 31 December 2022.
Key management personnel
The following table provides remuneration to key management personnel, being
persons having direct or indirect authority or responsibility of the Group,
for the periods ended 31 December 2023 and 2022:
Key management personnel 2023 2022
US$'000 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: $3.0 million).
33. Dividends
2023 2022
US$'million US$'million
First interim dividend of $0.132 per ordinary share announced 16 February 2023 133.0 -
and paid 9 March 2023
Second interim dividend of $0.132 per ordinary share announced 23 August 2023 133.0 -
and paid 29 September 2023
Total dividends paid during year ended 31 December 2023 266.0 -
Third interim dividend of $0.132 per ordinary share announced 21 March 2024 134.0 -
and payable in April 2024 (not accrued in the 2023 results)
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 2022
$m $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 2022
$m $m
RBL drawn facility - (600.0)
(625.0) (625.0)
Senior unsecured notes
(100.0) -
bp unsecured loan
Cash and cash equivalents 153.2 253.8
Adjusted net debt (571.8) (971.2)
Leverage ratio: adjusted net debt at the end of the year divided by adjusted
EBITDAX for the year then ended. The calculations are as follows:
2023 2022
Adjusted net debt ($m) 571.8 971.2
1,722.7 1,916.2
Adjusted EBITDAX ($m)
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 2022
$m $m
Cash and cash equivalents 153.2 253.8
725.0 325.0
Undrawn borrowing facilities
150.0 -
Undrawn optional project capital expenditure facility
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 2022
$m $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.
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