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 EBITDAX1 ($m)

1,722.7

1,916.2

Net cash flow from operating activities ($m)

1,290.8

1,723.3

Available liquidity1 ($m)

1,028.2

578.8

Statutory net income ($m)

215.6

1,031.5

Unit operating expenditure1 ($/boe)

20.5

19.0

 

Other KPIs

 

Total production (boe/d)

70,239

71,403

Tier 1 process safety events

1

-

Serious injury and fatality frequency

-

-

Scope 1 and 2 emissions (tCO2e3)

435,792

483,325

Greenhouse gas intensity (kgCO2e/boe)

25.0

23.8

1 Non-GAAP measure (see pages 77 to 79)

2023 Strategic and Operational Highlights

·    Full year production of 70.2 thousand barrels of oil equivalent per day (kboe/d), in line with previously stated guidance of 68-74 kboe/d

-      Underpinned by high levels of production efficiency across our operated asset base of 84%

-      Production split 66% liquids and 34% gas

·    Increase in Year-end 2P reserves and 2C resources to 544 mmboe (2022: 512 mmboe)

·    Significant progress across our strategic goals in 2023, delivering against our BUY, BUILD and BOOST

 

BUY

·    Completed acquisitions of the remaining 40% stake in Fotla and 30% stake in Cambo, at minimal near-term cost, providing full control over pre-Final Investment Decision (FID) work programme and timing

BUILD

·    FID taken to progress Phase I of the Rosebank development, the UK's largest undeveloped discovery with all major contracts awarded and work underway to upgrade the Petrojarl Knarr FPSO

·    Pre-FID work continues across the Group's high-value greenfield and brownfield development portfolio including:

-        Actively engaging with potential farm-in partners to enable the future progression of Cambo and Fotla towards FID, subject to fiscal and market conditions

-        Awarded license milestone extensions from 31 March 2024 to 31 March 2026 for Cambo field, on 19 March 2024

-        Captain Electrification FEED study matured to support FID in 2024, subject to market and fiscal conditions

-        Marigold Unitisation and Unit Operating Agreement executed with work progressing on preparation of a Field Development Plan

-        Fotla development concept selection in 2024

·    Successful exploration drilling at the K2 prospect (Ithaca Energy working interest 50%) and appraisal drilling at non-operated Leverett field, with good flow rates achieved (Ithaca Energy working interest 12%)

BOOST

·    Captain Enhanced Oil Recovery (EOR) Phase II project now substantially complete (>90%), supporting first Phase II polymer injection into the subsea wells in summer 2024 with the remaining project scopes to completion including commissioning and subsea tie-in activities

 

2023 Financial Highlights

Key financial highlights in-line with estimated results provided in FY 2023 Trading Update on 15 February 2024

· 

Adjusted EBITDAX of $1,723 million (2022: $1,916 million) on revenues of $2,319 million (2022: $2,599 million)

· 

Net cash flow from operating activities of $1,291 million (2022: $1,723 million)

· 

Net Operating costs of $524 million, representing a net unit opex cost of $20.5/boe (2022: $19.0/boe) at the bottom end of lowered management guidance of $525-$575 million. Operating cost performance reflects the success of the Group's internal cost optimisation projects and stringent cost control, and improved FX rates.

· 

Trading performance benefited from the Group's active hedging policy with $266 million of hedge gains in the year due to realised oil prices of $85/bbl before hedging (2022: $100/bbl) and $82/bbl after hedging (2022: $91/bbl) and gas prices of $76/boe before hedging (2022: $149/boe) and $111/boe after hedging (2022: $137/boe)

· 

Net producing asset capital cost of $393 million, at the bottom end of management guidance of $390-$435 million reflecting reduction in planned activity

· 

Net capital spend of $97 million on Rosebank development project, in line with management guidance of $90-$110 million and reflecting the meaningful activity in 2023 as project activity ramps up to support a targeted first oil date of 2026/27

· 

Strong cash flow generation supported continued deleveraging of the business, reporting a reduction in adjusted net debt from $971.2 million to $571.8 million, representing a Group leverage position of 0.33x (2022: 0.51x), with the Group's Reserve Based Lending Facility fully paid down

· 

Third Interim 2023 dividend declared of $134 million payable in April 2024, delivering against our IPO commitment of a total 2023 dividend of $400 million, representing ~30% of post-tax CFFO for the year

Guidance and Outlook 2024

·    We expect full year 2024 production in range of 56-61 kboe/d reflecting:

-      A reduction in investment in near-term projects as a direct result of the Energy Profits Levy including deferred or cancelled projects at the Greater Stella Area, Montrose Arbroath Area, Elgin Franklin Area and Alba

-      Longer path to Captain EOR II polymer well driven peak production, which is now expected in 2026. Ultimate reserve recovery of EOR Phase I and II remains unchanged

-      Operational issues at non-operated Pierce and Schiehallion fields and compressor issues at Erskine's host facility (Lomond) impacting production in Q1 2024

·    FY 2024 net operating cost guidance range of $540-590 million driven partly by tariff revenue reductions in the Greater Stella Area due to third party field production decline

·    FY 2024 net producing asset capital cost guidance range of $335-385 million (excluding pre-FID projects and Rosebank development)

·    FY 2024 net Rosebank project capital cost guidance range of $190-230 million

·    FY 2024 cash tax guidance of $345-355 million

·    Drawdown on unutilised capex carry arrangements of $150 million

·    Reaffirming dividend policy for 2024 targeting dividend at the top end of our capital allocation policy range of 15 - 30% post-tax CFFO

Medium-Term

·    Beyond 2024, the Group expects production growth through the medium-term with a return towards 80 kboe/d by 2027, as we see the full benefit of investment in our Captain EOR Phase II project and first production from the sanctioned Rosebank development

·    Strategic M&A focus on adding complementary cash-generative production portfolios that will support our investment in long-term organic growth opportunities to build a portfolio of significant scale and longevity

·    Continued focus on advancing high-value development projects and preserving optionality across our portfolio while prioritising capital allocation to maximise sustainable shareholder returns

Exclusivity Agreement for a potential transformational combination with Eni S.p.A.'s UK Business

·    Ithaca Energy today announces that it has entered into an exclusivity agreement (the "Exclusivity Agreement") in relation to a potential transformational combination with substantially all of Eni S.p.A.'s ("Eni") UK upstream assets including the recently acquired Neptune Energy assets, excluding certain assets including Eni's CCUS and Irish sea assets (the "Potential Combination")

·    Pursuant to the Exclusivity Agreement, Eni has granted Ithaca Energy exclusivity in respect of the assets the subject of the Potential Combination for a period of four weeks from the date of this announcement. Ithaca Energy and Eni have entered into the Exclusivity Agreement to allow time to separately progress the contractual documentation required in connection with the Potential Combination.

Key highlights of the Potential Combination

·    Eni will contribute its UK business in exchange for the issuance of new Ithaca Energy shares to Eni, with Eni anticipated to hold between 38% and 39% of the enlarged issued share capital of Ithaca Energy following completion

·    Eni has a well-diversified asset base across four key hubs: Elgin Franklin, J-Area, Cygnus and Seagull; Ithaca Energy is already a partner in the Elgin Franklin and Jade fields

·    Eni's UK business had 2023 pro forma production of 40-45 kboe/d and 2P reserves of c.100 mmboe as at 31 December 20231

·    The Potential Combination would represent a value-accretive opportunity for Ithaca Energy's shareholders, supporting delivery of the Company's BUY, BUILD and BOOST strategy

·    The Potential Combination would:

Add significant scale and diversification to Ithaca Energy's business: Significantly growing pro-forma production to above 100 kboe/d, creating the 2nd largest independent operator in the UKCS by production2

Create a leading UKCS portfolio: Enhancing Ithaca Energy's status as the largest independent operator by resource, holding stakes in 6 of the 10 largest fields3

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

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 VÃ¥r Energi and Azule Energy respectively. We look forward to updating the markets in the coming month."

Interim Chief Executive Officer and Chief Financial Officer, Iain Lewis, commented: "We have made material progress in 2023, executing against our BUY, BUILDand BOOSTstrategy including the milestone sanctioning of Phase I of the Rosebank development and the significant progress towards delivering our Captain EOR Phase II project.

I am pleased to share a strong set of financial results for 2023, despite the significant fiscal and political headwinds we have faced in the year. The Energy Profits Levy continues to have a direct impact on investment in the UK North Sea, with projects across our operated and non-operated deferred or cancelled. The extension of the Energy Profits Levy by a further year to a sunset date of March 2029, highlights the continued fiscal uncertainty our sector faces."

Ithaca Energy will host an in person and virtual presentation and Q&A session for investors and analysts at 09:00 GMT today, 27 March 2024, accessible via our website: https://investors.ithacaenergy.com/

 

Performance Overview

Executing our BUY, BUILD and BOOST Strategy

We made significant progress across our strategic goals in 2023, delivering against our BUY, BUILD and BOOST strategy to support the material long-term growth of the Group. We continue to focus on maximising value from across our diverse portfolio with targeted investment in high-quality assets demonstrating our commitment to investing in the UK North Sea.

In 2023, we were delighted to announce the landmark sanctioning of Phase I of the Rosebank development, with total recoverable resources over 300 mmboe and Phase I gross reserves of 234 mmboe. As the UK's largest undeveloped discovery, the field will provide critically important domestic energy, supporting a forecasted 7% of UK oil production from first production to 2030. And crucially, with its low carbon emissions design, the field has the potential to produce at a fraction of the world's average CO2 emissions contributing to both the UK's energy security and Net Zero objectives.

The Rosebank development is core to Ithaca Energy's BUILD strategy, executing on the material development portfolio acquired from Siccar Point Energy in 2022. With estimated net production of 15 kboe/d at the field's peak and a production life of 25 years, the field supports the Group's medium to long-term production growth. After taking the Final Investment Decision (FID), project activity has ramped up with work underway on upgrading the Petrojarl Rosebank FPSO (previously named Petrojarl Knarr), including making the vessel electrification ready in line with the North Sea Transition Deal. In 2024, work will commence on the installation of templates and satellite structures as part of the multi-year development timeline towards first production in 2026/27.

At Captain, material progress was made during the year on executing Phase II of our pioneering polymer Enhanced Oil Recovery (EOR) project with the project now over 90% complete and on track to support first Phase II polymer injection into the subsea wells in summer 2024. Remaining work scopes include final commissioning activities on the topsides, subsea tie-in campaign and completion of the drilling programme (completed during Q1 2024).

The EOR Phase II project, designed to maximise and accelerate reserve recovery from Captain and deliver on our strategy to BOOST field performance, will build on the success of the first phase of polymer injection with over 12 mmbbls recovered to date. Extensive subsurface modelling completed in H2 2023 to refine the predicted EOR Phase II polymer response, based on reprocessed seismic and latest field performance, has successfully confirmed initial overall EOR Phase II reserve recovery predictions. However, our expectation is that Captain production will now follow a longer path to peak response with production expected to peak in 2026, before plateau.

The Group continues to leverage our M&A capabilities to deliver on our BUY strategy evaluating potential inorganic opportunities both in the UK and internationally. In 2023, the Group acquired the remaining stakes of the Cambo and Fotla fields with the aim of preserving the long-term value of our assets by taking full control of pre-FID work programmes and timing.

Following the successful extension of the Cambo license milestones from 31 March 2024 to 31 March 2026, the Group is actively engaging with potential farm-in partners to secure an aligned joint venture partnership that would enable the future progression of the Cambo project towards FID.

In line with the Group's BUILD strategy we continue to target high-return tie-back opportunities close to existing infrastructure to maximise reserve recovery. In 2023, the Group reported positive appraisal activity at its non-operated Leverett discovery (Ithaca Energy Working Interest: 12%) and successful exploration drilling at its operated K2 prospect (Ithaca Energy Working Interest: 50%), however, the subsequent side-track encountered significant operational issues due to severe weather caused by Storm Babet and the sidetrack was suspended.

Strong delivery against 2023 management guidance

Our production in 2023 averaged 70.2 kboe/d (2022: 71.4 kboe/d), closing the year towards the mid-point of our 68-74 kboe/d production guidance range. Production was split 66% liquids and 34% gas with the Group's operated assets accounting for 51% of total 2023 production.

Our production performance in 2023 has been supported by strong production efficiency across our operated base of 84%, reflecting our commitment to maximise asset value through operational excellence. Most notably at FPF-1, where our focus on value and our investment in driving operational efficiency and uptime improvements continues to yield production efficiency rates above 90%.

Production from our non-operated portfolio was impacted by the delayed start-up and curtailed production from the Pierce field, where operational issues related to the vessel mooring system have temporarily shut down production from the field. We expect this issue to be rectified during H1 2024.

Operating costs in 2023 of $524 million (2022: $496 million), representing a net unit Opex cost of $20.5/boe (2022: $19.0/boe), came in below revised and lowered management guidance of $525 million to $575 million, reflecting the Group's stringent focus on cost control in an inflationary environment, improved FX rates and a reduction in planned activity.

Total net producing asset capital expenditure (excluding decommissioning) of $393 million (2022: $405 million), came in at the bottom end of the Group's management guidance range of $390 million to $435 million. Net capital expenditure on the progression of the Rosebank development totalled $97 million, compared to management guidance of $90 million to $110 million reflecting the meaningful activity in 2023 as project activity ramps up to support a targeted 2026/27 first oil date.

During 2023, the Group launched a cost optimisation project focused on maintaining tight control on expenditure across our operated and non-operated assets and corporate overhead base. The project was successful in continuing to build upon Ithaca Energy's strong cost culture and delivered more than $100 million of cash savings during the year.

Strong safety performance is critical to our continued success

Safety is our non-negotiable, number-one priority and is central to our business success - we do it safely or not at all. The Group delivered a slightly improved safety performance in 2023, with fewer Tier 1 and Tier 2 process safety events recorded in the year (2023: 1 Tier 1 and 2 events, 2022: 2 Tier 1 and 2 events). However, we believe there are areas for continued improvement and the Group is responding to an increase in personal safety incidents and process safety near misses in the final quarter of the year by revisiting the tone of safety leadership across the business.

Major accident prevention has been a core focus area in 2023, with the introduction of a process safety barrier tool across all operating locations designed to strengthen our defences against high-potential incidents and process safety events. The Process Safety Fundamentals programme supports greater visibility of our Major Accident Hazard (MAH) risks and aims to enable front-line workers to focus on process safety where potential for MAH events present in day-to-day operations. We will continue to support the roll-out of the barrier tool in 2024 with the aim of improving our focus on process safety risks and maintaining focus on preventing high-consequence events.

 

Meaningful focus on Decarbonisation

As we continue to progress short-term emissions reductions projects, we have made significant progress towards our long-term emissions reduction strategy, following the decision to proceed with the development of the low emission intensity Rosebank field. Development of Rosebank will act as a material catalyst as the Group looks to fundamentally transition our portfolio to low-intensity assets in the medium to long-term, as older higher-intensity assets move closer to the natural end of their life.

The Rosebank FPSO has been designed to be electrification ready as part of its optimised design to reduce carbon emissions, in line with the North Sea Transition Deal. The Group is collaborating with Equinor (as Operator), industry partners and government to pursue a regional solution for power from shore to Rosebank and nearby fields to minimise carbon emissions from production. With full electrification, it is estimated that the Rosebank lifetime upstream CO2 intensity would decrease from 12kg to approximately 3kg CO2/boe - a seventh of the current UK average of 21kg CO2/boe and a fraction of the emissions intensity associated with importing.

The Group's Scope 1 and 2 GHG emissions across our operated profile reduced from 483,325 tCO2e in 2022 to 435,792 tCO2e in 2023, representing a slight increase per barrel from 23.8kg CO2/boe to 25.0kg CO2/boe, due to a reduction in operated assets production in 2023 versus 2022, and an absolute reduction of 23%, compared to our 2019 baseline. The 23% reduction achieved in 2023 versus the Group's 2019 baseline, reflects reductions achieved through operational improvements of 12%, as well as a 11% reduction in emissions associated with Alba's John Brown turbine outage during the year, which is not expected to be a recurring reduction. We continue to work hard to deliver our targeted 25% reduction in Scope 1 and 2 CO2e emissions on a net equity basis by 2025 and remain on track to reach this target.

2023 has seen continued progress across our operated portfolio delivering operational improvements at FPF- 1 and Captain, while expanding our focus to more material emission reduction initiatives such as the potential for electrifying our flagship Captain field. Following a successful conclusion of a pre-Front-End Engineering and Design (FEED) study in Q1 2023, FEED activity commenced in Q2 and has been matured to support a Financial Investment Decision in the coming months. With over 70% of Captain's GHG emissions related to power generation, partial electrification of the asset has the potential to substantially reduce emissions intensity and is critical to the Group's ability to achieve its targeted 50% reduction in Scope 1 and 2 CO2e emissions on a net equity basis by 2030. We continue to seek assurances from the UK government to ensure the protection of the decarbonisation allowance on sanctioned projects to protect the economic viability of the project. In parallel, the Group will determine investment viability as projects compete for capital following a reduction in cash flow available for reinvestment as a result of the continued impact of the Energy Profits Levy.

Robust cash flow generation supporting low leverage position

In 2023, we delivered another year of strong cash flow generation supporting the further strengthening of our balance sheet. Our diversified, high-quality asset base reported adjusted EBITDAX of $1.7 billion (2022: $1.9 billion), generated free cash flow of $0.7 billion (2022: $1.1 billion), lowering our adjusted net debt position to $571.8 million at year-end (2022: $971.2 million), representing an adjusted net debt to adjusted EBITDAX ratio of 0.33x (2022: 0.51x).

With a robust available liquidity position at 31 December 2023 of over $1 billion (2022: $0.6 billion), the Group has sufficient available capital to support our future growth plans. During 2023, we have entered into attractive lending arrangements that supplement our existing capital structure including a five-year $100 million term loan facility agreement with bp at a commercial interest rate, and a $150 million project capex carry arrangement which was unutilised at the year-end.

 

Profit for the year of $215.6 million (2022: $1,031.5 million), was impacted by a $557.9 million pre-tax impairment charge (post-tax $154.0 million), principally in relation to the Greater Stella Area (GSA) and Alba, together with other gains of $89.1 million in the period. The impairment charge for GSA follows the decision not to proceed with further infill drilling at Harrier, as a direct result of the Energy Profits Levy (EPL) and falling gas prices and in relation to Alba due to the reduction in estimated future production.

Following revisions to the Energy Profits Levy in November 2022, that saw the rate of EPL rise to 35%, the Group incurred current EPL charges of $333.4 million in the year (2022: $131.4 million), with the charge payable in October 2024. The Group's cash flows continue to be protected by our tax efficient structure with a material ring fence corporate tax and supplementary charge tax loss position of $4.5 billion at year-end.

The importance of the Group's robust hedging policy has been highlighted in the year, with hedging gains recorded of $266 million. As we move into 2024, we continue to take a disciplined approach to hedging, recognising the importance of balancing upside exposure to commodity prices while managing downside protection of our cash flows. At year-end, the Group has a hedged position of 8.2 million barrels of oil equivalent (mmboe) (57% oil) from 2024 into 2025 at an average price floor of $78/bbl for oil and 135p/therm for gas.

In our first full year as a listed company, we are delighted to report that our strong financial performance in the year has supported the delivery of our 2023 dividend target. The Board has declared a further interim dividend of $134 million in respect of the 2023 financial year, bringing our overall 2023 dividend to $400 million, representing ~30% post-tax cash flow from operations (CFFO) in the year.

Outlook

Following a successful year of progress against our BUY, BUILD and BOOST strategy in 2023, we enter 2024 with a strong and diverse portfolio of cash-generative assets and increased 2P Reserves and 2C Resources of 544 mmboe (2022: 512 mmboe) following the acquisition of the remaining stakes in Cambo and Fotla, offset by a full year of production. With further strengthening of our balance sheet in 2023, we are well positioned to continue to deliver against our capital allocation framework supporting our long-term growth aspirations.

Through strategic acquisitions we have preserved our investment optionality across our portfolio with significant brownfield and greenfield development opportunities such as Cambo, Marigold, Fotla and Tornado and infill drilling at Montrose, Schiehallion and Mariner. With further consolidation in the sector likely due to continued market dislocation, our focus in 2024 will be on prioritising investment across our portfolio alongside the potential for value-accretive M&A to maximise shareholder returns.

As a direct result of the Energy Profits Levy, investment across the UK North Sea during 2023 has been significantly impacted, as the UK competes for capital across global portfolios. Our 2024 production guidance of 56-61 kboe/dreflects the impact of deferred or cancelled projects across our operated and non-operated asset base including in the Greater Stella Area, Montrose Arbroath Area, Elgin Franklin Area and Alba.

Beyond 2024, the Group expects production growth through the medium-term with a return towards 80 kboe/d by 2027, as we see the full benefit of investment in our Captain EOR Phase II project and first production from the sanctioned Rosebank development.

Our operating cost guidance for 2024 of $540-590 million reflects our continued focus on cost control but increasing net costs from the $524 million 2023 outturn, due partly to tariff revenues reducing with lower third-party throughput at Greater Stella Area. As a result of forecasted reductions in 2024 volumes we expect an increase in unit operating cost per barrel in the short-term.

 

Our mid-term ambition is to drive down our average operating cost per barrel as we transition our portfolio to earlier-life assets from mature assets with a significantly lower unit operating cost profile.

Our producing asset capital cost guidance of $335-385 million (excluding capital investment for projects awaiting Final Investment Decision and Rosebank), reflects investment in executing the final stages of the Captain EOR Phase II project to completion and first injection in the subsea wells, continued drilling at Mariner and Schiehallion and facilities upgrades at Captain. In 2024, we forecast capital spend on the Rosebank development to be in the range of $190-230 million reflecting a significant ramp up of activities including FPSO upgrades and installation of subsea templates and satellites structures.

Ithaca Energy is targeting a 2024 dividend at the top end of its capital allocation policy range of 15 - 30% post-tax CFFO.

 

 

Enquiries

 

Ithaca Energy


Kathryn Reid - Head of Investor Relations, Corporate Affairs & Communications

kathryn.reid@ithacaenergy.com

FTI Consulting (PR Advisers to Ithaca Energy)

+44 (0)203 727 1000

Ben Brewerton / Nick Hennis / Rosie Corbett

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

$m

2023

$m

Depletion, depreciation and amortisation

(740.3)

(662.9)

Operating costs

(576.7)

(547.8)

Movement in inventory

20.6

(130.3)

Inventory provision

(16.3)

-

Royalties

(4.4)

(11.3)

Impairment charges

(557.9)

(31.5)

Exploration and evaluation

(13.6)

(9.0)

Other gains/losses

89.1

(9.5)

Administrative expenses

(34.3)

(87.9)

Gain on bargain purchase

-

1,335.2

Net finance costs

(184.0)

(203.0)

Total costs and charges

(2,017.8)

(358.0)

 

Depletion, depreciation and amortisation charges were $740.3 million (2022: $662.9 million). The year-on-year increase is principally due to the full-year effect of acquisitions made during 2022. Depletion, depreciation and amortisation per barrel was $29 (2022: $25).

 

Operating costs amounted to $576.7 million (2022: $547.8 million) with the increase driven by the full-year impact of acquisitions made in 2022. As noted above, unit operating expenditure increased principally as a result of the Q3 maintenance shutdowns.

 

Movements in oil and gas inventories was a credit of $20.6 million (2022: charge of $130.3 million) representing movements in underlift/overlift entitlement imbalances.

 

Materials inventory provisions of $16.3 million (2022: $nil) were made in respect of principally MonArb, Britannia and Elgin-Franklin.

 

Impairment charges of $557.9 million (2022: $31.5 million) principally reflects charges in respect of the Greater Stella area and Alba following changes in commodity prices and planned drilling activities due to EPL.

 

Exploration and evaluation costs amounted to $13.6 million (2022: $9.0 million) and principally related to licence relinquishments during the year as a result of unsuccessful geotechnical evaluation.

 

Other gains of $89.1 million (2022: losses of $9.5 million) comprise principally the settlement of a claim relating to a historic acquisition of $50.1 million and a $43.0 million gain on the revaluation and realisation of commodity hedges.

 

Administrative expenses were $34.3 million (2022: $87.9 million) with the decrease principally due to non-recurring costs associated with the IPO of $20.3 million and acquisition costs of $25.8 million in 2022.

Gain on bargain purchase in 2022 arose on the Marubeni and Siccar Point Energy acquisitions (see note 17 for further details).

 

Net finance costs were $184.0 million (2022: $203.0 million) with the reduction principally due to there no longer being interest on related-party loans which were repaid during 2022 and lower bank interest due to lower debt levels, partly offset by higher accretion charges as the discount rate on long-term liabilities has increased from 2.5% in the year to 31 December 2022 to 4.25% in the year to31 December 2023.

 

Taxation

 

The tax charge for the year was $86.4 million (2022: $1,029.0 million) with the reduction principally due to the introduction of the EPL last year. The charge for 2022 included an exceptional EPL deferred tax charge of $766.5 million and a current EPL tax charge of $131.4 million compared to a 2023 EPL deferred tax credit of $215.9 million and a current EPL tax charge of $333.4 million.

 

Earnings per share (EPS)

 

Statutory EPS was 21.4 cents (2022: 102.6 cents) and adjusted EPS was 36.7 cents (2022: 46.0 cents). Adjusted EPS eliminates items which distort year-on-year comparisons such as gain on bargain purchase, impairment charges, the tax effect of these items where applicable and the exceptional non-cash deferred EPL charge upon initial implementation in 2022.

Shares in issue

During the year, 7.8 million shares were issued to the Ithaca Energy plc Employee Benefit Trust (EBT) in order to satisfy the exercise of employee share options during the year and in future. As at 31 December 2023 there were 1,014.4 million (2022: 1,006.6 million) shares in issue.

The weighted average number of shares, excluding shares held by the EBT, for EPS calculations was 1,006.7 million (2022: 1,005.2 million).

Dividends

Interim dividends of $266.0 million (2022: $nil) were paid during the year. A further interim dividend for FY 2023 of $134.0 million will be paid in April 2024.

 

Financial position: assets/liabilities/equity

 


2023

$m

2023

$m

Total assets

6,246.6

6,759.6

Total liabilities

(3,802.2)

(4,302.1)

Net assets and shareholders' equity

2,444.4

2,457.5

 

Assets

At 31 December 2023, total assets amounted to$6,246.6 million (2022: $6,759.6 million), of which current assets were $845.6 million (2022: $988.7 million) and non-currents assets were $5,401.0 million (2022: $5,770.9 million). The decrease in total assets during the year was primarily due to fixed asset impairment charges of $557.9 million and lower cash balances of $100.6 million due to the repayment of debt partly offset by a higher deferred tax asset of $235.3 million due principally to the asset impairment charges.

 

Liabilities

 

At 31 December 2023, total liabilities amounted to $3,802.2 million (2022: $4,302.1 million) including decommissioning provisions of $1,859.7 million (2022: $1,720.5 million) and non-current borrowings of $718.2 million (2022: $1,213.7 million). The reduction in total liabilities during the year was primarily due to lower noncurrent borrowings of $495.5 million and a reduction in trade and other payables of $232.8 million due to a lower level of negative value commodity hedge positions, partly offset by higher decommissioning liabilities of $139.2 million, mainly due to revisions to asset retirement obligation estimates, and higher current tax payable of $214.4 million principally due to EPL.

Equity and reserves

 

At 31 December 2023, total equity and reserves amounted to $2,444.4 million (2022: $2,457.5 million) The decrease in equity and reserves during the year was primarily due to interim dividend payments of $266.0 million partly offset by the retained profit for the year of $215.6 million and net hedging gains of $23.9 million.

 

Financial position: cash


2023

$m

2023

$m

Opening cash

253.8

44.8

Operating cash flows

1,290.8

1,723.3

Investing cash flows

(492.4)

(1,404.2)

Financing cash flows

(900.7)

(107.4)

Foreign exchange

1.7

(2.7)

Net cash flow

(100.6)

209.0

Closing cash

153.2

253.8

Undrawn borrowing facilities

725.0

325.0

Undrawn capex carry facility

150.0

-

Available liquidity

1,028.2

578.8

 

Operating cash flows

Net cash from operating activities amounted to $1,290.8 million (2022: $1,723.3 million) after accounting for adverse working capital movements of $210.8 million (2022: favourable movements of $94.8 million) with the reduction principally due to lower operating profit, the working capital movements and higher corporation tax payments during the year.

 

Investing cash flows

Cash flow used in investing activities was $492.4 million (2022: $1,404.2 million) reflecting capital expenditure of $478.8 million (2022: $380.6 million) driven mainly by Captain enhanced oil extraction activities and Rosebank, including ongoing modifications to the FPSO. 2022 included investing cash flows related to acquisitions (net of cash acquired) of $957.4 million being primarily the Siccar Point Energy ($926.7 million) acquisition.

 

Financing cash flows

 

Cash outflow from financing activities amounted to $900.7 million (2022: $107.4 million) with dividend payments of $266.0 million (2022: $nil), interest costs and lease payments of $141.7 million (2022: $177.2 million) and a net reduction in principal debt of $500.0 million (2022: net increase of $50.0 million).

At 31 December 2023, cash balances were $153.2 million (2022: $253.8 million) and available liquidity was $1,028.2 million (2022: $578.8 million).

 

Principal risks

The principal and emerging risks facing the Group are the same as those set out in the H1 Trading Update.

 

Derivative financial instruments

 

Derivative financial instruments are utilised to manage commodity price risk in a substantive financial hedging programme for future oil and gas production volumes. As at 31 December 2023, the following hedges were in place:


2024

2025

Oil



Volume hedged (mmboe)

4.7

-

Weighted average floor hedged price ($/bbl)

78

-




Gas



Volume hedged (mmboe)

3.0

0.5

Weighted average floor hedged price

137

123

 

Subsequent events

On 6 March 2024, it was announced that EPL will be extended by a further year to 31 March 2029. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million.

 

On 19 March 2024, the North Sea Transition Authority sanctioned the extension of the licence on the Cambo field to 31 March 2026.

 

On 26 March 2024, the Group signed an exclusivity agreement between ENI and Ithaca Energy covering substantially all of ENI's UK upstream assets, excluding ENI CCUS and Irish sea assets, under which ENI has granted Ithaca exclusivity whilst a potential business combination is pursued. Under the terms of the proposed business combination ENI is anticipated to hold between 38% and 39% of the enlarged issued share capital of Ithaca Energy following completion.  If this progresses further, it will be subject to the issuance of both a Circular and a Prospectus and the related shareholder approvals and will also be subject to, amongst other things, regulatory approvals.

 

Going concern

Management closely monitor the funding position of the Group including monitoring continued compliance with covenants and available facilities to ensure sufficient headroom is maintained to fund operations.

 

Management have considered a number of risks applicable to the Group that may have an impact on the Group's ability to continue as a going concern. Short-term and long-term cash forecasts are produced on aweekly and quarterly/annual basis respectively along with any related sensitivity analysis. This allows proactive management of any business risks including liquidity risk.

 

The Directors consider the preparation of the financial statements on a going concern basis to be appropriate. This is due to the following key factors:

 

? Continuing robust commodity price backdrop and a well-hedged portfolio over the next 12 months;

 

? New unsecured loan arrangements of $100 million with bp which was fully drawn at 31 December 2023 and a new $150 million optional project specific capital expenditure carry arrangement available at the discretion of the Group which was undrawn at 31 December 2023;

 

? Reserves Based Lending (RBL) headroom of $836 million ($nil drawn versus $836 million available),plus $303 million of cash at 22 March 2024; and

 

? Robust operational performance and a well diversified portfolio

.

The Group's base case going concern assessment assumes an average oil price of $81/bbl and a gas price of 67p/therm in 2024 and an oil price of $77/bbl and a gas price of 75p/therm in the six months to 30 June 2025 with production in line with approved asset plans.

 

Owing to the ongoing fluctuations in commodity demand and price volatility, management prepared sensitivity analyses to the forecasts and applied a number of plausible downside scenarios including: decreases in production of 10%, reduced sales prices of 20% and increases in operating and capital expenditures of 10%. Management aggregated these scenarios to create a reasonable combined worst-case scenario. The sensitivity analysis showed that, after consideration of the mitigation strategies within management's control, there was no reasonably possible scenario that would result in the business being unable to meets its liabilities as they fall due. The analysis demonstrated that the Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 June 2025 to continue trading.

 

In addition reverse stress tests have been performed reflecting further reductions in commodity prices, prior to any mitigating actions, to determine at what levels they would have to reach such that either lending covenants are breached or there is no liquidity headroom left. This stress test demonstrated that the likelihood of the fall in price required to cause a breach of covenants or liquidity issue, is considered sufficiently remote in the context of the mitigation strategies available to management. The mitigation strategies within the control of management include the reduction in uncommitted capital expenditure and variable opex savings in the low production scenario. In addition to this, there is also further potential to refinance the Group's borrowing arrangements.

 

Based on their assessment of the Group's financial position over the period to 30 June 2025, the Directors believe that the Group will be able to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the consolidated financial statements.


Consolidated statement of profit or loss

For the year ended 31 December



 

Note

2023

US$'000

2022

US$'000

Revenue

5

2,319,811

2,598,482

Cost of sales

                                                                          

6

(1,317,010)

(1,352,324)

Gross profit

 

                                                                          

1,002,801

1,246,158

Impairment charges on development and production assets

19

(557,936)

(31,467)

Exploration and evaluation expenses

                                                                          

14

(13,634)

(9,040)

Administrative expenses

                                                                          

7

(34,259)

(87,851)

Other gains/(losses)

                                                                          

8

89,091

(9,429)

Gain on bargain purchase

                                                                          

17

-

1,335,171

Profit from operations before tax, finance income and finance costs

 

                                                                          

486,063

2,443,542

Finance income

9

5,688

695

Finance costs

                                                                          

9

(189,724)

(203,708)

Profit before tax

 

                                                                          

302,027

2,240,529

Income tax

27

(86,392)

(1,208,997)

Profit for the year


215,635

1,031,532

 

 

Earnings per share

 

 

 

Note

 

 

2023

Cents

 

 

2022

Cents

Basic

10

21.4

102.6

Diluted

10

21.2

102.1

 

The results above are entirely derived from continuing operations.




The accompanying notes on pages 23 to 75 are an integral part of the financial statements.





Consolidated statement of comprehensive income

For the year ended 31 December





 

Note

2023

US$'000

2022

US$'000

Profit for the year


215,635

1,031,532

Items that may be reclassified to profit and loss




Fair value gains on cash flow hedges

29

92,484

453,862

Fair value gains on cost of hedging


3,116

14,231

Deferred tax charge on cash flow hedges and cost of hedging

27

(71,700)

(200,455)

Other comprehensive income


23,900

267,638

Total comprehensive income for the year


239,535

1,299,170

 

The accompanying notes on pages 23 to 75 are an integral part of the financial statements.





Consolidated statement of financial position

as at 31 December



 

Note

2023

US$'000

2022

US$'000

Assets

 

                                                                          

 

 

Current assets

 

                                                                          

 

 

Cash and cash equivalents

 

                                                                          

153,215

253,822

Trade and other receivables

11

334,290

359,994

Decommissioning reimbursements

                                                                          

11

30,417

38,115

Prepaid expenses and decommissioning securities

                                                                          

12

37,678

9,055

Inventories

                                                                          

13

150,496

176,881

Derivative financial instruments

                                                                          

30

139,497

150,858

 

 

                                                                          

845,593

988,725

Non-current assets

 

                                                                          

 

 

Decommissioning reimbursements

11

165,064

162,710

Exploration and evaluation assets

                                                                          

14

548,354

775,773

Property, plant and equipment

                                                                          

15

3,258,206

3,634,896

Deferred tax assets

                                                                          

27

627,738

392,456

Derivative financial instruments

                                                                          

30

17,810

21,191

Goodwill

                                                                          

18

783,848

783,848



5,401,020

5,770,874

Total assets


6,246,613

6,759,599

Liabilities and equity

 

                                                                          

 

 

Current liabilities

 

                                                                          

 

 

Borrowings

20

(29,913)

-

Trade and other payables

                                                                          

22

(478,607)

(711,412)

Current tax payable

                                                                          

27

(321,116)

(106,678)

Decommissioning liabilities

                                                                          

23

(107,026)

(146,829)

Lease liability

                                                                          

24

(19,898)

(41,637)

Contingent and deferred consideration

                                                                          

25

(101,669)

(107,680)

Derivative financial instruments

                                                                          

30

(13,708)

(136,668)



(1,071,937)

(1,250,904)


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               

Consolidated Statement of financial position continued

As at 31 Deember

 

 



 

Note

2023

US$'000

2022

US$'000

Non-current liabilities




Borrowings

20

(718,238)

(1,213,731)

Decommissioning liabilities

23

(1,752,652)

(1,573,711)

Lease liability

24

(660)

(17,221)

Contingent and deferred consideration

25

(258,700)

(219,120)

Derivative financial instruments

30

-

(27,440)



(2,730,250)

(3,051,223)

Total liabilities


(3,802,187)

(4,302,127)

Net assets


2,444,426

2,457,472

Shareholders' equity




Share capital

26

11,540

11,445

Share premium

26

308,845

293,712

Capital contribution reserve

26

181,945

181,945

Own shares

26

(12,412)

-

Share-based payment reserve

26

15,494

4,920

Cash flow hedge reserve

29

39,818

16,710

Cost of hedging reserve

29

4,068

3,275

Retained earnings


1,895,128

1,945,465

Total equity


2,444,426

2,457,472

 

The accompanying notes on pages 23 to 75 are an integral part of the financial statements.




Approved on behalf of the Board on 26 March 2024:




Iain C S Lewis

Director





Consolidated statement of changes in equity For the year ended 31 December




 

Share

 

Share

Capital contribution


 

Share-based

 

Cash flow

 

Cost of





capital

premium

reserve

Own Shares

payment reserve

hedge reserve

hedging reserve

Retained earnings

Total


Note

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

Balance at 1 January 2022

 

1

634,658

114,000

-

-

(242,791)

(4,862)

175,503

676,509

Issuance of shares for capital reduction

26

114,000

-

(114,000)

-

-

-

-

-

-

                                                                                                                                                                                                                                                          

Reduction in capital

26

(114,000)

(634,658)

-

-

-

-

-

748,658

-

                                                                                                                                                                                                                                                          

Issuance of shares

26

11,444

293,712

-

-

(3,004)

-

-

(10,228)

291,924

                                                                                                                                                                                                                                                          

Capital contribution through debt cancellation

26

-

-

181,945

-

-

-

-

-

181,945

                                                                                                                                                                                                                                                          

Share-based payments

26

-

-

-

-

7,924

-

-

-

7,924

                                                                                                                                                                                                                                                          

Comprehensive income for the year:

 

 

 

 

 

 

 

 

 

 

Profit for the year

 

-

-

-

-

-

-

-

1,031,532

1,031,532

Other comprehensive income


-

-

-

-

-

259,501

8,137

-

267,638

Total comprehensive income for the year


-

-

-

-

-

259,501

8,137

1,031,532

1,299,170

Balance at 31 December 2022


11,445

293,712

181,945

-

4,920

16,710

3,275

1,945,465

2,457,472

Balance at 1 January 2023

 

11,445

293,712

181,945

-

4,920

16,710

3,275

1,945,465

2,457,472

Dividends

33

-

-

-

-

-

-

-

(265,972)

(265,972)

                                                                                                                                                                                                                                                          

Issuance of shares

26

95

15,133

-

(15,228)

-

-

-

-

-

                                                                                                                                                                                                                                                          

Share-based payments

26

-

-

-

2,816

10,574

-

-

-

13,390

                                                                                                                                                                                                                                                          

Comprehensive income for the year:

 

 

 

 

 

 

 

 

 

 

Profit for the year

 

-

-

-

-

-

-

-

215,635

215,635

Other comprehensive income


-

-

-

-

-

23,108

793

-

23,901

Total comprehensive income for the year


-

-

-

-

-

23,108

793

215,635

239,536

Balance at 31 December 2023


11,540

308,845

181,945

(12,412)

15,494

39,818

4,068

1,895,128

2,444,426

 

Detail on the movements in the capital contribution reserve can be found in notes 26 and 31. The ccompanying notes on pages 23to 75are an integral part of the financial statements.

Consolidated statement of cash flows

For the year ended 31 December



 

Note

2023

US$'000

2022

US$'000

Cash provided by/(used in):

 

                                                                          

 

 

Operating activities

 

                                                                          

 

 

Profit before tax

 

                                                                          

302,027

2,240,529

Adjustments for:

 

                                                                          

 

 

Depletion, depreciation and amortisation

15

740,300

662,947

Impairment of capitalised exploration and evaluation expenditure

                                                                          

14

13,634

9,040

Impairment charges on development and production assets

                                                                          

19

557,936

31,467

Increase in contingent/deferred consideration

                                                                          

 

                                                                          

8,008

4,295

Loan fee amortisation

9

4,508

6,418

Fair value gains on derivatives

                                                                          

29

(43,059)

(16,787)

Gain on bargain purchase

                                                                          

 

                                                                          

-

(1,335,170)

Hedging resets1

 

                                                                          

-

(39,680)

Accretion

9

76,162

56,511

Finance costs

                                                                          

9

109,054

122,163

Interest income

                                                                          

9

(5,688)

-

Interest on related-party loan

                                                                          

9

-

17,924

Unrealised foreign exchange on cash and cash equivalents

                                                                          

 

                                                                          

(1,725)

2,464

Share-based payment expenses

 

                                                                          

13,390

14,069

Decommissioning expenditure


(95,552)

(65,707)

Operating cash flows before movements in working capital

 

                                                                          

1,678,995

1,710,483

Decrease in inventories

 

                                                                          

26,386

4,051

Decrease/(increase) in trade and other receivables

 

                                                                          

12,540

(50,575)

(Decrease)/increase in trade and other payables


(249,760)

141,275

Operating cash flows

 

                                                                          

1,468,161

1,805,234

Corporation tax paid

 

                                                                          

(176,305)

(81,914)

Settlement of foreign exchange and commodity derivative financial instruments

29

(6,739)

-

Interest received

                                                                          

5,688

-

Net cash from operating activities


1,290,805

1,723,320


Consolidated statement of cash flows continued

For the year ended 31 December



 

Note

2023

US$'000

2022

US$'000

Investing activities

 

                                                                          

 

 

Capital expenditure

 

                                                                          

(478,838)

(380,640)

Acquisition of subsidiaries net of cash acquired

17

-

(957,452)

Deferred consideration payments

                                                                          

25

(6,367)

(55,092)

Contingent consideration payments

                                                                          

25

(7,200)

(11,040)

Net cash used in investing activities


(492,405)

(1,404,224)

Financing activities

 

                                                                          

 

 

Receipt from issue of equity

 

                                                                          

-

299,749

Dividends paid

 

                                                                          

(265,972)

-

Payments for lease liabilities (principal)

24

(41,902)

(34,348)

Repayment of RBL loan

                                                                          

 

                                                                          

(600,000)

(500,000)

Repayment of shareholder loan

 

                                                                          

-

(273,055)

Drawdown of RBL loan

 

                                                                          

-

550,000

Drawdown of bp loan

 

                                                                          

100,000

-

Bank interest and charges paid

 

                                                                          

(99,825)

(142,820)

Interest rate swaps

9

6,967

851

Costs of share issue

                                                                          

-

(7,825)

Net cash used in financing activities


(900,732)

(107,448)

Currency translation differences relating to cash


1,725

(2,675)

(Decrease)/increase in cash and cash equivalents


(100,607)

208,973

Cash and cash equivalents at 1 January


253,822

44,849

Cash and cash equivalents at 31 December


153,215

253,822

 

1. Hedging resets relate to the amortisation of the deferred reset gains which have been recycled to the current year profit and loss.




The accompanying notes on pages 23 to 75 are an integral part of the financial statements.





Notes to the consolidated financial statements

 

 

1. General information

Ithaca Energy plc (the Group or Ithaca Energy), is a Company limited by shares incorporated and domiciled in the UK and is a Group involved in the development and production of oil and gas in the North Sea. The Group's registered office is 33 Cavendish Square, London, United Kingdom, W1G 0PP.

The financial information for the years ended 31 December 2023 and 2022 contained in this document does not constitute statutory accounts of Ithaca Energy plc (the Company), as defined in section 435 of the Companies Act 2006. The financial information for the years ended 31 December 2023 and 2022 have been extracted from the consolidated financial statements of Ithaca Energy plc and all its subsidiaries (the Group), which were authorised by the Board of Directors on 26 March 2024 and which will be delivered to the Registrar of Companies in due course. The auditor's report on those financial statements was unqualified and did not contain a statement under section 498 of the Companies Act 2006.

2.  Basis of preparation

The consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standards (IAS) and in conformity with the requirements of the Companies Act 2006. The consolidated financial statements are presented in US Dollars as this is the functional currency of the business. All values are rounded to the nearest thousand (US$'000), except when otherwise indicated. The principal accounting policies applied in the preparation of the financial statements are set out below. These policies have been consistently applied to all the periods presented.

3.  Material accounting policies, judgements and estimation uncertainty

Basis of measurement

The consolidated financial statements have been prepared on a going concern basis using the historical cost convention, except for the revaluation of certain financial assets and financial liabilities, under International Financial Reporting Standards (IFRS), to fair value, including derivative instruments. Historical cost is generally based on the fair value consideration given in exchange for the assets and liabilities.

Going concern

Management closely monitor the funding position of the Group including monitoring compliance with covenants and available facilities to ensure sufficient headroom is maintained to fund operations. Management have considered a number of risks applicable to the Group that may have an impact on the Group's ability to continue as a going concern. Short-term and long-term cash forecasts are prepared on a weekly and quarterly/annual basis respectively along with any related sensitivity analysis. This allows proactive management of any business risk including liquidity risk.

The Directors consider the preparation of the financial statements on a going concern basis to be appropriate. This is due to the following key factors:

?     Continuing robust commodity price backdrop and a well-hedged portfolio over the next 12 months;

?     New unsecured loan arrangement of $100 million with bp which was fully drawn at 31 December 2023 and a new $150 million optional project specific capital expenditure carry arrangement available at the discretion of the Group which was undrawn at 31 December 2023;

?     Reserves Based Lending (RBL) liquidity headroom of $836 million ($nil drawn versus $836 million available), plus $303 million of cash as at 22 March 2024; and

?     Robust operational performance and a well-diversified portfolio.

 

Cash flow forecast - base case assumptions:


2024

H1 2025

Average oil price

$/bbl

81

77

Average gas price

p/th

67

75

Average hedged oil price (including floor price for zero cost collars)

$/bbl

78

N/A

Average hedged gas price (including floor price for zero cost collars)

p/th

137

123

 

Owing to the ongoing fluctuations in commodity demand and price volatility, management prepared sensitivity analyses to the forecasts and applied a number of plausible downside scenarios including decreases in production of 10%, reduced sales prices of 20% and increases in operating and capital expenditures of 10%. Management aggregated these scenarios to create a reasonable combined worst-case scenario. The sensitivity analysis showed that, after

consideration of mitigation strategies within management's control, there were was no reasonably possible scenario that would result in the business being unable to meet its liablilities as they fell due. In addition, reverse stress tests have been performed reflecting further reductions in commodity prices, prior to any mitigating actions, to determine at what levels prices would have to reach such that there is no liquidity headroom left. The stress test demonstrated that the likelihood of the fall in prices required to cause a liquidity issue is considered sufficiently remote in the context of the mitigation strategies available to management. The mitigation strategies within the control of management include a reduction in uncommitted capital expenditure and variable opex savings in the low production scenario. In addition to this, there is also further potential to refinance the Group's borrowing arrangements. The analysis demonstrated that the Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 June 2025 to continue trading.

 

3. Material accounting policies, judgements and estimation uncertainty continued

Based on their assessment of the Group's financial position in the period to 30 June 2025, the Directors believe that the Group will be able to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the financial statements.

 

Basis of consolidation

The consolidated financial statements of the Group includes the financial information of Ithaca Energy and all wholly-owned subsidiaries as listed per note 31. All intergroup transactions and balances have been eliminated on consolidation.

Subsidiaries are all entities over which the Group has control. The plc controls an entity when the Group is exposed to or has rights to variable returns from its investments with the entity and has the ability to affect those returns through its power over the investee. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated on the date that control ceases.

Impact of climate change on the financial statements and related notes

Judgements and estimates made in assessing the impact of climate change and the energy transition

Climate change and the transition to a lower-carbon system were considered in preparing the consolidated financial statements. These may have the potential for significant impacts on the carrying values of the Group's assets and liabilities discussed below as well as on assets and liabilities that may be reflected in the future. There is also the potential for significant impact on future cash flows. There is generally a high level of uncertainty about the speed and magnitude of impacts of climate change which, together with limited historical data, provides significant challenges in the preparation of forecasts and financial plans with a wide range of potential future outcomes.

The Group's ambition is to have one of the lowest carbon emission portfolios in the UK North Sea and to achieve Net Zero (whereby the amount of CO2 added by the Group's activities is no greater than the amount taken away), on a net equity basis (by applying the Group's working interest in each respective asset to the total emissions of that asset), and in respect of Scope 1 and 2 emissions, by 2040, ten years ahead of the North Sea Transition Deal commitment. This will be achieved by optimising the Group's current portfolio in the short term and fundamentally transitioning the Group's portfolio over the medium to long term whilst maintaining forecast levels of production. Initiatives include, but are not limited to, operational improvements, offshore electrification, and the eventual cessation of production of mature fields which have higher carbon intensity. Where the Group cannot reduce Scope 1 and Scope 2 emissions, Ithaca Energy will invest in carbon offsets to achieve the Group's goal of Net Zero. All new economic investment decisions include estimated costs of the energy transition based on existing technology and estimated costs of carbon and these opportunities are assessed on their climate impact potential and alignment with Ithaca Energy's Net Zero target, taking into account both greenhouse gas volumes and emissions intensity.

Specific considerations of the potential impacts of climate change on significant judgements and estimates used in the consolidated financial statements are considered below. The items outlined below are likely to manifest themselves over a number of years and are therefore not generally considered to represent 'key sources of estimation uncertainty' as required by IAS 1 (being those which could have a material impact on the Group's results in the 12 months following the reporting date) which are separately disclosed later in this note.

Impairment of goodwill and property, plant and equipment

The energy transition has the potential to significantly impact future commodity and carbon prices in that as the UK and global energy system decarbonises, reduced demand for oil and gas products in favour of low carbon alternatives could cause oil and gas prices to fall which would, in turn, affect the recoverable amount of goodwill and property, plant and equipment. In the current period management's estimate of the long-term commodity price assumptions are, in real terms from 2028, $93/bbl for Brent Crude and 87p/therm for UK NBP gas. Further details of climate change including a sensitivity in this area are provided in note 19.

Recoverable values used for impairment testing for all cash-generating units (CGUs) include the estimated cost of UK carbon emissions allowances of £70 per tonne for CO2e. The recoverable value of CGU's may be impacted by future carbon pricing legislation changes, which could increase operating costs through higher emissions allowances or the introduction of other carbon pricing mechanisms. Electrification of offshore operations for specific assets is planned in line with the Group's 2040 Net Zero ambitions and where feasible based on existing technology, estimated electrification costs are included within the assessment of the recoverable value of the relevant CGU.

Property, plant and equipment - depreciation and useful economic lives

The energy transition has the potential to reduce the expected useful economic lives of assets and hence accelerate depreciation charges. Although no changes have been identified or recognised to date, as noted in the Strategic Report on page [XX], it is anticipated that certain higher emission-intensity assets such as FPF-1 and Alba will cease production in the medium term and will be replaced by new lower-emission intensity assets. Management does not currently expect the useful economic lives of the Group's reported property, plant and equipment to significantly change solely as a result of the energy transition. However, significant capital expenditure is still required for ongoing projects and therefore the useful lives of future capital expenditure may be different

.

Intangible assets - exploration and evaluation assets

The impacts of climate change and the energy transition may affect the viability of exploration prospects. The recoverability of the existing intangibles was considered during 2023, however, no significant write-offs were identified as a result of climate change considerations. Viability of these assets will continue to be assessed on a regular basis.

Decommissioning provisions

Most of the Group's existing decommissioning obligations are estimated to be completed over the course of the next 20 years. The impacts of climate change and the energy transition may bring forward the expected timing

of decommissioning activity, increasing the present value of the associated decommissioning provisions. The potential impact of a reasonably possible acceleration of estimated decommissioning dates, which considers the potential impact of the energy transition, is considered to be two years. The impact of such an acceleration of cessation of production across the Group's entire producing portfolio would result in an increase in the decommissioning provision of approximately $69 million (2022: $74 million). The risk in this area may increase if key assets within the Group's existing exploration, appraisal and development portfolio proceed to the production stage, as this is likely to significantly extend the life of the Group's portfolio, in some cases to 2050 or beyond.

While the pace of the transition to a lower-carbon economy is uncertain, oil and gas demand is expected to remain a key element of the energy mix for many years based on stated policies, commitments and announced pledges to reduce emissions. Therefore given the estimated useful lives of the Group's oil and gas portfolio, a material adverse change is not anticipated to the carrying value of the Group's assets and liabilities in the short-term as a result of climate change and the transition to a lower-carbon economy.

Business combinations

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the consideration given for the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Transaction costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of the Group's share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition is less than the Group's share of the net assets acquired, the difference is recognised directly in the consolidated statement of profit or loss as a gain on bargain purchase.

Goodwill

Capitalisation

Goodwill is initially recognised and measured as set out above. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses.

Impairment

Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU or group of CGUs to which the goodwill relates. If the recoverable amount of a CGU is less than its carrying amount, the impairment loss is allocated first to reduce the carrying amount of goodwill allocated to the unit and then to the other assets of the unit pro-rata based on the carrying amount of each asset in the unit. Any impairment loss is recognised in the consolidated statement of profit or loss. Impairment losses relating to goodwill cannot be reversed in future periods. The CGU for the purposes of the goodwill test is the North Sea, i.e. the entire Group portfolio of oil and gas assets which is consistent with the operating segment view of the business.

Interest in joint ventures and associates

Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. Associates are investments over which the Group has significant influence but not control or joint control, and generally holds between 20% and 50% of the voting rights.

The Group's interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation and its expenses (including its share of any expenses incurred jointly).

Revenue

The sale of crude oil, gas or condensate represents a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue is accordingly recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. Revenue is recognized at a point in time and is measured based on the consideration to which the group expects to be entitled in a contract with a customer and excludes amounts collected for third parties. Details of hedging gains and losses presented in revenue are discussed in the hedging acccounting policy set out below.

 

3. Material accounting policies, judgements and estimation uncertainty continued

Tariff income is recognised as the underlying commodity is shipped through the pipeline network based on established tariff rates.

Foreign currency translation

Items included in these consolidated financial statements are measured using the currency of the primary economic environment in which the Group and its subsidiaries operate (the functional currency). The consolidated financial statements are presented in US Dollars, which is the Group's presentation currency as well as the functional currency of the Parent Company and each of its subsidiaries. In preparing the financial statements of the parent and its subsidiaries, trans actions in currencies other than the entity's functional currency (foreign currencies) are recognised at the rates of exchange prevailing on the dates of the transactions. At each reporting date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing at that date. Non-monetary items carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Non-monetary items that are measured in terms of historical cost in a foreign currency are not retranslated.

Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of profit or loss.

Exchange differences are recognised in profit or loss in the period in which they arise except for:

?     Exchange differences on foreign currency borrowings relating to assets under construction for future productive use, which are included in the cost of those assets when they are regarded as an adjustment to interest costs on those foreign currency borrowings;

?     Exchange differences on transactions entered into to hedge certain foreign currency risks (see below under financial instruments/hedge accounting).

Financial instruments

All financial instruments are initially recognised at fair value on the statement of financial position. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

The Group derecognises a financial asset only when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another entity. The Group derecognises financial liabilities when, and only when, the Group's obligations are discharged, cancelled or have expired. The difference between the carrying amount of the financial asset or financial liability derecognised and the consideration received/receivable or paid/payable respectively is recognised in profit or loss.

IFRS 9 classifications:

Cash and cash equivalents are classified at amortised cost which equates to its fair value. Accounts receivable and long-term receivables are classified and carried at amortised cost less expected credit losses as they have a business model of held to collect and the terms of the financial instrument meet the solely payments of interest on principle outstanding. Accounts payable, accrued liabilities, certain other long-term liabilities, and borrowings are classified as other financial liabilities and carried at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium. Contingent consideration is measured at fair value though profit or loss. Although the Group does not intend to trade its derivative financial instruments, they are required to be carried at fair value with the treatment of fair value movements explained further below.

Interest-free loans from parents are initially recognised at fair value. The difference between the fair value of the loans and the nominal value is accounted for as a capital contribution and is credited to equity. After initial recognition, the loans are measured at amortised cost using implied interest rate of the notes.

Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability and original issue discounts on long-term debt have been included in the carrying value of the related financial asset or liability and are amortised to consolidated net earnings over the life of the financial instrument using the effective interest method.

Impairment of financial assets

For trade receivables and accrued income, the Group applies a simplified approach in calculating expected credit losses (ECLs). Therefore, the Group does not track changes in credit risk, but instead, recognises any material loss allowance based on lifetime ECLs at each reporting date. For all other financial assets, the Group measures the loss allowance using 12-month expected credit losses unless there was a significant increase in credit risk since initial recognition in which case the loss allowance is measured using lifetime expected credit losses.

In making this assessment whether the credit risk increased significantly since initial recognition, the Group considers both quantitative and qualitative information that is reasonable and supportable, including historical experience and forward-looking information that is available without undue cost or effort. The Group considers that the credit risk increased significantly since initial recognition when the credit rating changes, the debtor has significant financial difficulty or if there was a breach of contract. For balances that are beyond 30 days overdue it is presumed to be an indicator of a significant increase in credit risk.

The Group considers a financial asset in default when contractual payments are 90 days past due. However, in certain cases, the Group may also consider a financial asset to be in default when internal or external information indicates that the Group is unlikely to receive the outstanding contractual amounts in full before taking into account any credit enhancements held by the Group.

A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. Financial assets written off may still be subject to enforcement activities under the Group's recovery procedures, taking into account legal advice where appropriate. Any recoveries made are recognised in profit or loss.

Derivative financial instruments

The Group enters into a variety of derivative financial instruments to manage its exposure to commodity risks, interest rate and foreign exchange rate risks. These instruments include: commodity swaps, collars and options; foreign exchange forward contracts and collars; and interest rate swaps. Further details of derivative financial instruments are disclosed in notes 29 and 30.

Derivatives are recognised initially at fair value at the date a derivative contract is entered into and are subsequently remeasured to their fair value at each reporting date. The resulting gain or loss on remeasurement of derivatives is recognised in profit or loss immediately unless the derivative is designated in a hedge relationship and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship.

A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a financial liability. Derivatives are not offset in the financial statements unless the Group has both a legally enforceable right and intention to offset. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than 12 months and it is not due to be realised or settled within 12 months. Other derivatives maturing in less than 12 months and expected to be realised or settled in less than 12 months are presented as current assets or current liabilities.

Hedge accounting

The Group designates certain derivatives as hedging instruments in respect of commodity risks in cash flow hedges.

At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is highly effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk.

If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again.

 

The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the cost of hedging reserve. If the hedged item is transaction-related, the time value is reclassified to profit or loss when the hedged item affects profit or loss. If the hedged item is time-period related, then the amount accumulated in the cost of hedging reserve is reclassified to profit or loss on a rational basis - the Group applies straight-line amortisation. Those reclassified amounts are recognised in profit or loss in the same line as the hedged item. If the Group expects that some or all of the loss accumulated in the cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.

The effective portion of changes in the fair value of derivatives and other qualifying hedging instruments that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated under the heading of cash flow hedge reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss, and is included in the 'other gains and losses' line item.

 

3. Material accounting policies, judgements and estimation uncertainty continued

Amounts previously recognised in other comprehensive income and accumulated in equity are reclassified to profit or loss in the periods when the hedged item affects profit or loss, in the same revenue line as the recognised hedged item. However, when the hedged forecast transaction results in the recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognised in other comprehensive income and accumulated in equity are removed from equity and included in the initial measurement of the cost of the non-financial asset or non-financial liability. This transfer does not affect other comprehensive income. Furthermore, if the Group expects that some or all of the loss accumulated in the cash flow hedge reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.

The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in the cash flow hedge reserve is reclassified immediately to profit or loss.

If a hedge of a transaction related item is discontinued part way through the life of the hedge (e.g. due to early termination of the swap, hedging resets), but the hedged item is still expected to occur, the amounts deferred in equity would remain in equity until the earlier of: (i) the hedged transaction occurring; or (ii) expectation that the amount deferred in equity will not be recovered in the future periods.

Note 29 and note 30 set out details of the fair values of the derivative instruments used for hedging purposes and movements in the hedging reserve in equity are detailed in note 29.

Contingent and deferred consideration

Contingent consideration in relation to a business combination or asset acquisition is accounted for as a financial liability and measured at fair value at the date of acquisition with any subsequent remeasurements recognised in profit or loss in accordance with IFRS 9. These fair values are generally based on risk-adjusted future cash flows discounted using appropriate discount rates. Changes in fair value of the contingent consideration that qualify as measurement period adjustments are adjusted retrospectively, with corresponding adjustments against goodwill. Measurement period adjustments are adjustments that arise from additional information obtained during the 'measurement period' (which cannot exceed one year from the acquisition date) about facts and circumstances that existed at the acquisition date.

The subsequent accounting for changes in the fair value of the contingent consideration that do not qualify as measurement period adjustments depends on how the contingent consideration is classified. Contingent consideration that is classified as equity is not remeasured at subsequent reporting dates and its subsequent settlement is accounted for within equity. Other contingent consideration is remeasured to fair value at subsequent reporting dates with changes in fair value recognised in profit or loss.

Deferred consideration is measured at amortised cost because the amount payable in the future is fixed.

Settlement of contingent consideration is recorded as investing outflows in the cash flow statement to the extent that cumulative amounts paid do not exceed the amount recognised at the date of acquisition, with any excess recorded as an operating cash outflow. Settlement of deferred consideration is recorded as either an investing or financing outflow in the cash flow statement, depending on the substance of the arrangement at inception. Key considerations

in forming this judgment will include the extent of inferred financing costs included in the overall consideration arrangements at acquisition, the period of time over which the payments are made, the rationale for agreeing to defer elements of the consideration and the general level of funding resources available to the Group at the time of acquisition.

Cash and cash equivalents

For the purpose of the statement of cash flow, cash and cash equivalents include investments with an original maturity of three months or less. In the statement of financial position, cash and bank balances comprise cash (i.e. cash on hand and demand deposits) and cash equivalents. Cash equivalents are short-term (generally with original maturity of three months or less), highly-liquid investments that are readily convertible to a known amount of cash and which are subject to an insignificant risk of changes in value. Cash equivalents are held for the purpose of meeting short-term cash commitments rather than for investment or other purposes.

Inventories - hydrocarbon and materials

Inventories of materials are stated at the lower of cost and net realisable value. Cost comprises direct materials and, where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition. Cost is determined on the first-in, first-out method. Current hydrocarbon inventories are stated at net realisable value, which is based on estimated selling price less any further costs expected to be incurred to completion and disposal/sale. Non-current oil and gas inventories are stated at historic cost. Provision is made for obsolete, slow-moving and defective items where appropriate.

Lifting or offtake arrangements

 

Lifting or offtake arrangements for oil and gas produced in certain of the Group's oil and gas properties are such that each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative volume sold is an 'underlift' included within inventories, and 'overlift' is included within trade and other payables in the statement of financial position. Both are stated at net realisable value. Movements during an accounting period are adjusted through cost of sales in the consolidated statement of profit or loss.

Exploration and evaluation assets

Oil and gas expenditure - exploration and evaluation (E&E) assets

Geological and geophysical costs and costs incurred pre-licence are expensed as incurred. Costs directly associated with an exploration well are initially capitalised as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, freight costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is, the efforts are not successful, then the costs are expensed.

Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal

wells where hydrocarbons were not found, are initially capitalised as an intangible asset. Upon external approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is first assessed for impairment and, if required, an impairment loss is recognised. The remaining balance is then transferred to development and production (D&P) assets. If development is not approved and no further activity is expected to occur, then the costs are expensed.

The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially economic quantities of oil and natural gas in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required before production could begin and where the economic viability of that major capital expenditure depends on the successful completion of further exploitation or appraisal work in the area remain capitalised on the balance sheet as long as such work is under way or firmly planned.

 

Property, plant and equipment

Oil and gas expenditure - D&P assets

 Capitalisation

Costs of bringing a field into production, including the cost of facilities, wells and subsea equipment, direct costs including staff costs together with E&E assets reclassified in accordance with the above policy, are apitalized as a D&P asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset.

Depreciation

All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset generally on a field-by-field basis. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset.

Non-oil and natural gas operations

Non-oil and gas assets are initially recorded at cost and depreciated over their estimated useful lives on a straight-line basis as follows-

 

Buildings

10 years

Computer and office equipment

3 years

Furniture and fittings

5 years

 

3. Material accounting policies, judgements and estimation uncertainty continued

Impairment

For impairment review purposes the Group's oil and gas assets are aggregated into CGUs typically on a field-by-field basis for development and production assets in accordance with IAS 36, and on a North Sea segment basis for exploration and evaluation assets in accordance with IFRS 6. A review is carried out at each reporting date for any indicators that the carrying value of the Group's assets may be impaired or previously impaired assets (excluding goodwill) where a reversal of a previous impairment may arise. Such reviews are carried out on a field-by-field basis for both development and production assets and exploration and evaluation assets. For assets where there are such indicators, an impairment test is carried out on the CGU. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to the recoverable amount. The resulting impairment losses are written off to the consolidated statement of profit or loss. Previously impaired assets (excluding goodwill) are reviewed for possible reversal of previous impairment at each reporting date. The maximum possible reversal is capped at the net book value had the asset not been impaired in the past. Where an exploration and evaluation licence is relinquished, amounts capitalised in respect of the licence are witten off to profit or loss in the period in which the licence is relinquished.

Borrowing costs

Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets until such time as the assets are substantially ready for their intended use or sale. All other borrowing costs are expensed as incurred. Borrowing costs directly attributable to E&E assets are not capitalised and are expensed directly to profit or loss when incurred.

Decommissioning liabilities

The Group records the present value of legal obligations associated with the retirement of long-term tangible assets, such as producing well sites and processing plants, in the period in which they are incurred with a corresponding increase in the carrying amount of the related long-term asset. Liabilities for decommissioning are recognised when the Group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and restore the site on which it is located, and when a reliable estimate can be made. Where the obligation exists for a new facility or well, such as oil and gas production or transportation facilities, the obligation generally arises when the asset is installed or the ground/environment is disturbed at the field location. In subsequent periods, the asset is adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. The carrying amounts of the associated decommissioning assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred. The unwinding of discount in the net present value of the total expected cost is treated as an interest expense. Changes in the estimates are reflected prospectively over the remaining life of the field.

Where some or all of the expenditure required to settle a provision is expected to be reimbursed by another party, a reimbursement asset is recognised when, and only when, it is virtually certain that reimbursement will be received if the entity settles the obligation. The amount recognised for the reimbursement may not exceed the amount of the provision.

Taxation

Current tax

Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted by the reporting date. Taxable profit differs from net profit, as reported in the consolidated statement of profit or loss, because it excludes items of income or expense that are taxable or deductible in other accounting periods and it further excludes items of income or expenses that are never taxable or deductible.

Deferred tax

Deferred tax is recognised using the liability method, providing for temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax is measured at the tax rates that are expected to be applied to the temporary differences when they reverse, based on the laws that have been enacted or substantively enacted at each balance sheet date. Deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill and deferred tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred tax assets are recognised only to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each balance sheet date and all available evidence is considered in evaluating the recoverability of these deferred tax assets. Deferred tax assets and liabilities are offset where there is a legally enforceable right to offset current tax assets and liabilities relating to taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis.

 

Deferred Petroleum Revenue Tax (PRT) assets are recognised where PRT relief on future decommissioning costs is probable.

 

Leases

The Group assesses at contract inception all arrangements to determine whether it is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Group is not a lessor in any transactions, it is only a lessee. The Group recognises a right-of-use asset and a corresponding lease liability with respect to all lease arrangements in which it is the lessee. The Group has elected to apply Paragraph 6 of IFRS 16 to short-term leases (defined as leases with a lease term of 12 months or less) and leases of low-value assets (such as tablets and personal computers, small items of office furniture and telephones). Lease payments associated with these leases are expensed over the relevant lease term.

Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The right-of-use asset is depreciated over the useful life of the asset.

The Group's right-of-use assets are included in property, plant and equipment (note 15).

At the commencement date of the lease, the Group recognises lease liabilities measured at the present value of lease payments to be made over the lease term. In calculating the present value of lease payments, the Group uses its incremental borrowing rate at the lease commencement date because the interest rate implicit in the lease is generally not readily determinable. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments (e.g. changes to future payments resulting from a change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the underlying asset.

Maintenance expenditure

Expenditure on major maintenance refits or repairs is capitalised where it enhances the life or performance of an asset above its originally assessed standard of performance, replaces an asset or part of an asset which was separately depreciated and which is then written off, or restores the economic benefits of an asset which has been fully depreciated. All other maintenance expenditure is charged to the statement of profit or loss as incurred.

Share-based payments

The Group issues equity-settled share-based payments to certain employees. Equity-settled share-based payments are measured at fair value at the date of grant. The fair value is expensed over the vesting term either on a straight-line basis or as specified in the vesting terms, based on the Group's estimate of shares that will eventually vest and is adjusted for the effects of non-market-based vesting conditions.

Fair value is measured by using a Black-Scholes or other appropriate valuation model. The expected life used in the model is adjusted based on management's best estimate for the effects of non-transferability, exercise restrictions and behavioural considerations.

Retirement benefit costs

The Group operates a defined contribution pension scheme and payments into this plan are charged as an expense as they fall due. There is no further obligation to pay contributions into the plan once the contributions specified in the plan rules have been paid.

Short-term employee benefits

A charge or liability is recognised for benefits accruing to employees in respect of salaries, bonuses, annual leave and sick leave in the period the related service is rendered at the undiscounted amount of the benefits expected to be paid for that service. Charges or liabilities recognised in respect of short-term employee benefits are measured at the undiscounted amount of the benefits expected to be paid in exchange for the related service.

 

Non-GAAP measures

In measuring the Group's adjusted operating performance, additional financial measures derived from the reported results have been used by management in order to eliminate factors which distort year-on-year comparisons. The Group's adjusted performance is used to explain year-on-year changes when the effect of certain items is significant, including material impairment charges or reversals, non-cash bargain purchase credits, the tax effect of these items where applicable and non-cash deferred tax charges on the initial application of EPL.

Adjusted EBITDAX, adjusted net income, adjusted EPS, unit operating expenditure, leverage ratio, adjusted net debt and certain other reported metrics are non-GAAP measures that are not specifically defined under IFRS or other generally accepted accounting principles. Further details are set out on pages 76 to 78.

 

3. Material accounting policies, judgements and estimation uncertainty continued

Changes in accounting pronouncements

The Group has adopted all new and amended IFRS Standards effective in the consolidated financial statements for the period 1 January 2022 to 31 December 2023 including IFRS 17 Insurance Contracts. There was no impact of this or of any of the amendments to existing standards and interpretations which were effective from 1 January 2023.

New and revised IFRS Standards in issue but not yet effective

At the date of authorisation of these consolidated financial statements, the Group has not applied the following revisions to IFRS Standards that have been issued but are not yet effective.

 

Amendments to IFRS 10 and IAS 28

Sale or Contribution of Assets between an Investor and its Associate or Joint Venture

Amendments to IAS 1

Classification of Liabilities as Current or Non-current

Amendments to IAS 1

Non-current liabilities with Covenants

Amendments to IAS 7 and IFRS 7

Supplier Finance Arrangements

Amendments to IFRS 16

Lease Liability in a Sale and Leaseback

Amendments to IAS 21

The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability

The Company does not expect that the adoption of the amendments listed above will have a material impact on the consolidated financial statements of the Group in future periods.

Critical judgements and key sources of estimation uncertainties Key sources of estimation uncertainty

The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.

Decommissioning provision estimates

Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements, technology and price levels,

the carrying amounts of decommissioning provisions are reviewed on a regular basis. The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. For operated assets, cost estimates are based on management's assessment of work programmes (including durations) and supply chain conditions including, amongst other factors, applicable vessel and rig rates and durations. For non-operated assets, cost estimates are arrived at by management's review of the basis of estimates as provided by the respective operators.

While the Group uses its best estimates and judgement, actual results could differ from these estimates. Expected timing of expenditure can also change, for example in response to changes in laws and regulations or their interpretation, and/or due to changes in commodity prices. The payment dates are uncertain and depend on the production lives of the respective fields. Management does not expect any reasonable change in the expected timing of decommissioning to have a material effect on the decommissioning provisions, assuming cash flows remain unchanged. Decommissioning costs are expected to be incurred over the next 40 years. A nominal discount rate of 4.60% (2022: 4.25%),

based on the average risk-free rate over the second half of 2023, is used to discount the estimated costs. The inflation rate applied to estimated costs is 2.0% (2022: 2.0%). Given the long-term nature of the Group's decommissioning liabilities and the historic compounded inflation rates in the industry, management do not believe that the current short-term inflationary pressures will have a material impact on the decommissioning liabilities of the Group. A reduction or an increase in this discount rate of 1% would increase or reduce the decommissioning liabilities by approximately $223 million or $188 million respectively (2022: $218 million or $201 million respectively), and is not expected to have a material impact on the corresponding decommissioning reimbursement asset. For further details regarding the estimated value, inputs and assumptions refer to note 23. Given the large number of variables involved, management consider that it is not practical to provide sensitivities for the various other individual assumptions.

 

Contingent consideration

Liabilities for contingent consideration have been recognised on certain business combinations, which are measured at fair value at acquisition and remeasured at fair value through profit and loss at each reporting date.

The amounts of contingent consideration ultimately payable depend on several factors, including the progress of certain of the oil and gas properties acquired and the achievement of certain production and commodity price thresholds. Management has estimated the fair value as the aggregate value of each element of the contingent consideration in each case using an appropriate valuation technique, taking into account the likelihood of occurrence of each contingent event and the net present value of the amount potentially payable. Where applicable, risking assumptions applied in the measurement of contingent consideration were consistent with those applied in the fair valuation of the related oil and gas properties.

A 20% decrease in probability of payment, with all other assumptions held constant, would result in a decrease in contingent consideration of $97.1 million (2022: $87.1 million). Whereas a 20% increase in probability of payment, with all other assumptions held constant, would result in an increase in contingent consideration of $84.1 million (2022: $83.6 million).

Other areas of estimation

The key assumptions concerning the future, and other sources of estimation uncertainty at the reporting period, but are not expected to cause a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below:

Taxation estimates

The Group's operations are subject to a number of specific tax rules which apply to exploration, development and production companies such as the Energy Profits Levy at 35%, ring-fenced Corporation Tax at 30%, the Supplementary Charge of 10% and the application of investment allowances. In addition, the tax provision is prepared before the relevant companies have filed their tax returns with the relevant tax authorities and, significantly, before these have been agreed. As a result of these factors, the tax provision process necessarily involves the use of a number of judgements and estimates including those required in calculating the effective tax rate. The Group recognises deferred tax assets on unused tax losses where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the likelihood of future taxable profits and the amount of deferred tax that can be recognised. Further details regarding the estimated value and related inputs are set out in note 27.

The Group's deferred tax assets are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised, including as a result of Group re-organisations and asset transfers. In accordance with IAS 12 Income Taxes, the Group assesses the recoverability of its deferred tax assets at each period end. Consistent with the impairment sensitivity described above, as at 31 December 2023, a 20% reduction in future revenues, with all other assumptions held constant, would eliminate current headroom and result in a deferred tax asset derecognition of $304 million (2022: $24 million). It should be noted that mitigating actions are considered to be available to materially offset this impact. An increase in future revenues would result in no additional deferred tax asset recognition on the basis that deferred tax assets are already recognised in full. The $304 million (2022: $24 million) de-recognition assumes that cash flows are equivalent to taxable profits and that any reorganisation required to utilise certain deferred tax assets does not result in a displacement of other balances.

Estimates in oil and gas reserves and contingent resources

The Group's estimates of oil and gas reserves and contingent resources, and the associated production forecasts, are used in the impairment testing of property plant and equipment and goodwill, in the measurement of depletion and decommissioning provisions, the measurement of certain elements of contingent consideration, the going concern assessment, the viability assessment and in the determination of whether deferred tax assets are recoverable. The business of the Group is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner. Estimates of oil and gas reserves and contingent resources require critical judgement. Factors such as the availability of geological and engineering data, reservoir performance data, drilling of new wells and estimates of future oil and gas prices all impact on the determination of the Group's estimates of its oil and gas reserves which could result in different future production profiles affecting prospectively the discounted cash flows used in impairment testing.

The Group's estimates of reserves and resource volumes used for accounting purposes are built up from historically-matched models for operated assets and principally from operators' estimates for non-operated assets. A review process is undertaken to compare the results of the Group's internal estimates to those of an independent consultant to understand any differences in underlying assumptions to ensure there are no material unreconciled differences between the estimates.

For the purposes of depletion and decommissioning estimates, the Group uses proved and probable reserves; and for the purposes of the impairment tests performed and deferred tax asset recoverability, the Group considers the same proved and probable reserves as well as risked resource volumes. These risking adjustments are reflective of management's assessment of technical and commercial factors that reflect the value considerations of a market participant. Changes in estimates of oil and gas reserves and resources resulting in different future production profiles will affect the discounted cash flows used in impairment testing, the anticipated date of decommissioning, the depletion charges in accordance with the unit of production method and the recoverability of deferred tax assets. The sensitivity of the Group's impairment tests and deferred tax recoverability assessments to key sources of estimation uncertainty including reserves and resources is discussed below.

 

3.  Material accounting policies, judgements and estimation uncertainty continued

Estimates in impairment of oil and gas assets and goodwill

Determination of whether the Group's oil and gas assets (note 15) or goodwill (note 18) have suffered any impairment requires an estimation of the recoverable amount of the CGU to which oil and gas assets and goodwill have been allocated. Projected future cash flows are used to determine a fair value less cost to sell to establish the recoverable amount. Key assumptions and estimates in the impairment models relate to: commodity prices that are based on internal view of forward curve prices that are considered to be a best estimate of what a market participant would use; discount rates which reflect management's estimate of a market participant post-tax weighted average cost of capital; and oil and gas reserves and resources on a risked basis as described above. Management's estimates of a market participant's view of pricing and discount rates are supported by an independent consultant.

 

The sensitivity of the Group's carrying amounts to these assumptions is illustrated by the impairments and reversals disclosed in note 19, and by the sensitivity disclosures in note 19. Sensitivity disclosures include, in particular, the impact of a 20% reduction in forecast revenues.

 

Critical accounting judgements

The following are the critical judgements, apart from those involving estimation (which are presented separately above), that the Directors have made in applying the Group's accounting policies and that have the most significant effect on the amounts recognised in the financial statements.

Cambo field carrying value

Management has reviewed the carrying value of the Cambo field of $391 million and has concluded that due to the recent licence extension to 31 March 2026 and the detailed plans in place for final investment decision (FID), there are currently no indicators of impairment. The Group is actively engaging with potential farm-in partners to secure an aligned joint venture partnership that would progress the project towards FID and assist in obtaining the additional funding required for the project. The Group is also mindful that the outcome of the 2024 General Election could have implications for the project as well as the wider fiscal uncertainties on oil and gas investment in general. Details of contingent consideration in respect of Cambo are set out in note 17 and note 25.

Notes to the consolidated financial statements continued

 

 

4. Segmental reporting

The Group operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area, presently being the North Sea. The Group's segmental reporting structure remained in place for all periods presented and is consistent with the way in which the Group's activities are reported to the Board and Chief Decision Making Officer. The Group's activities are considered to be an individual operating segment due to the nature of the Group's operations being consistent, and such operations existing in a single geographical region that is covered by the same regulations.

5. Revenue

 


2023

US$'000

2022

US$'000

Oil sales

1,329,751

1,692,697

Gas sales

658,659

1,348,212

Condensate sales

48,789

75,445

Other income

32,341

40,617

Realised losses on oil derivative contracts

(31,676)

(211,636)

Put premiums on oil derivative instruments

(11,850)

(14,629)

Realised gains/(losses) on gas derivative contracts

297,387

(289,877)

Put premiums on gas derivative instruments

(3,590)

(42,347)


2,319,811

2,598,482

The majority of payment terms are on a specified monthly date, as detailed in the initial contract. Otherwise, payment is due within 30 days of the invoice date. No significant judgements have been made in determining the timing of satisfaction of performance obligations, the transactions price and the amounts allocated to performance obligations. Other income relates to tariff income receivable in the year.

 

Revenue from two customers exceeded 10% of the Group's consolidated revenue arising from hydrocarbon sales for the year ended 31 December 2023, representing $1,296 million and $436 million of revenue respectively (2022: one customer representing $2,436 million of revenue).

 

Revenue from contracts with customers derives largely from customers within a single geographical region, being the United Kingdom. Revenue from contracts with customers out with the United Kingdom is immaterial and is therefore not disclosed separately.

 

6. Cost of sales

 

2023

 

2022

US$'000

US$'000

Movement in oil and gas inventory (including underlift/overlift)

20,582

(130,295)

Operating costs of hydrocarbon activities

(576,660)

(547,795)

Materials inventory provision

(16,268)

-

Royalties

(4,364)

(11,287)

Depreciation on right-of-use assets (note 15)

(42,648)

(37,438)

Depletion, depreciation and amortisation (note 15)

(697,652)

(625,509)


(1,317,010)

(1,352,324)

 

Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the original licence holders. Ithaca holds a 100% interest in the Stella and Harrier fields.




 

7. Administrative expenses



2023

US$'000

2022

US$'000

Administrative expenses excluding transaction costs

(34,259)

(41,762)

Transaction costs

-

(46,089)


(34,259)

(87,851)

 

Transactions costs in 2022 relate to the acquisitions of Marubeni Oil & Gas Limited (MOGL), Summit Exploration and Production Limited (Summit) and Siccar Point Energy entities, and costs incurred in connection to the IPO. Further details on the acquisitions can be found in note 17.

 

The total employee benefit expenses which are either capitalised or included in cost of sales, pre-licence exploration and evaluation expenses and administrative expenses are noted below.

 

 

Employee benefit expenses

2023

US$'000

2022

US$'000

Wages and salaries

(104,027)

(81,017)

Share-based payment charges (note 32)

(16,369)

(14,069)

Social security costs

(12,290)

(9,902)

Pension costs

(9,997)

(8,298)


(142,683)

(113,286)

Directors' emoluments in aggregate were $13.4 million (2022: $18.1 million). The average number of employees during each year was as follows:




 

2023

 

2022

Onshore and administrative

316

268

Offshore

283

249


599

517

 

The increase in average employee numbers in 2023 reflects the full-year impact of acquisitions made in 2022 and the conversion of a number of contractor roles to staff positions.




7. Administrative expenses continued

 


2023

2022

Audit fees

US$'000

US$'000

Fees payable to the Company's auditor for audit of the Company's financial statements

1,286

1,095

Audit of the Company's subsidiaries pursuant to legislation

326

324

Non-audit fees provided by the auditors

205

4,707


1,817

6,126

 

Non-audit fees provided by the auditors for the year ended 31 December 2023 comprise audit-related assurance services of $205k (2022: $170k), other assurance services of $nil (2022: $990k) and other non-audit services of $nil (2022: $3,547k), with the latter two captions in 2022 relating to reporting accountant workstreams in relation to the IPO.

 

8. Other gains and losses

 

2023

 

2022

US$'000

US$'000

Gain/(loss) on financial instruments (note 29)

43,059

(278)

Fair value losses on contingent consideration (note 25)

(8,008)

(4,295)

Remeasurements of decommissioning reimbursement receivables

5,645

-

Net foreign exchange

(1,673)

(4,856)

Settlement of historic claim relating to an acquisition

50,068

-


89,091

(9,429)

 

On 12 February 2023, the Group reached agreement on the settlement of a historic claim relating to an acquisition. Under the terms of the agreement the Group received $50.1 million.



9. Finance costs and finance income

 

 

2023

 

 

2022


US$'000

US$'000

Loan interest and charges

(47,494)

(58,317)

Senior notes interest

(58,377)

(61,537)

Loan fee amortisation

(4,508)

(6,418)

Interest on lease liabilities (note 24)

(3,183)

(3,852)

Interest on related-party loan (note 31)

-

(17,924)

Accretion

(76,162)

(56,511)

Realised gains on interest derivative contracts (note 29)

-

851

Total finance costs

(189,724)

(203,708)




Interest income

5,688

695

 

There was no interest capitalised into qualifying assets in either the year to 31 December 2023 or the year to 31 December 2022.




10. Earnings per share

The calculation of basic earnings per share is based on the profit after tax and the weighted average number of ordinary shares in issue during the year. Basic and diluted earnings per share are calculated as follows:

 


2023

US$'000

2022

US$'000

Earnings for the year:



Earnings for the purpose of basic and diluted earnings per share

215,635

1,031,532

Number of shares (million)



Weighted average number of ordinary shares for the purpose of basic earnings per share1

1,006.7

1,005.2

Dilutive potential ordinary shares

12.7

5.0

Weighted average number of ordinary shares for the purpose of diluted earnings per share

1,019.4

1,010.2

Earnings per share (cents)



Basic

21.4

102.6

Diluted

21.2

102.1

11. Trade and other receivables



 

Current

2023

US$'000

2022

US$'000

Trade receivables

19,968

31,906

Other receivables

24,369

14,210

Joint operations receivables

91,960

99,800

Accrued income

197,993

214,078


334,290

359,994

 

Materially all trade and other receivables, including receivables from joint operations are not overdue by more than 90 days. The credit risk associated with trade receivables, accrued income and other receivables is considered to be insignificant. No ECL has been recognised in the current or prior year.

 

11. Trade and other receivables continued


 

Non-current

2023

US$'000

2022

US$'000

Decommissioning reimbursements

165,064

162,710

 

 

Current

 

2023

US$'000

 

2022

US$'000

Decommissioning reimbursements

30,417

38,115

 

Movements on decommissiong reimbursements were as follows:




2023

US$'000

2022

US$'000

At 1 January

200,825

246,824

Accretion

7,536

5,946

Reimbursements received

(22,101)

(23,418)

Change in reimbursement estimates

9,221

(28,527)

At 31 December

195,481

200,825

 

The decommissioning reimbursements represent the equal and opposite of decommissioning liabilities (note 23), net of tax, associated with the Heather and Strathspey fields and relates to a contractual agreement as part of

the CNSL acquisition. As part of the terms of the CNSL acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL in relation to these interests. The Group pays the liabilities in respect of Heather and Strathspey and then receives full reimbursement from Chevron.

 

As these payments are virtually certain they have been accounted for under IAS 37 as a reimbursement asset.

12. Prepaid expenses and decommissioning securities

 

Current

2023

US$'000

2022

US$'000

Prepayments

34,355

7,415

Decommissioning securities

3,323

1,640


37,678

9,055


 

13. Inventories


 

Current

2023

US$'000

2022

US$'000

Hydrocarbon underlift

60,427

87,563

Materials inventories

125,674

124,755

Provision for obsolete materials inventory

(35,605)

(35,437)


150,496

176,881

14. Exploration and evaluation assets





US$'000

At 1 January 2022


116,355

Additions


42,168

Acquisitions (note 17)


706,558

Transfers to development and production assets (note 15)


(75,005)

Write offs/relinquishments


(14,303)

At 31 December 2022 and 1 January 2023


775,773

Additions


165,516

Transfers to right-of-use operating assets and development and production assets (note 15)


(379,301)

Write offs/relinquishments


(13,634)

At 31 December 2023


548,354

 

Following completion of geotechnical evaluation activity, certain North Sea licences were declared unsuccessful and certain prospects were declared non-commercial. This resulted in the carrying value of these licences being fully written off to $nil with $13.6 million being expensed in the year to 31 December 2023 (2022: $14.3 million).

 

The transfers from exploration and evaluation assets to development and production assets in 2023 relates to the Rosebank development. Transfers in 2022 related to the Abigail and Jade South wells. Included within additions in the year is equity acquired in the Cambo and Fotla developments acquired from Shell U.K. Limited and Spirit Energy Resources Limited respectively.

The write offs/relinquishments includes $nil (2022: $5.3 million) impairment relating to decommissioning revisions.

 

The principal component of exploration and evaluation assets at 31 December 2023 is the Cambo field with a carrying value of $391 million (2022: Cambo $364 million and Rosebank $315 million) which formed part of the Siccar acquisition (see note 17).

 

15. Property, plant and equipment



Right-of-use operating assets

Development and production assets

Other fixed assets

 

Total


US$'000

US$'000

US$'000

US$'000

Cost

 

                                                                          

 

 

 

At 1 January 2022

9,210

5,838,178

40,293

5,887,681

Additions

                                                                          

89,717

362,844

5,619

458,180

Acquisitions (note 17)

                                                                          

-

1,115,023

-

1,115,023

Transfers from exploration and evaluation assets (note 14)

                                                                          

-

75,005

-

75,005

Change in decommissioning estimates (note 23)

                                                                          

-

(278,398)

-

(278,398)

At 31 December 2022 and 1 January 2023

98,927

7,112,652

45,912

7,257,491

Additions

                                                                          

26,468

358,361

1,728

386,557

Transfers from exploration and evaluation assets (note 14)

                                                                          

30,774

348,527

-

379,301

Change in decomissioning estimates (note 23)

                                                                          

-

157,224

-

157,224

At 31 December 2023

156,169

7,976,764

47,640

8,180,573

 

 

                                                                          

 

 

 

Depletion, depreciation, amortisation and impairment

 

                                                                          

 

 

 

At 1 January 2022

(5,429)

(2,909,695)

(13,824)

(2,928,948)

Depletion, depreciation and amortisation charge for the year

                                                                          

(37,438)

(615,261)

(10,248)

(662,947)

Impairment charge (note 19)

                                                                          

-

(30,700)

-

(30,700)

At 31 December 2022 and 1 January 2023

(42,867)

(3,555,656)

(24,072)

(3,622,595)

Depletion, depreciation and amortisation charge for the year

                                                                          

(42,648)

(693,573)

(4,079)

(740,300)

Impairment charge (note 19)

                                                                          

-

(559,472)

-

(559,472)

At 31 December 2023

(85,515)

(4,808,701)

(28,151)

(4,922,367)






Net book value at 31 December 2022

56,060

3,556,996

21,840

3,634,896

Net book value at 31 December 2023

70,654

3,168,063

19,489

3,258,206

 

The transfers from exploration and evaluation assets to development and production assets in 2023 relates to the Rosebank development following consent being granted for the development by the North Sea Transition Authority (NSTA) on 27 September 2023. Subsequent to this, environmental campaigners Uplift and Greenpeace UK announced that they are separately seeking judicial review by the Court of Session in Edinburgh with respect to the decision by the NSTA and the Secretary of State for Energy to approve the Rosebank development. In 2022 the transfers related to the Abigail and Jade South wells. At the point of transfer these assets were tested for impairment and none was found.

 

Additions to right of use assets in the year to 31 December 2023 principally relate to modifications to the Rosebank FPSO and will begin to be depreciated on commencement of production. The related lease will commence on delivery of the FPSO to the joint venture partners at first oil which is currently anticipated to be 2026/27.

 

Other fixed assets includes buildings, computer equipment, office equipment and furniture and fittings.

 

16. Interests in joint operations

The contractual agreement for the licence interests in which the Group has an investment do not typically convey control of the underlying joint arrangement to any one party, even where one party has a greater than 50% equity ownership of the area of interest.

The Group's material joint operations as at 31 December are as follows:

Group net % interest

Block

Licence

Field/discovery name

Operator

2023

2022


9/11c

P.979

Mariner

Equinor UK Limited

8.89%

8.89%

 

9/11b

P.726

Mariner

Equinor UK Limited

8.89%

8.89%

 

30/2c

P.672

Jade

Chrysaor Petroleum Company UK Limited

25.50%

25.50%

 

22/30c and 29/5c

P.666

Elgin-Franklin

TotalEnergies E&P UK Limited

6.09%

6.09%

 

15/29b

P.590

Callanish

Chrysaor Production (UK) Limited

20.00%

20.00%

 

204/25a

P.559

Schiehallion

BP Exploration Operating Company Limited

35.30%

35.30%

 

204/19b and 204/20b

P.556

Suilven

Ithaca SP E&P Limited

50.00%

50.00%

 

29/5b

P.362

Elgin-Franklin

TotalEnergies E&P UK Limited

6.09%

6.09%

 

21/4a

P.347

Callanish

Chrysaor Production (UK) Limited

13.70%

13.70%

 

16/27b

P.345

Britannia

Ithaca MA Limited

35.75%

35.75%

 

9/11a

P.335

Mariner

Equinor UK Limited

8.89%

8.89%

 

13/22a

P.324

Captain

Ithaca SP E&P Limited

85.00%

85.00%

 

22/18a

P.292

Arbroath, Arkwright, Carnoustie, Wood

Repsol Sinopec Resources UK Limited

41.03%

41.03%

 

22/17s, 22/22a and 22/23a

P.291

Arbroath, Arkwright, Brechin, Carnoustie, Cayley, Shaw

Repsol Sinopec Resources UK Limited

41.03%

41.03%

 

23/26b

P.264

Erskine

Ithaca Energy (UK) Limited

50.00%

50.00%

 

9/11d and 9/12b

P.2508

Mariner

Equinor UK Limited

8.89%

8.89%

 

22/1b

P.2373

F Block (Fotla and Fortriu)

Ithaca Oil and Gas Limited

100.00%

60.00%

 

15/18b

P.2158

Marigold

Ithaca Oil and Gas Limited

100.00%

100.00%

 

9/11g

P.2151

Mariner

Equinor UK Limited

8.89%

8.89%

 

16/26a A-ALB

P.213

Alba

Ithaca Oil and Gas Limited

36.67%

36.67%

 

16/26a B-BRI

P.213

Britannia

Ithaca MA Limited

33.17%

33.17%

 

16/26a

P.213

N/A

Ithaca Oil and Gas Limited

34.50%

34.50%

 

3/7a

P.203

Columba E

CNR International (UK) Limited

20.00%

20.00%

 

3/8a and 3/8a

P.199

Columba B/D

CNR International (UK) Limited

5.60%

5.60%

 


16. Interests in joint operations continued

 

Group net % interest

Block

Licence

Field/discovery name

Operator

2023

2022


22/30b

P.188

Elgin-Franklin

TotalEnergies E&P UK Limited

6.09%

6.09%

 

21/20a

P.185

Cook

Ithaca SP E&P Limited

61.35%

61.35%

 

8/15a

P.1758

Mariner

Equinor UK Limited

8.89%

8.89%

 

29/10b

P.1665

Abigail

Ithaca SP E&P Limited

100.00%

100.00%

 

30/7b

P.1589

Jade

Chrysaor Petroleum Company UK Limited

25.50%

25.50%

 

30/1f

P.1588

Vorlich

Ithaca MA Limited

100.00%

100.00%

 

30/1c

P.363

Vorlich

Ithaca MA Limited

34.00%

34.00%

 

205/2a

P.1272

Rosebank

Equinor UK Limited

20.00%

20.00%

 

205/1a

P.1191

Rosebank

Equinor UK Limited

20.00%

20.00%

 

15/29a

P.119

Alder

Ithaca Energy (UK) Limited

73.68%

73.68%

 

15/29a

P.119

Britannia

Ithaca MA Limited

75.00%

75.00%

 

204/4a and 204/5a

P.1189

Cambo

Ithaca SP E&P Limited

100.00%

70.00%

 

21/3a

P.118

Brodgar

Chrysaor Production (UK) Limited

25.00%

25.00%

 

23/22a

P.111

Pierce

Enterprise Oil Limited

34.01%

34.01%

 

15/30a

P.103

Britannia

Chrysaor Production (UK) Limited

33.03%

33.03%

 

21/5a

P.103

Enochdhu

Chrysaor Production (UK) Limited

50.00%

50.00%

 

204/9a and 204/10a

P.1028

Cambo

Ithaca SP E&P Limited

100.00%

70.00%

 

213/26b and 213/27a

P.1026

Rosebank

Equinor UK Limited

20.00%

20.00%

 

23/26a

P.057

Erskine

Ithaca Energy (UK) Limited

50.00%

50.00%

 

22/18n

P.020

Montrose

Repsol Sinopec Resources UK Limited

41.03%

41.03%

 

22/17n, 22/17s, 22/22a and 22/23a

P.019

Godwin, Montrose

Repsol Sinopec Resources UK Limited

41.03%

41.03%

 

30/6a and 29/10a

P.011

Stella/Harrier

Ithaca Energy (UK) Limited

100.00%

100.00%

 

30/11a and 30/12d

P.1820

Isabella

Total Energies E&P North Sea UK Limited

10.00%

10.00%

 

204/8, 204/9c, 204/10c, 204/13, 204/14d

and 204/15

P.2403

Tornado

Ithaca SP E&P Limited

50.00%

50.00%



 

 

 

 

 

 

1  Net cash flows relating to the MOGL acquisition includes a $7 million deposit paid in the year ended 31 December 2021.

 

17. Business combinations continued

MOGL

On 4 February 2022, the Group completed the acquisition of 100% of the issued share capital of MOGL. The transaction added a further non-operated share in nine producing field interests (known as MonArb) to the existing Ithaca portfolio.

Taking into account the interim period cash flows generated by MOGL since the transaction effective date of 1 January 2021, the $7 million deposit paid at signing of the transaction in November 2021 and conventional working capital adjustments, the price payable at completion of the acquisition was $108 million. A deferred consideration of $63 million and risked contingent consideration of $139 million, discounted at 2.5% were recognised at acquisition, resulting in a gain on bargain purchase of $620 million.

 

The contingent consideration arrangement on MOGL depends on whether various milestones in the Sale and Purchase Agreement (SPA) are met as follows: set gross export production volume from Montrose Infill Project Phase 1, set cumulative gross export production volume following Arbroath well reinstatements, set gross export production volume from next new well in the Shaw Field and, an amount payable during the Value Sharing Period (1 January 2022 to 31 December 2024) in relation to sales in excess of a set oil trigger price. The amount payable in relation to sales in excess of a set oil trigger price is capped under the terms of the SPA.

 

The contingent consideration is subsequently revalued at each year-end date.

 

The gain on bargain purchase arising on the MOGL acquisition was principally a result of recognising a deferred tax asset arising from tax losses of $745 million, which were not forecast to be utilised by MOGL, as allowed under IFRS 3 fair value accounting for business combinations. The gain was also partially attributed to the extended period from effective date of 1 January 2021 to the completion date of 4 February 2022 during which time hydrocarbon prices rose significantly. The gain on bargain purchase of $620 million was credited to income in the year ended 31 December 2022.

Siccar Point Energy

On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Siccar Point Energy (Holdings) Limited (Siccar Point Energy) and its UK subsidiaries. The transaction added a further two producing assets (Mariner 8.89% and Schiehallion 11.75%), an additional 5.57% increase to the Group's existing equity in Jade, and three development prospects (Rosebank 20%, Cambo 70% at date of acquisition and Tornado 50%) to the existing Group portfolio.

Taking into account the interim period cash flows generated by Siccar since the transaction effective date of 1 January 2022 and conventional working capital adjustments, the price payable at completion of the acquisition was $1.015 billion. A risked contingent consideration of $102 million was recognised, resulting in a gain on bargain purchase of $704 million.

 

The contingent consideration arrangement on Siccar Point Energy depends on whether various milestones of the SPA are met as follows: redemption of acquired bond as at repayment date, Final Investment Decision and the associated reserves in respect of the Cambo and Rosebank fields and, an amount paid in relation to sales in excess of a set floor oil price. The amount payable in relation to sales in excess of a set oil trigger price is capped under the terms of the SPA.

 

The contingent consideration is subsequently revalued at each year-end date.

 

 

17. Business combinations continued

The gain on bargain purchase arising on the Siccar Point Energy transaction was principally as a result of recognising a deferred tax asset arising from tax losses of $1,334 million as allowed under IFRS 3 fair value accounting for business combinations. The gain on bargain purchase of $704 million was credited to income in the year ended 31 December 2022.

On acquisition of Siccar Point Energy, the Group acquired a $200 million bond. On 28 July 2022 a group of bondholders exercised their right to redeem and subsequently $166.4 million was paid to these bondholders. Subsequently, in September 2022, notes totalling $25.6 milion were bought back at a premium of 6% by the Group. The remaining notes totalling $8.0 million were redeemed on 12 October 2022 and there was no remaining balance at 31 December 2022.

Summit

On 30 June 2022, the Group completed the acquisition of 100% of the issued share capital of Summit. The transaction added a further 2.1875% ownership of the Elgin Franklin field interest within the existing Group portfolio.

 

Taking into account the interim period cash flows generated by Summit since the transaction effective date of 1 January 2021, the $10 million deposit paid at signing of the transaction in February 2022 and conventional working capital adjustments, the price payable at completion of the acquisition was $119 million and goodwill of $62 million was recognised. The goodwill recognised can be attributed to the increase in the Group's equity interest in the Elgin Franklin field and the corresponding impact of EPL, which was announced between effective date and completion, on the fair values at acquisition.

 

There are no contingent consideration arrangements under the Sale and Purchase Agreement of the Summit assets. No contingent liabilities have been acquired on the business combinations detailed above.

The fair values of the oil and gas assets and the intangible assets acquired have been determined using valuation techniques based on discounted cash flows using forward curve commodity prices and estimates of long-term commodity prices reflective of market conditions at each completion date, a discount rate based on observable market data and cost and production profiles generally consistent with the proved and probable reserves acquired with each asset.

The decommissioning liabilities recognised have been estimated based on operator cost estimates with reference to observable market data.

18. Goodwill

 


2023

US$'000

2022

US$'000

Balance at 1 January

783,848

722,075

Additions (note 17)

-

61,773

Balance at 31 December

783,848

783,848

 

The goodwill is not tax deductible on any of the acquisitions.




18. Goodwill continued

The goodwill on acquisition in the year to 31 December 2022 relates to the Summit acquisition, as detailed in note 17.

 

Annual impairment tests were performed at both 31 December 2023 and 31 December 2022. These reviews were carried out on a fair value less cost of disposal basis using risk adjusted cash flow projections from the approved business plans including the same commodity prices, life of field cost profiles and production volumes used for impairment of oil and gas assets (see note 19), discounted at a post-tax discount rate of 10.3% (2022: 10.9%). Assumptions and estimates in the Group impairment models are detailed in note 3. An increase of 1% in the discount rate assumption would not result in a post-tax impairment of goodwill. Goodwill is monitored, and tested for impairment, at the operating segment level, being the North Sea (the entire Group portfolio of oil and gas assets). This is consistent with the operating segment view of the business which is presented to the Board and the Chief Decision Maker.

The Group's activities are considered to be an individual operating segment due to the uniform nature of the Group's operations within a single geographical area, overseen by the same management and subject to the same regulations. The fair value estimate is categorised as level 3 in the fair value hierarchy.

19. Impairment charge on oil and gas assets

 


2023

US$'000

2022

US$'000

D&P assets

(559,472)

(30,700)

E&E assets

-

(1,867)

Other movements

1,536

-

Contingent consideration reversal

-

1,100

North Sea oil and gas assets

(557,936)

(31,467)

The impairment charge on D&P assets of $559.5 million (2022: $30.7 million) primarily relates to Alba of $141.3 million and the Greater Stella Area (GSA) of $373.2 million. The charge in 2022 reflected revisions in decommissioning provisions, principally on fields that are no longer producing.

 

Estimated production volumes and cash flows used in impairment reviews are considered up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure and are derived from management approved business plans.

 

An impairment review was carried out at the end of 2023 on the Group's producing assets with the main triggers being a reduction in future reserves on Alba, a decrease in short-term forward oil prices against all oil producing CGUs and a decrease in short-term gas prices for GSA and other predominantly gas-producing CGUs with relatively short remaining useful economic lives. The review was carried out on a fair value less cost of disposal basis using risk adjusted cash flow projections discounted at a post-tax discount rate of 10.3%, and represents level 3 in the fair value hierarchy. The recoverable amount (post tax) for Alba and GSA was $nil and $29.7 million respectively.

 

The following assumptions, as supported by third-party analysis, were used at Q4 2023 in developing the cash flow model and applied over the expected life of the respective fields:

 



Price assumptions (nominal)



Post tax

discount rate

assumption

2024

2025

2026

2027

20281


Oil

10.3%

$85/bbl

$83/bbl

$87/bbl

$90/bbl

$93/bbl


Gas

10.3%

101p/therm

96p/therm

83p/therm

85p/therm

87p/therm


 

1.  Post-2028 an annual 2% increase is applied to the price assumptions.








With all other assumptions held constant and supported by third-party analysis, a 20% decrease in the forecast revenues, illustrating lower commodity prices and/or production volumes, would result in an additional post-tax impairment of PP&E of $22 million (2022: $13 million) at 31 December 2023. A 20% increase in forecast revenues would reduce the reported post-tax impairment by $26 million. An increase or decrease of 1% in the discount rate assumption would not result in a material additional post-tax impairment or reversal of impairment of PP&E.

 

19. Impairment charge on oil and gas assets continued

The group has also conducted a sensitivity scenario on the climate-related risk of a reduction in demand and commodity prices for oil and gas due to changing consumer preferences and/or government regulations. Utilising the Climate scenario's average oil price while maintaining all other parameters in line with the base case would result in an immaterial effect on additional post-tax impairment as at 31 December 2023.

To calculate the Climate Scenario average oil price, the group utilised data from both the International Energy Agency (IEA) climate scenarios (NZ, STEPS, APS) and the World Business Council for Sustainable Development (WBCSD) data catalogue. Management's base case assumption aligns substantially with climate-adjusted curves for gas and carbon emission prices; hence, no supplementary sensitivity analysis has been presented.

An impairment review was also carried out at the end of 2022 on the Group's producing assets with the main trigger being the implementation of the Energy Profits Levy (EPL) in the second half of 2022. The review demonstrated that there was no requirement to impair any of the Group's producing assets. The review was carried out on a fair value less cost of disposal basis using risk adjusted cash flow projections discounted at a post-tax discount rate of 10.9%.

 

The following assumptions, as supported by third-party analysis, were used at Q4 2022 in developing the cash flow model and applied over the expected life of the respective fields:

 



Price assumptions (nominal)



Post tax

discount rate

assumption

2023

2024

2025

2026

20271


Oil

10.9%

$89/bbl

$84/bbl

$83/bbl

$83/bbl

$83/bbl


Gas

10.9%

315p/therm

211p/therm

99p/therm

86p/therm

86p/therm


 

1.  Post 2027 an annual 2% is applied to the price assumptions.








Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital expenditure, are derived from the approved business plans and third-party reports.

20. Borrowings

 


2023

US$'000

2022

US$'000

Current



Accrued interest costs on borrowings

(29,913)

-


(29,913)

-

Non-current



RBL facility

-

(600,000)

Senior unsecured notes

(625,000)

(625,000)

bp unsecured loan

(100,000)

-

Unamortised long-term bank fees

4,555

7,591

Unamortised long-term senior notes fees

2,207

3,678

Total debt

(718,238)

(1,213,731)

Accrued interest on borrowings has been reclassed in the current year from accruals (within trade and other payables) to borrowings, to reflect the current payable in respect of borrowings. The prior year equivalent of $21.7 million has not been adjusted for this change as it is not material and remains within accruals for the year ended 31 December 2022.

 

Adjusted net debt, which does not include accrued interest on borrowings, lease liabilities or unamortised fees, is set out in non-GAAP measures on pages 76 to 78.

 

20. Borrowings continued

Reserves Based Lending (RBL) facility

During 2021, the Group completed a refinancing to amend and extend the RBL facility. The RBL commitment was approximately $1.225 billion with a maturity to 2026, and subject to interest at a reference rate of SOFR plus 3.5%. At 31 December 2023, due to the NPV cap described in the covenants section below, the total availability was $725 million (2022: $925 million), of which none (2022: $600 million) was drawn down, leaving an amount of $725 million (2022: $325 million) being available for drawdown. Subsequent to 31 December 2023, RBL liquidity increased from $725 million to $836 million.

Loan fees of $15.2 million relating to the RBL were capitalised and are being amortised over the term of the loan, $4.6 million (2022: $7.6 million) remains to be amortised as at 31 December 2023.

 

The RBL facility is secured by the assets of the guarantor members of the Group, such security including share pledges, floating charges and/or debentures. Total assets pledged as security at 31 December 2023 was $[6,238] million (2022: $6,760 million).

Senior notes

In 2021, the Group completed the refinancing of its senior unsecured notes with the issuance of $625 million 9% senior unsecured notes due July 2026 and repayment in full of the notes issued during 2019. Loan fees of $7.4 million relating to the new senior notes were capitalised and are being amortised over the life of the loan, $2.2 million (2022: $3.7 million) remains to be amortised as at 31 December 2023.

Covenants in relation to these senior notes are detailed below.

 

On acquisition of Siccar Point Energy on 30 June 2022, the Group acquired their existing $200 million 9% senior unsecured notes due March 2026. The Group also acquired $5.8 million of accrued interest in relation to these senior notes. On 1 August 2022, a settlement was made as a result of the exercise of the put option on the notes and a combined holding of $166.4 million exercised the put option. Subsequently, in September 2022, notes totalling $25.6 million were bought back at a premium of 6% by the Group. The remaining notes totalling $8.0 million were fully redeemed on 12 October 2022.

bp facility

During the year to 31 December 2023, a new $100 million five-year facility was entered into with bp which is subject to an interest rate of SOFR plus a commercially agreed margin. The loan is unsecured, is due for repayment in 2028 and was fully drawn at 31 December 2023 (2022: $nil). Fees of $0.5 million were incurred on drawdown.

Optional project capital expenditure facility

During the year to 31 December, a carry arrangement of up to $150 million was entered into relating to a field development. The carry is repayable by instalment expected to be from 2027. Under the terms of the arrangement, interest is payable at a rate of SOFR (subject to a minimum of 5%) plus a commercially agreed margin. The carry arrangement was undrawn at 31 December 2023.

Covenants

The Group is subject to financial and operating covenants related to the RBL facility. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the facility agreements, potentially resulting in accelerated repayment of the debt obligations. The Group was in compliance with all its relevant quarterly financial and operating covenants during all periods shown for the RBL facility and acquired senior notes. There are no ongoing maintenance or financial covenant tests associated with the $625 million unsecured notes.

 

In addition to the below financial covenants, the Group is subject to restrictive covenants under the RBL facility and 2026 notes, restricting the Group, to, amongst other things: make certain payments (including, subject to certain exceptions, dividends and other distributions), with respect to outstanding share capital; repay or redeem subordinated debt or share capital; create or incur certain liens; make certain acquisitions and investments or loans; sell, lease or transfer certain assets, including shares of any of the Group's restricted subsidiaries; incur expenditure on exploration and appraisal activities in excess of approved levels; guarantee certain types of the Group's other indebtedness; expand into unrelated businesses; merge or consolidate with other entities; or enter into certain transactions with affiliates.

 

20.  Borrowings continued

The key financial covenants in the RBL are:

?   The parent shall ensure that as at the end of each Relevant Period (starting with the Relevant Period ending on 30 November 2021) the ratio of adjusted net debt to adjusted EBITDAX shall be less than 3.5:1. 'Adjusted net debt' referred to is not an IFRS measure. The Company uses adjusted net debt as a measure to assess its financial position. Adjusted net debt comprises amounts outstanding under the Company's RBL facility, bp facility and senior notes, less cash and cash equivalents;

?   Total projected sources of funds must exceed the total projected uses of funds for the following 12-month period (or a longer period to first production from development, if applicable);

?   The ratio of the net present value of cash flows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1; and

?   The ratio of the net present value of cash flows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.

 

The Group was in compliance with all financial covenants of the RBL facility in all periods presented.

21. Changes in liabilities arising from financing activities

 

Non-cash changes


 

1 January 2023

Financing cash

flows (i)

 

Additions

 

Imputed interest

Fair value movements

 

Amortisation

 

Debt waiver

Other movements (ii)

 

31 December 2023


US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

Borrowings (note 20)

1,213,731

(596,642)

-

-

-

4,507

-

126,554

748,150

Lease liabilities

                                                                          

58,858

(45,085)

3,603

-

-

-

-

3,183

20,559

Interest rate derivatives (note 29)

                                                                          

(7,125)

6,967

-

-

(479)

-

-

-

(637)

Total liabilities from financing activities

1,265,464

(634,760)

3,603

-

(479)

4,507

-

129,737

768,072

Non-cash changes


 

1 January 2022

Financing cash

flows (i)

 

Additions

 

Imputed interest

Fair value movements

 

Amortisation

 

Debt waiver

Other movements (ii)

 

31 December 2022


US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

US$'000

Borrowings (note 20)

954,616

50,000

200,000

-

-

4,508

-

-

1,213,731

Parent company debt (note 31)

                                                                          

437,076

(273,055)

-

17,924

-

-

(181,945)

-

-

Lease liabilities

                                                                          

3,489

(38,200)

-

-

-

-

-

93,569

58,858

Interest rate derivatives (note 29)

                                                                          

(133)

851

-

-

(7,843)

-

-

-

(7,125)

Total liabilities from financing activities

1,395,048

(260,404)

200,000

17,924

(7,843)

4,508

(181,945)

98,176

1,265,464

(i)  The cash flows from borrowings, Parent Company debt, lease liabilities and interest rate derivatives make up the net amount of proceeds from borrowings and repayments of borrowings in the cash flow statement.

(ii)  Other movements include interest accruals and new liabilities in the year.

 

22. Trade and other payables



2023

US$'000

2022

US$'000

Trade payables

(34,559)

(14,917)

Hydrocarbon amounts owed to joint operations/overlift

(72,486)

(124,365)

Other payables

(68,034)

(185,720)

Accruals

(254,781)

(299,604)

Deferred income

(48,747)

(86,806)


(478,607)

(711,412)

 

The Directors consider the carrying values of trade and other payables to approximate the fair value. Other payables mainly comprises amounts owed due to production adjustments and amounts owed to joint operations partners. Deferred income represents receipts in advance of deliveries to customers. The prior year deferred income was recognised in revenue in the current year.

23. Decommissioning liabilities

 


2023

US$'000

2022

US$'000

Balance at 1 January

(1,720,540)

(1,641,489)

Business combination additions

-

(390,530)

Accretion

(74,621)

(52,592)

Additions and revisions to estimates

(160,069)

298,564

Decommissioning provision utilised

95,552

65,507

Balance at 31 December

(1,859,678)

(1,720,540)

Current



Balance at 1 January

(146,829)

(94,640)

Balance at 31 December

(107,026)

(146,829)

Non-current



Balance at 1 January

(1,573,711)

(1,546,849)

Balance at 31 December

(1,752,652)

(1,573,711)

Additions and revisions to estimates comprise $157,224k (2022: $(278,398)k) of development and production assets and $2,845k (2022: $(20,166)k) of exploration and evaluation assets.

 

The total future decommissioning liability represents the estimated cost to decommission, in situ or by removal, the Group's net ownership interest in all wells, infrastructure and facilities, based upon forecast timing in future periods. The Group uses a nominal discount rate of 4.60% (31 December 2022: 4.25%) and an inflation rate of 2.0% (31 December 2022: 2.0%) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. The impact of a change in discount rate is considered in note 3. Revisions to estimates in the years ended 31 December 2023 and 2022 were due to changes in both cost estimates and discount rate assumptions.

 

The estimated 2024 decommissioning spend of of $107 million (2022: estimated 2023 decommissioning spend of $147 million) has been treated as a current liability as at 31 December 2023. Although the Group currently expects to incur decommissioning costs over the next 40 years, it is estimated that approximately 47% of the decommissioning liability relates to assets which are expected to cease production in the next five years and which includes spend for assets that will be reimbursed (see note 11 for further details).

 

24. Lease liabilities


 

Current

2023

US$'000

2022

US$'000

Lease liabilities

(19,898)

(41,637)

 

 

Non-current

 

2023

US$'000

 

2022

US$'000

Lease liabilities

(660)

(17,221)

 

The following table sets out a maturity analysis of lease payments, showing the undiscounted lease payments to be paid after the reporting date. All lease liabilities are fully payable within two years from 31 December 2023.


2023

US$'000

2022

US$'000

Less than one year

(20,152)

(44,257)

One to two years

(669)

(17,439)

Total undiscounted lease payments

(20,821)

(61,696)

Future finance charges and other adjustments

263

2,838

Lease liabilities in the financial statements

(20,558)

(58,858)


 

2023

US$'000

 

2022

US$'000

At 1 January

(58,858)

(3,489)

Additions

(3,603)

(89,717)

Interest

(3,183)

(3,852)

Payments

45,086

38,200

At 31 December

(20,558)

(58,858)

Current

(19,898)

(41,637)

Non-current

(660)

(17,221)


(20,558)

(58,858)

 

The additions in the year to 31 December 2023 relate to modifications of the Captain Emergency Response and Recovery Vehicle lease.

 

The addition in the year to 31 December 2022 relates to the Pioneer rig lease currently utilised on the Captain EOR project. The incremental borrowing rate applied to the lease is 6.07%.

 

If the Company were to terminate the use of the Pioneer rig early then termination fees would apply, escalating to 75% of total expected costs if within one month prior to commencement date of planned works. Remuneration for work performed up to the date of termination, together with costs relating to demobilisation of the drilling unit to the demobilisation port would also be due.

 

Amounts recognised in profit and loss related to leases is detailed in notes 6 and 9.

 

25. Contingent and deferred consideration


 

Current

2023

US$'000

2022

US$'000

Contingent consideration

(101,669)

(101,559)

Petrofac deferred consideration

-

(6,121)


(101,669)

(107,680)

 

 

Non-current

 

2023

US$'000

 

2022

US$'000

Contingent consideration

(194,721)

(157,337)

MOGL deferred consideration

(63,979)

(61,783)


(258,700)

(219,120)


 

2023

US$'000

 

2022

US$'000

Cash flows relating to contingent and deferred considerations

(13,567)

(66,132)

 

Movement in contingent consideration consideration is as follows:




2023

US$'000

2022

US$'000

At 1 January

(258,896)

(19,480)

Business combinations (note 17)

-

(241,431)

Addition

(26,872)

-

Payments made

7,200

11,040

Reversal

-

1,100

Accretion

(9,814)

(5,830)

Changes in fair value

(8,008)

(4,295)

At 31 December

(296,390)

(258,896)

 

Movement in deferred consideration consideration is as follows:




2023

US$'000

2022

US$'000

At 1 January

(67,904)

(55,610)

Business combinations (note 17)

-

(63,415)

Payments made

6,367

55,156

Accretion

(2,442)

(4,035)

At 31 December

(63,979)

(67,904)


 

25.  Contingent and deferred consideration continued

Cash outflows in the year ended 31 December 2023 of $13.6 million (2022: $66.1 million) are in relation to the consideration payable on Petrofac GSA transaction and quarterly payments in consideration to the MOGL and Siccar oil price triggers.

MOGL

During the year ended 31 December 2022 the Group acquired MOGL which included elements of consideration that are payable upon certain events occurring and contingent considerations have been recognised to reflect this. Further details regarding the acquisition and the related contingent terms are set out in note 17. The carrying amount at 31 December 2023, discounted at 4.6% was $111 million (2022: $128 million using a discount rate of 4.25%). The total undiscounted potential consideration as at 31 December 2023 is $230 million (2022: $241 million).

The MOGL deferred consideration of $64 million (2022: $62 million) relates to completion of the MOGL transaction in February 2022. It is payable on 1 July 2025 and is discounted to reflect the time value of money.

Siccar

During the year ended 31 December 2022 the Group acquired Siccar Point Energy which included elements of consideration that are payable upon certain events occurring and contingent considerations have been recognised to reflect this. Further details regarding the acquisition and the related contingent terms are set out in note 17. The carrying amount at 31 December 2023, discounted at 4.6% was $130 million (2022: $102 million using a discount rate of 4.25%). The total undiscounted potential consideration as at 31 December 2023 is $362 million (2022: $362 million). As a result of the Rosebank field obtaining FDP approval during 2023, the carrying amount at 31 December 2023 has been increased.

Others

During the year ended 31 December 2023, the Group acquired a further 30% equity in the Cambo field from Shell. The acquisition included elements of consideration that are payable upon certain events occurring and contingent consideration has been recognised to reflect this. The consideration value equates to $1.50 per barrel of oil equivalent of the P50 resource volumes of the field, and is payable on the earlier of receipt of proceeds of any subsequent sale of a working interest in Cambo by the Group, or first oil. The carrying amount at 31 December 2023 was $12.7 million (2022: $nil).

During the year ended 31 December 2023, the Group acquired 40% equity in the Fotla field from Spirit. The acquisition included elements of consideration that are payable upon certain events occurring and contingent consideration has been recognised to reflect this. The consideration comprises two capped amounts with approximately two-thirds payable on final investment decision and one-third on first production. The carrying amount at 31 December 2023 was $14.2 million (2022: $nil).

 

A further $3.0 million (2022: $6.4 million) relates to Yeoman/Marigold, with a remaining unrisked payment of $11.0 million (2022: $11.0 million) contingent on achieving FDP and a further $6.0 million (2022: $6.0 million) unrisked on certain production criteria being met.

 

During the year ended 31 December 2023, further consideration of $5.7 million (2022: $6.4 million) was recognised as an additional payable due to changes in the variables in the calculation of the liability, resulting in $25.6 million (2022: $19.9 million) liability on Strathspey in accordance with the Sale and Purchase Agreement with Chevron.

 

Revaluation of contingent consideration in the year to 31 December 2023 resulted in an increase of $8.0 million (2022: increase of $4.3 million).

 

26.  Reserves

(a) Issued share capital

The issued share capital is as follows:

Number of common shares

Amount US$'000

At 31 December 2022

1,006,564,976

11,445

At 31 December 2023

1,014,372,281

11,540

On 5 October 2023, 7,807,305 ordinary shares of £0.01 each were issue to the Ithaca Energy plc Employee Benefit Trust (EBT) to satisfy the exercise of share options during the year and in future years.

 

On 26 October 2022 the Company undertook a share capital reduction whereby 114,000,000 issued A ordinary shares of $1.00 each were cancelled and extinguished. In addition on this date the share premium account as at 31 December 2021 of $634,658,000 was cancelled. A number of further steps followed in preparation for the IPO including the conversion of $1.00 shares to £0.88 shares, the conversion of £0.88 shares to £0.01 shares, the issue of bonus shares principally to existing shareholders and the issue of 105,000,000 new shares on the IPO. As a result the issued share capital of the Company immediately after the IPO was 1,005,162,217 ordinary shares of £0.01 each.

 

A reconciliation of the opening to closing number of shares in the year to 31 December 2022 is set out below:

Number of shares

 

A ordinary

B1 ordinary

B2 ordinary

Ordinary

Total

A ordinary shares of $1.00 each at 1 January 2022

1,001

-

-

-

1,001

Issue of new $0.01 B1 shares and $0.01 B2 shares

                                                                          

-

100

100

-

                                                                         

200

Issue of new $1.00 A ordinary shares

                                                                          

114,000,000

-

-

-

                                                                         

114,000,000

Cancellation of $1.00 A ordinary shares relating to capital reduction

                                                                          

(114,000,000)

-

-

-

                                                                         

(114,000,000)

Conversion of $1.00 A ordinary shares, $0.01 B1 share and 0.01 B2 share to £0.01 A ordinary shares

                                                                          

87,087

(12)

(12)

-

                                                                         

87,063

Bonus issue of new £0.01 A shares

                                                                          

898,131,843

-

-

-

                                                                         

898,131,843

Bonus issue of new £0.01 B1 shares

                                                                          

-

1,401,670

-

-

                                                                         

1,401,670

Bonus issue of new £0.01 B2 shares

                                                                          

-

-

420,440

-

                                                                         

420,440

Conversion of £ 0.01 A ordinary shares, £0.01 B1 shares and £0.01 B2 shares to £0.01 ordinary shares

                                                                          

(898,219,931)

(1,401,758)

(420,528)

900,042,217

                                                                         

-

Bonus issues of £0.01 ordinary shares

                                                                          

-

-

-

120,000

                                                                         

120,000

Issue of new £0.01 ordinary shares on IPO

                                                                          

-

-

-

105,000,000

                                                                         

105,000,000

Issue of new £0.01 ordinary shares on exercise of share options

                                                                          

-

-

-

1,402,759

                                                                         

1,402,759

Ordinary shares of £0.01 each at 31 December 2022

-

-

-

1,006,564,976

1,006,564,976


 

26.  Reserves continued

 

(b) Share premium

2023

2022

US$'000

US$'000

At 1 January

293,712

634,658

Share premium cancellation

-

(634,658)

Additions

15,133

293,712

At 31 December

308,845

293,712

The share premium account represents the cumulative difference between the market share price and the nominal share value on the issuance of new ordinary shares multiplied by the number of shares issued. Additions during 2023 represent the difference between the nominal value per share of £0.01 and the closing share price on the day before the shares were issued to the EBT multiplied by the number of shares. During 2022, the additions represent the difference between the nominal value per share of £0.01 and IPO price of £2.50 per share multiplied by the number of shares issued (net of share issues expenses).

(c) Capital contribution reserve

2023

2022

US$'000

US$'000

At 1 January

181,945

114,000

Capital reduction

-

(114,000)

Addition

-

181,945

At 31 December

181,945

181,945

 

During the year to 31 December 2022, the Company settled outstanding loan liabilities (including interest) of DKL Energy Limited (DKLE) out of IPO proceeds. As per the terms of the confirmation letter dated 29 November 2022 signed between DKLE and the Company, DKLE unconditionally and irrevocably released and forever discharged Ithaca Energy plc from any and all liabilities to the DKLE in respect of or in connection with the Capital and Subordinated loan note agreements. The remaining loan balance of $181.9 million has been capitalised as Capital Contribution Reserve as per the requirements of IFRS 9.

(d) Own shares

 


 

Own shares comprise shares held in the Ithaca Energy plc EBT which are being used to satisfy the exercise of employee share options. During the year, 7,807,305 ordinary shares of £0.01 each were issued to the EBT and 1,443,561 ordinary shares were used to satisfy the exercise of share options. As a result, the EBT held 6,363,744 ordinary shares of £0.01 each at 31 December 2023.

(e) Share-based payment reserve (note 32)

 

The share-based payment reserve represents the cumulative charge for share options, as described in note 32, less the cumulative cost of share option exercises.

 

27. Taxation



2023

US$'000

2022

US$'000

Current tax



Current corporation tax charge

(39,308)

(54,557)

Current EPL tax charge

(333,425)

(131,389)

Current corporation tax (charge)/credit - prior year

(17,426)

1,839

Total current tax charge

(390,159)

(184,107)

Deferred tax



Adjustment in respect of prior period

6,370

(641)

Group tax credit/(charge) in consolidated statement of profit or loss

227,360

(1,013,817)

Group tax charge in consolidated statement of other comprehensive income

(71,700)

(200,455)

Total deferred tax credit/(charge)

162,030

(1,214,913)

Deferred Petroleum Revenue Tax



Deferred PRT credit/(charge) in statement of profit or loss

70,037

(10,432)

Total tax charge through consolidated statement of profit or loss

(86,392)

(1,208,997)


 

 

27. Taxation continued

The tax on the Group's profit before tax differs from the theoretical amount that would arise using the 40% statutory rate of tax applicable for UK ring fence oil and gas activities as follows:

2023

2022

US$'000

US$'000

Accounting profit before tax

302,027

2,240,529

At tax rate of 40% (2022: 40%)

(120,811)

(896,211)

Non-deductible expense

(34,578)

(53,548)

Recognition of non-taxable gain on bargain purchase

-

534,069

Financing costs not allowed for SCT

(704)

(1,958)

Ring Fence Expenditure Supplement

102,866

155,113

Deferred tax effect of investment allowance

56,930

(20,615)

Prior year adjustment

(11,673)

1,198

Deferred PRT net of corporation tax

42,022

(6,259)

Deferred tax on EPL

215,910

(766,489)

Current tax on EPL

(333,425)

(131,389)

Prior year adjustments on acquired entities

-

(3,165)

Share-based payments

1,945

-

Unrecognised tax losses

(4,874)

(19,743)

Total tax charge recorded in the consolidated statement of profit or loss

(86,392)

(1,208,997)

The Company is UK tax resident. The effective rate of corporation tax applicable for UK ring fence oil and gas activities in both 2023 and 2022, prior to the introduction of the EPL, was 40% (2022: 40%) consisting of a Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%. Items affecting the tax charge include a 10% uplift on ring fence losses, Ring Fence Expenditure Supplement increasing the losses available to offset future profits subject to Ring Fence Corporation Tax and Supplementary Charge. In addition, investment allowance, a 62.5% uplift on capital expenditure, is available reducing the profits subject to the supplementary charge only. The credit arising in 2023 of $42.0 million was principally due the impairment of the Alba field due to forecast future production volumes. Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in the UK however adjustments to recognised deferred PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The EPL was enacted in July 2022 with effect from 26 May 2022, at a headline rate of 25% which increased the effective UK Ring Fenced oil and gas rate to 65% until 2025, resulting in additional current and deferred tax charges in the year to 31 December 2022. Further changes to the EPL were announced on 17 November 2022 and enacted in December 2022 whereby the Levy was increased to 35% from 1 January 2023 until 31 March 2028, increasing the effective UK Ring Fenced oil and gas tax rate to 75% resulting in an additional deferred tax charge during the year to 31 December 2022.

 

Deferred tax at 31 December relates to the following:

2023

2022

US$'000

US$'000

Deferred corporation tax liability

(1,944,941)

(2,258,813)

Deferred corporation tax asset

2,480,921

2,629,548

Deferred PRT asset

91,759

21,721

Net deferred tax asset

627,738

392,456

 

Deferred tax assets primarily relate to decommissioning liabilities, brought forward tax losses and accumulated losses and profits related to derivative contracts. Deferred tax liabilities primarily relate to accelerated capital allowances on property, plant and equipment and accumulated losses and profits related to derivative contracts. Deferred tax balances are presented net as they arise in the same jurisdiction and the Group has a legally-enforceable right to offset as well as an intention to settle on a net basis.

 

Non-oil and gas losses of $251 million (2022: $156 million), of which there is no expiry date, have not been recognised for deferred tax purposes as it is not sufficiently certain that there will be future non-oil and gas profits to offset these losses.

 

The net movement on deferred tax in the statement of financial position, including deferred PRT, is as follows:

 


2023

US$'000

2022

US$'000

At 1 January

392,456

220,918

Profit or loss credit/(charge)

                                                                          

303,767

(1,024,889)

Other comprehensive income charge

                                                                          

(71,700)

(200,455)

Deferred tax on decommissioning reimbursements (note 11)

                                                                          

3,214

-

Business combinations (note 17)

                                                                          

-

1,396,882

At 31 December

627,738

392,456

 

The net movement on deferred tax through the consolidated statement of profit or loss and consolidated statement of comprehensive income relates to the following:




2023

US$'000

2022

US$'000

Accelerated capital allowances

438,359

(490,246)

Tax losses

                                                                          

(216,937)

(386,819)

Decommissioning provision

                                                                          

52,440

(124,598)

Deferred PRT

                                                                          

(28,015)

4,173

Hedging

                                                                          

(101,744)

(226,040)

Share schemes

                                                                          

3,978

-

Investment allowances

                                                                          

13,950

8,617


162,030

(1,214,913)


 

27. Taxation continued





Deferred corporation tax on

 

Accelerated tax


Gross deferred corporation tax liabilities


Hedges US$'000

deferred PRT

US$'000

depreciation

US$'000

Total US$'000

At 1 January 2022

 

-

(12,861)

(675,279)

(688,140)

Prior year adjustment

 

-

-

(4,347)

(4,347)

Reclassification of decommissioning asset

 

-

-

(436,771)

(436,771)

Business combinations

 

-

-

(647,743)

(647,743)

Origination and reversal of temporary differences


-

4,173

(485,985)

(481,812)

At 31 December 2022 and 1 January 2023

 

-

(8,688)

(2,250,125)

(2,258,813)

Reclass to deferred corporation tax assets

 

(8,678)

-

-

(8,678)

Prior year adjustment

 

2,721

-

8,307

11,028

Origination and reversal of temporary differences


(101,744)

(28,015)

441,281

311,522

At 31 December 2023


(107,701)

(36,703)

(1,800,537)

(1,944,941)


 

 

Share schemes

 

Decommissioning

provision

 

 

Tax losses

 

 

Hedges

 

 

Total

Gross deferred corporation tax assets

US$'000

US$'000

US$'000

US$'000

US$'000

At 1 January 2022

-

197,666

500,282

178,956

876,904

Prior year adjustment

-

-

                                                                         

3,706

-

3,706

Reclassification of decommissioning asset

-

436,772

                                                                         

-

-

436,772

Business combinations

-

156,212

                                                                         

1,858,706

38,406

2,053,324

Origination and reversal of temporary differences

-

(124,598)

                                                                         

(390,520)

(226,040)

(741,158)

At 31 December 2022 and 1 January 2023

-

666,052

1,972,174

(8,678)

2,629,548

Reclass from deferred corporation tax liabilities

-

-

                                                                         

-

8,678

8,678

Prior year adjustment

177

-

                                                                         

(4,989)

-

(4,812)

Origination and reversal of temporary differences

3,802

55,654

                                                                         

(211,949)

-

(152,493)

At 31 December 2023

3,979

721,706

1,755,236

-

2,480,921


 


Total

Deferred PRT asset

US$'000

At 1 January 2022

32,154

Origination and reversal of temporary differences

(10,433)

At 31 December 2022 and 1 January 2023

21,721

Origination and reversal of temporary differences

70,037

At 31 December 2023

91,758

 

The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 31 December 2023 of $536 million and $92 million respectively (2022: $371 million and $21 million respectively) are supported by estimates of the Group's future taxable income, based on the same price and cost assumptions as used for impairment testing. The Group has undertaken a restructuring exercise to move certain assets between Group entities which has now been substantially completed. The recoverability of the deferred corporation tax asset is supported by this restructuring. The DTA relating to losses within the Group are expected to unwind against taxable profits before the end of 2029.

 

An EPL or 'Levy' was enacted on 14 July 2022 applying a Levy of 25% to the profits of oil and gas companies until 31 December 2025 or earlier if prices return to normalised levels. On 17 November 2022, the Levy was increased to 35% and extended to 31 March 2028 regardless of oil and gas prices. The Levy is charged upon oil and gas profits calculated on the same basis as Ring Fence Corporation Tax (RFCT), however, excludes relief for decommissioning and finance costs. RFCT losses and investment allowance are not available to offset the EPL. On 9 June 2023 an Energy Security Investment Mechanism price floor was announced which would remove the EPL if both average oil and gas prices fall to, or below, $71.40 per barrel for oil and £0.54 per therm for gas, for two consecutive quarters. It is not currently forecast that this price floor will be met for both oil and gas prices and therefore there is currently no impact from this on tax carrying values. On 6 March 2024 an extension of the Levy until 31 March 2029 was announced. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million.

 

On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK, introducing a global minimum effective tax rate of 15%. The legislation implements a domestic top-up tax and a multinational top-up tax, effective for all accounting periods starting on or after 31 December 2023. The Group does not anticipate that the adoption of this will have a material impact as the prevailing rate of tax in the United Kingdom is in excess of the 15% minimum rate. The Group has applied the exemption under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes and therefore there is no impact on the tax values reported.

28.  Commitments and contingencies

 


2023

US$'000

2022

US$'000

Capital commitments



Capital commitments incurred jointly with other venturers (Group's share)

506,959

52,309

The Group's capital expenditure is driven largely by full phase expenditure on existing producing fields, new development projects and appraisal and development activities. As of 31 December 2023, the Group had commitments for future capital expenditure amounting to $507 million (2022: $52.3 million). The key component of this relates to Rosebank, following FID approval in September 2023. Additionally, there are commitments in relation to AFEs (authorisations for expenditure) signed for activities on Captain enhanced oil extraction.

Contingencies

The Group enters into letters of credit and surety bonds to provide security for the Group's obligations under certain field and bi-lateral decommissioning security agreements, or equivalent, Sullom Voe Terminal Tariff Agreements and deferred payment obligations. The instruments are either held by the Law Debenture Trust Corporation P.L.C. under a trust deed or EnQuest Heather Limited, as SVT Terminal Operator. At 31 December 2023 the Group had $450 million (31 December 2022: $469 million) in letters of credit and surety bonds outstanding relating to security obligations under certain decommissioning and security agreements.

 

29.   Financial instruments

To estimate the fair value of financial instruments, the Group uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilise observable market data. In addition to market information, the Group incorporates transaction specific details that market participants would utilise in a fair value measurement, including the impact of non-performance risk. The Group characterises inputs used in determining fair value using a hierarchy that prioritises inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realised or settled in a current market transaction. The three levels of the fair value hierarchy are as follows:

?     Level 1 - inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

?     Level 2 - inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates and volatility factors, which can be observed or corroborated in the marketplace. The Group obtains information from sources such as the New York Mercantile Exchange and independent price publications.

?     Level 3 - inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value.

In forming estimates, the Group utilises the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorised based upon the lowest level of input that is significant to the fair value measurement. The valuation of over-the-counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorised as Level 2.

Gains or losses on financial instruments, that are not hedge accounted for, are recorded through the 'other gains and losses' line in the consolidated statement of profit or loss. Credit valuation adjustments (CVA) and debit valuation adjustments (DVA) are calculated for each trade using two key inputs, being future exposures and credit spreads (incorporating both probability of default and loss given default). Future exposures have been estimated using an expected exposure-based approach over the lifetime of the trades. For the risk associated with counterparties, the credit spread is calculated using market observable credit default spreads. For the own credit risk, the credit spread is calculated using reference to a senior unsecured quoted publicly traded bond of the parent entity using appropriate tenor adjustments, except for out-of-the-money derivatives with counterparties which are in the Group's RBL. These derivatives rank higher than those with other counterparties as they are fully secured as part of the RBL agreement. Therefore for the own risk credit risk adjustment (DVA) it has been estimated that the loss given default is zero and hence there is no DVA recognised for those derivatives which are with counterparties of the RBL.

All of the Group's assets are pledged as security against borrowings.

The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2023 are set out below:

 


 

Measured at amortised cost

Mandatorily

measured at fair value through

profit or loss

Derivatives

designated in hedge

relationships

 

Total carrying

amount

US$'000

US$'000

US$'000

US$'000

Financial assets





Cash and cash equivalents

153,215

-

-

153,215

Trade and other receivables

330,351

-

-

330,351

Derivative financial instruments

-

2,782

154,525

157,307

Financial liabilities





Borrowings

(748,151)

-

-

(748,151)

Trade and other payables

(343,279)

-

-

(343,279)

Lease liability

(20,559)

-

-

(20,559)

Contingent and deferred consideration

(63,979)

(296,390)

-

(360,369)

Derivative financial instruments

-

(10,373)

(3,335)

(13,708)





(845,193)


The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2022 are set out below:



 

 

Measured at

Mandatorily measured at fair value through

Derivatives designated in hedge

 

 

Total carrying


amortised cost

US$'000

profit or loss

US$'000

relationships

US$'000

amount US$'000

Financial assets





Cash and cash equivalents

253,822

-

-

253,822

Trade and other receivables

359,994

-

-

359,994

Derivative financial instruments

-

7,125

164,924

172,049

Financial liabilities





Borrowings

(1,213,731)

-

-

(1,213,731)

Trade and other payables

(618,460)

-

-

(618,460)

Lease liability

(58,858)

-

-

(58,858)

Contingent and deferred consideration

(67,904)

(258,896)

-

(326,800)

Derivative financial instruments

-

(57,546)

(106,563)

(164,109)





(1,596,093)

 

The following table presents the Group's material financial instruments measured at fair value for each hierarchy level as at 31 December 2023:






Level 1

Level 2

Level 3

Total Fair Value


US$'000

US$'000

US$'000

US$'000

Contingent consideration (note 25)

-

(24,039)

(272,351)

(296,390)

Derivative financial instrument asset

-

157,307

-

157,307

Derivative financial instrument liability

-

(13,708)

-

(13,708)

 

Movements in level 3 financial instruments in the 12 months to 31 December 2023 were as follows:









US$'000

At 1 January 2023




(223,246)

Additions




(26,872)

Cash settlement




-

Accretion




(8,799)

Changes in fair value




(13,434)

At 31 December 2023




(272,351)


 


 

Management has considered alternative scenarios to assess the valuation of the contingent consideration including, but not limited to, the key accounting estimate relating to the oil price. A reduction or increase in the price assumptions of 20% are considered to be reasonably possible changes. A 20% reduction in the oil price would result in a decrease in contingent consideration of $23.3 million (2022: $36.4 million). A 20% increase in the oil price would lead to an increase in contingent consideration of $41.0 million (2022: $26.4 million).

The level three contingent consideration is valued based on the probability of the events occurring ("trigger events") as set out in note 17. The forecast cash flows in the event of the trigger event occurring are discounted at a rate of 4.6% (2022: 4.25%).

The following table summarises the sensitivity of 20% change in probability of trigger event occurring and conditions being met for payment of contingent consideration, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date. The impact on equity is the same as the impact on profit before tax.

 

Change in probability

2023

US$'000

2022

US$'000

20% decrease in probability

97,119

87,080

20% increase in probability

(84,086)

(83,612)

 

The following table summarises the sensitivity of 1% decrease in discount rate, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of level 3 financial instruments at the reporting date. The impact on equity is the same as the impact on profit before tax.

 

Change in discount rate

2023

US$'000

2022

US$'000

1% decrease in discount rate

(5,284)

(4,374)

 

A 1% increase in discount rate would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant.




Financial instruments of the Group consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in the financial statements. At 31 December 2023 and 31 December 2022, financial instruments and the carrying amounts reported on the balance sheet approximates the fair values with the exception of borrowings. The carrying amount of borrowing is at amortised cost of $748.2 million (2022: $1,213.7 million) and the equivalent fair value is $781.4 million (2022: $1,257.9 million) per level 1 of the fair value hierarchy.

The table below presents the total gain on financial instruments that has been disclosed through the consolidated statement of profit or loss:

 

Cash flow hedge reserve

The table below presents the movement in financial instruments that has been disclosed through the statement of comprehensive income relating to the cash flow hedge reserve:


29. Financial instruments continued

Cost of hedging reserve

The table below presents the movement in financial instruments that has been disclosed through the statement of comprehensive income relating to the cost of hedging reserve:

 

The Group has identified that it is exposed principally to these areas of market risk.

i)  Commodity risk

Commodity price risk related to crude oil prices is the Group's most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Group is also exposed to natural gas price movements on uncontracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions. The Group's expenditures are subject to the effects of inflation, and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. The Group may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows.

In all periods presented the Group has designated certain commodity options as a cash flow hedge of highly probable sales. Because the critical terms (i.e. the quantity, maturity and underlying price) of the commodity option and their corresponding hedged items are the same, the Group performs a qualitative assessment of effectiveness and it is expected that the intrinsic value of the commodity option and the value of the corresponding hedged items will systematically change in opposite direction in response to movements in the price of underlying commodity if the price of the commodity increases above the strike price of the derivative. The main source of hedge ineffectiveness in these hedge relationships is the effect of the counterparty and the Group's own credit risk on the fair value of the option contracts, which is not reflected in the fair value of the hedged item and if the forecast transaction will happen earlier or later than originally expected. There was no hedge ineffectiveness in the current or prior year.

 

The Group's target is to hedge oil and gas prices up to a maximum of 75% of the next 12 months' production on a rolling annual basis, up to 50% in the following 12-month period and 25% in the subsequent 12-month period. On a rolling 12-month period under the RBL, the Group is required to hedge a minimum of 70% of volumes of net RBL entitlement production expected to be produced in the next 12 months, and 50% of volumes of net RBL entitlement produced for the following 12 months on a best-effort basis.

The below represents total commodity hedges in place at the 2023 year-end:

 

Derivative

Term

Volume


Average price

Oil swaps

Jan 24 - Dec 24

1,931,500

bbls

$82/bbl

Oil collars

Jan 24 - Dec 24

2,744,000

bbls

$75/bbl floor - $87/bbl ceiling

Gas swaps

Jan 24 - Dec 24

53,175,000

therms

140p/therm

Gas swaps

Jan 25 - Sep 25

18,225,000

therms

120p/therm

Gas collars

Jan 24 - Dec 24

123,350,000

therms

135p/therm floor - 210p/therm ceiling

Gas collars

Jan 25 - Mar 25

9,000,000

therms

130/therm floor - 185p/therm ceiling


The below represents total commodity hedges in place at the 2022 year-end:


Derivative

Term

Volume


Average price

Oil swaps

Jan 23 - Jun 24

3,390,500

bbls

$70/bbl

Oil collars

Jan 23 - Dec 23

4,560,000

bbls

$68/bbl floor - $91/bbl ceiling

Gas swaps

Jan 23 - Jun 24

104,585,000

therms

188p/therm

Gas puts

Apr 23 - Sep 23

9,150,000

therms

220p/therm

Gas collars

Jan 23 - Mar 24

100,200,000

therms

244p/therm floor - 479p/therm ceiling

 

The following table summarises the sensitivity of 20% decrease in realised commodity prices, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact on equity is the same as the impact on profit before tax.

 

Change in realised commodity price

2023

US$'000

2022

US$'000

20% decrease in realised oil price

(177,151)

(246,914)

20% decrease in realised gas price

(146,794)

(330,285)

 

A 20% increase in realised commodity prices would have the equal but opposite effect to the amounts shown above, on the basis that all other variables remain constant.

ii)  Interest risk

The calculation of interest payments for the RBL facility and bp unsecured loan incorporate SOFR. The Group is therefore exposed to interest rate risk to the extent that SOFR may fluctuate. The Group mitigates the risk of SOFR fluctuations by entering into interest rate swaps on floating rates.

There were no material interest rate financial instruments in place at 31 December 2023.

The below represents interest rate financial instruments in place at the 2022 year end:

Derivative

Term

Value

Rate

Interest rate swap (floating to fixed)

Jan 22 - Dec 23

$150 million

0.398%

 

 

The following table summarises the sensitivity of an increase of 250 basis points in interest rate, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date.


 

Change in interest rate

 



2023

US$'000

2022

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

US$'000

2022

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

US$'000

Total

$'000

Net-settled (derivative liabilities):




Commodity options

(51,654)

(15,402)

(67,056)





Gross-settled:




Foreign exchange forwards - gross outflows

(83,529)

(107,235)

(190,764)

Foreign exchange collars - gross outflows

-

-

-


(135,183)

(122,637)

 

vi)  Capital management

The Group's objectives when managing capital are to safeguard the Group's ability to continue as a going concern in order to provide returns to shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required.

The Group has approval from management to hedge external risks, commodity prices, interest rates and foreign exchange risk. This is designed to reduce the risk of adverse movements in market prices, interest rates and exchange rates eroding the Group's financial results.

 

30.  Derivative financial instruments

The net carrying amount of each category of derivative is set out below:

 


2023

US$'000

2022

US$'000

Oil swaps - cash flow hedge

9,913

(28,685)

Oil swaps - non-cash flow hedge

-

(15,027)

Oil collars - cash flow hedge

7,434

(21,983)

Gas swaps - cash flow hedge

47,232

19,797

Gas swaps - non-cash flow hedge

(2,290)

(29,271)

Gas puts - cash flow hedge

-

9,746

Gas collars - cash flow hedge

89,944

79,489

Interest rate swaps - non-cash flow hedge

637

7,125

FX forwards - non-cash flow hedge

(3,961)

(13,250)

FX collars - cash flow hedge

(3,335)

-

FX collars - non-cash flow hedge

(1,975)

-


143,599

7,941


 

30. Derivative financial instruments continued



 

Maturity analysis of derivative financial instruments

2023

US$'000

2022

US$'000

Non-current assets

17,810

21,191

Current assets

139,497

150,858

Non-current liabilities

-

(27,440)

Current liabilities

(13,708)

(136,668)


143,599

7,941

 

The fair value of commodity derivatives is estimated using a net present value model (commodity swaps) or an appropriate option valuation model (options and collars). These contracts are valued using observable market pricing data including volatilities. A 20% reduction in future commodity prices, with all other assumptions held constant, would result in a decrease in the fair value of derivatives of $113 million (2022: $179 million). A 20% increase in future commodity prices, with all other assumptions held constant, would result in an increase in the intrinsic value of option derivative instruments at 31 December 2023 of $88 million (2022: $188 million).

Derivative financial instruments that are with counterparties included within the RBL are subject to Master Netting Agreements, this includes the majority of the Group's derivative financial instruments as at 31 December 2023 and 2022.

Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2023 are detailed below:

 


Amount recognised in balance sheet

Related amounts not set off in balance

sheet

Net amount

$'000

$'000

$'000

Derivative assets

157,306

(4,436)

152,870

Derivative liabilities

(13,708)

4,436

(9,272)

 

Financial instruments subject to enforceable master netting agreements and similar agreements at 31 December 2022 are detailed below:

 


Amount recognised in balance sheet

Related amounts not set off in balance

sheet

Net amount

$'000

$'000

$'000

Derivative assets

172,049

(33,117)

138,932

Derivative liabilities

(164,109)

33,117

(130,992)

 

31. Related-party transactions

The immediate parent undertaking is DKL Energy Limited (incorporated in Jersey) who owns 88.55% of the issued share capital of Ithaca Energy plc. The registered office address of the DKL Energy Limited is 47 Esplanade, St Helier, Jersey, JE1 0BD.

The ultimate parent of the Group is Delek Group Limited (incorporated in Israel), an independent E&P company listed on the Tel Aviv Stock Exchange. The Group and Delek's ultimate controlling party is Mr Itshak Sharon Tshuva.

 

31. Related-party transactions continued

The consolidated financial statements include the financial information of the Group, which comprises the Company and the subsidiaries listed in the following table:

% equity interest at 31 December


Registered office

Country of incorporation

2023

2022


Ithaca Energy (E&P) Limited

1

Jersey

100%

100%

 

Ithaca Energy (UK) Limited

2

Scotland

100%

100%

 

Ithaca Minerals (North Sea) Limited

2

Scotland

100%

100%

 

Ithaca Energy (Holdings) Limited

3

Bermuda

100%

100%

 

Ithaca Energy Holdings (UK) Limited

2

Scotland

100%

100%

 

Ithaca Energy (North Sea) PLC

2

Scotland

100%

100%

 

Ithaca Oil and Gas Limited

4

England and Wales

100%

100%

 

Ithaca Petroleum Ltd

4

England and Wales

100%

100%

 

Ithaca Causeway Limited

4

England and Wales

100%

100%

 

Ithaca Gamma Limited

4

England and Wales

100%

100%

 

Ithaca Alpha (NI) Limited

5

Northern Ireland

100%

100%

 

Ithaca Epsilon Limited

4

England and Wales

100%

100%

 

Ithaca Exploration Limited

4

England and Wales

100%

100%

 

Ithaca Petroleum EHF

6

Iceland

100%

100%

 

Ithaca Dorset Limited

4

England and Wales

100%

100%

 

Ithaca SP UK Limited

4

England and Wales

100%

100%

 

Ithaca GSA Holdings Limited

1

Jersey

100%

100%

 

Ithaca GSA Limited

1

Jersey

100%

100%

 

Ithaca Energy Developments UK Limited

4

England and Wales

100%

100%

 

FPF-1 Limited

7

Jersey

100%

100%

 

Ithaca MA Limited

4

England and Wales

100%

100%

 

Ithaca SP Bonds PLC

4

England and Wales

100%

100%

 

Ithaca SP Finance Limited

4

England and Wales

100%

100%

 

Ithaca SP (Holdings) Limited

4

England and Wales

100%

100%

 

Ithaca SP (E&P) Limited

4

England and Wales

100%

100%

 

Ithaca SP (O&G) Limited

4

England and Wales

100%

100%

 

Ithaca SPE Limited

4

England and Wales

100%

100%

 

Ithaca Zeta Limited

4

England and Wales

100%

100%



 

31. Related party transactions continued

Transactions between subsidiaries are eliminated on consolidation.

 

1. 47 Esplanade, St Helier, Jersey, JE1 0BD

2.  13 Queen's Road, Aberdeen, Scotland AB15 4YL

3.  Canon's Court, 22 Victoria Street, Hamilton HM 12, Bermuda

4.  Pinsent Masons LLP, 1 Park Row, Leeds, England, LS1 5AB

5.  Pinsent Masons LLP, The Soloist, 1 Lanyon Place, Belfast, BT1 3LP

6.  Borgartúni 26, 105 Reykjavík, Iceland

7. 26 New Street, St Helier, Jersey, JE2 3RA

 

Amounts owed to Delek Group Limited

An outstanding interest amount of $29 million with respect to a historic related party loan with Delek Group Limited was repaid in full on 4 October 2022.

The movement in capital loan notes during the year ended 31 December 2022 related to imputed interest of $18 million on the unwind of the capital contribution and subsequent settlement of the $392 million balance under a waiver agreement.

On 8 November 2022, a waiver agreement was signed by DKL Energy Limited, the immediate parent company of Ithaca Energy plc at that time, to partially waive a capital note balance and a subordinated loan balance (including interest) totalling $469 million, such that, post-IPO these balances would no longer be due from Ithaca Energy plc.

A loan waiver of $181.9 million was recognised as a Capital Contribution on equity in the year to 31 December 2022.

Key management personnel

The following table provides remuneration to key management personnel, being persons having direct or indirect authority or responsibility of the Group, for the periods ended 31 December 2023 and 2022:

 

Key management personnel

2023

US$'000

2022

US$'000

Salaries and short-term employee benefits

5,741

4,590

Payments made in lieu of pension contributions

249

229

Company pension contributions

106

106

Share-based payment

5,863

12,623


11,959

17,548

 

Further detail regarding share-based payments received by key management personnel is set out below.

32. Share-based payments

The charge for share-based payment transactions in the year to 31 December 2023 was $16.4 million (2022: $14.1 million). Like other elements of compensation, this charge is processed through the time-writing system which allocates costs, based on time spent by individuals, to various activities within the Ithaca Energy plc Group. Part of this cost is therefore capitalised as directly attributable to capital projects and part is charged to the statement of profit or loss as operating costs of hydrocarbon activities, pre-licence exploration costs or administrative expenses.

 

32. Share-based payments continued

Long-Term Incentive Plans (LTIPs)

Outstanding share options under LTIPs were as follows:

 

All LTIP awards are nil-cost options. There are no performance conditions attaching to the Heritage and At-IPO awards. Details of the performance conditions of the 2022 LTIP are set out in the Directors' remuneration report. The fair values of all the LTIP awards were determined based on the share price on date of award. The Heritage awards vested over the period to 14 November 2023, the At-IPO awards vest in three equal tranches over the period to

14 November 2025 and the 2022 LTIP awards vest over the period to 1 April 2026. It is anticipated that future exercises of LTIP awards will be settled by equity. The total charge for LTIP share options in the year to 31 December 2023 was $12.9 million (2022: $0.6 million).

 

IPO-related share options

Under the terms section 11.6 of the Prospectus, the Executive Chairman, Gilad Myerson (GM) and the former Chief Executive Officer, Alan Bruce (AB) were entitled to an award of share options worth 0.2% of the value of the Group immediately on IPO which valued these awards at $5.0 million or 2,337,931 share options each. There are no performance conditions attaching to these share options. The exercise price of each of the share options is £0.01. Mr Myerson's share options vested immediately on IPO and Mr Bruce's share options were vesting equally over the period 21 July 2021 to 20 July 2026. During the year to 31 December 2022 Mr Myerson exercised 1,402,759 share options. The total charge for IPO-related share options in the year to 31 December 2023 was $0.5 million (2022: $7.3 million).

 


GM options

AB options

Total

Balance at 1 January 2023

935,172

2,337,931

3,273,103

Exercised during the year

-

-

-

Balance at 31 December 2023

935,172

2,337,931

3,273,103

Exercisable at 31 December 2023

935,172

935,172

1,870,344

Share option exercise price

£0.01

£0.01

N/A

Weighted average remaining life

N/A

N/A

N/A

 

Mr Bruce left the business on 4 January 2024 and, as part of his termination arrangements, retained his 935,172 share options which had already vested.





 

32. Share-based payments continued

Management Equity Plan (MEP)

During the year to 31 December 2022, Mr Myerson was also awarded share options under a Management Incentive Agreement (MIA) and Share Subscription and Bonus Agreement (SSBA), comprising 100 B1 shares of $0.01 each and 100 B2 shares of $0.01 each. Following the changes in the issued share capital, as detailed in note 26, in the run up to the IPO, on 9 November 2022 these share options equated to 1,401,759 B1 shares of £0.01 each and 420,528 B2 shares of £0.01 each. Following the IPO Mr Myerson elected to retain these options but in so doing did not waive his right to receive the Aggregate Guaranteed Payment (AGP) of $10.0 million less any special bonus payments since September 2021.

 

During the year to 31 December 2023, Mr Myerson elected to receive the AGP and $8.0 million (AGP of $10.0 million less special bonuses of $2.0 million) was paid to him on 1 December 2023. As a result, the MEP share options, which would otherwise have vested over the period to 30 September 2026, were transferred back to the Company for nil payment.

There were no performance conditions attaching to either the MEP share options or the AGP.

The total share-based payment charge for MEP arrangements in the year to 31 December 2023 was $3.0 million (2022: $6.2 million).

The share-based payment reserve of $15.5 million (2022: $4.9 million) reflects the opening balance of $4.9 million (2022: $nil) plus the charge of $12.9 million (2022: $0.6 million) for LTIPs plus the charge of $0.5 million (2022: $7.3 million) for IPO-related share options less the cost of satisfying exercises during the year of $2.8 million (2022: $3.0 million).

 

33. Dividends

 


2023

US$'million

2022

US$'million

First interim dividend of $0.132 per ordinary share announced 16 February 2023 and paid 9 March 2023

133.0

-

Second interim dividend of $0.132 per ordinary share announced 23 August 2023 and paid 29 September 2023

133.0

-

Total dividends paid during year ended 31 December 2023

266.0

-

Third interim dividend of $0.132 per ordinary share announced 21 March 2024 and payable in April 2024 (not accrued in the 2023 results)

134.0

-

Total dividends paid or payable relating to year ended 31 December 2023

400.0

-

 

34.  Subsequent events

On 6 March 2024 it was announced that EPL will be extended by a further year to 31 March 2029. If this had been enacted at the balance sheet date, it is estimated that this would have increased the deferred tax liability by $112.2 million.

On 19 March 2024, the North Sea Transition Authority sanctioned the extension of the licence on the Cambo field to 31 March 2026.

On 26 March 2024, the Group signed an exclusivity agreement between ENI and Ithaca Energy covering substantially all of ENI's UK upstream assets, excluding ENI CCUS and Irish sea assets, under which ENI has granted Ithaca exclusivity whilst a potential business combination is pursued. Under the terms of the proposed business combination ENI is anticipated to hold between 38% and 39% of the enlarged issued share capital of Ithaca Energy following completion. If this progresses further, it will be subject to the issuance of both a Circular and a Prospectus and the related shareholder approvals and will also be subject to,amongst other things, regulatory approvals.

Alternative Performance Measures

 

Non-GAAP measures

The Group uses certain performance metrics that are not specifically defined under United Kingdon adopted International Financial Reporting Standards or other generally accepted accounting principles. These measures are considered to be important as they track both operational and financial performance and are used to manage the business and to provide an objective comparison to Ithaca Energy's peer group. These non-GAAP measures which are presented in the Annual Report and Accounts are defined below:

Adjusted EBITDAX: earnings before interest, tax, put premiums on oil and gas derivative instruments, revaluation of derivative contracts, depletion depreciation and amortisation, impairment (charge)/reversal, exploration and evaluation expenditure, remeasurements of decommissioning reimbursement receivables, fair value losses on contingent consideration, gain on bargain purchase, transaction costs and historic claims relating to acquisitions. The Group believes that adjusted EBITDAX is a useful measure for stakeholders because it is a measure closely tracked by management to evaluate the Group's operating performance and to make financial, strategic and operating decisions and because it may help stakeholders to better understand and evaluate, in the same manner as management, the underlying trends in the Group's operational performance on a a comparable basis, period-on-period.

 

Adjusted EBITDAX is reconciled to profit after tax as follows:

2023

2022

$m

$m

Profit after tax

215.6

1,031.5

Taxation charge

86.4

1,209.0

Gain on bargain purchase

-

(1,335.2)

Depletion, depreciation and amortisation

740.3

662.9

Impairment charges

557.9

31.5

Net finance costs

184.0

203.0

Oil and gas put premiums

15.4

56.9

Revaluation of derivative contracts

(42.8)

(16.8)

Transaction costs

-

60.1

Exploration and evaluation expenses

13.6

9.0

Historic claim relating to an acquisition

(50.1)

-

Remeasurements of decommissioning reimbursement receivables

(5.6)

-

Fair value losses on contingent consideration

8.0

4.3

Adjusted EBITDAX

1,722.7

1,916.2

 

Adjusted net income: profit after tax excluding non-cash bargain purchase credits, material impairment charges or reversals, the tax effects of these items where applicable and non-cash deferred tax charges on initial application of EPL. Adjusted net income, which is presented as it eliminates items which distort year-on-year comparisons, is reconciled to profit after tax as follows:

 


2023

$m

2022

$m

Profit after tax

215.6

1,031.5

Gain on bargain purchase

-

(1,335.2)

Impairment charges

557.9

-

Tax credit on impairment charges

(403.9)

-

EPL deferred tax charge

-

766.5

Adjusted net income

369.6

462.8


Alternative Performance Measures continued

 

Adjusted earnings per share (EPS): Adjusted net income divided by average shares for the year of 1,006.7 million (2022: 1,005.2 million)

 


 

Adjusted net debt: consists of amounts outstanding under RBL facility, senior unsecured loan notes and bp unsecured loan less cash and cash equivalents and excludes intragroup debt arrangements or liabilities represented by letters of credit and surety bonds. Adjusted net debt, which excludes accrued interest on borrowings, lease liabilities and unamortised fees, comprises:

 


2023

$m

2022

$m

RBL drawn facility

-

(600.0)

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

Senior unsecured notes

(625.0)

(625.0)

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

bp unsecured loan

(100.0)

-

Cash and cash equivalents

153.2

253.8

Adjusted net debt

(571.8)

(971.2)

 

Leverage ratio: adjusted net debt at the end of the year divided by adjusted EBITDAX for the year then ended. The calculations are as follows:




2023

2022

Adjusted net debt ($m)

571.8

971.2

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

Adjusted EBITDAX ($m)

1,722.7

1,916.2

Leverage ratio

0.33x

0.51x

 

Available liquidity: the sum of cash and cash equivalents on the balance sheet and the undrawn amounts available to the Group using existing approved third-party facilities. Available liquidity comprises:




2023

$m

2022

$m

Cash and cash equivalents

153.2

253.8

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

Undrawn borrowing facilities

725.0

325.0

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

Undrawn optional project capital expenditure facility

150.0

-

Available liquidity

1,028.2

578.8

 

Subsequent to 31 December RBL liquidity increased from $725.0 million to $836.0 million.




 

Group free cash flow: net cash flow from operating activities less cash used in investing activities, adding back acquisition of subsidiaries net of cash acquired, less bank interest and interest rate swaps. This measure is considered a useful indicator of the Group's ability to make strategic investments, repay the Group's debt and meet other payment obligations. Group free cash flow reconciles to net cash flow from operating activities as follows:

 


2023

$m

2022

$m

Net cash flow from operating activities

1,290.8

1,723.3

Net cash used in investing activities

(492.4)

(1,404.2)

Add back acquisitions

-

957.5

Bank interest and charges

(99.8)

(142.8)

Interest rate swaps

7.0

0.8

Group free cash flow

705.6

1,134.6

 

Unit operating expenditure: operating costs (excluding over/underlift) including tariff expense, tariff income and tanker costs divided by net production for the year. This measure is considered a useful indicator of ongoing operating costs and is also used to compare performance between assets. Operating costs for this calculation reconcile to note 6 as follows:

 


 

DD&A rate per barrel: depletion, depreciation and amortisation charge for the year divided by net production for the year.

Other key performance indicators

Total production: historic production boe/d include volumes from date of acquisition of MOGL on 4 February 2022 and Siccar Point Energy and Summit on 30 June 2022.

Tier 1 process safety events: process safety incidents as defined by API 465 Process Safety-Recommended Practice On Key Performance Indicators.

Serious injury and fatality frequency: the number of serious injuries resulting in permanent impairment, as defined by IOGP, per million hours worked.

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