H1 Report 2024 Results & trading update

ITHACA ENERGY PLC H1 REPORT 2024

Strategic execution supports long-term growth

Transformational Business Combination with Eni UK, with a targeted completion in early Q4 2024, and execution of the Group's strategic objectives supports long-term outlook.

You can also read our H1 Report online: investors.ithacaenergy.com

Highlights	2
Outlook for 2024	8
Half year 2024 performance in review	9
Operational and financial review	14
Statement of Directors' responsibilities	21
Independent review report to Ithaca Energy plc	22

Financial statements	23 to 49
Unaudited condensed consolidated statement of profit or loss	23
Unaudited condensed consolidated statement of comprehensive income	24
Unaudited condensed consolidated statement of financial position	25
Unaudited condensed consolidated statement of changes in equity	27
Unaudited condensed consolidated statement of cash flows	28
Notes to the condensed consolidated financial statements	30
Alternative performance measures	50

H1 2024 strategic highlights

2024 INTERIM DIVIDEND DECLARED

Interim 2024 dividend

H1 2024 AVERAGE PRODUCTION

53.0 (H1 2023: 75.8)

KBOE/D

Financial highlights

H1 2024 ADJUSTED EBITDAX

H1 2024 AVAILABLE LIQUIDITY

LEVERAGE RATIO AT 30 JUNE 2024

\$533m

(H1 2023: \$980m)

\$1.0bn (H1 2023: \$0.8bn)

H1 2024 NET CASH FLOW FROM OPS

\$560m

(H1 2023: \$691m)

H1 2024 STATUTORY NET INCOME

\$106m (H1 2023: \$160m)

0.40x (H1 2023: 0.35x)

2024 DIVIDEND AMBITION

(2023 ACTUAL: \$400m)

All dividends are subject to operational performance and commodity prices as well as Combined Group refinancing and availability of distributable profits.

H1 2024 PRODUCTION SPLIT

COMBINED 2P RESERVES & 2C RESOURCES

632 mmboe

RESOURCE TO PRODUCTION RATIO

16 years

LARGEST UKCS FIELDS

6 of 10

Transformative Business Combination with Eni UK

Transformational Business Combination of Ithaca Energy and substantially all of Eni S.p.A's (Eni) UK upstream oil and gas assets announced in April 2024 and expected to complete in early Q4 2024, creating a dynamic growth player with the largest resource base in the UKCS and significant growth optionality creating a platform for organic and inorganic growth (the "Business Combination" to form the "Combined Group").

The Combination:

1. Creates a platform for value-driven growth

Transformational Combination creates a dynamic growth player with the largest resource base in the UKCS 1 and significant growth optionality via a highly-complementary and diversified portfolio of production and development assets, creating a platform for organic and inorganic growth
Well positioned to deliver further consolidation in mature UKCS basin, with a proven track record for value-accretive M&A and an agile response to market dislocation
Credible platform for international M&A as an additional route for value creation, leveraging Ithaca Energy's enhanced technical resource and financial strength and the expertise of Ithaca Energy's shareholders

2. Establishes a diverse and high-value portfolio at scale

• Second largest independent operator in the UKCS by 2024 production with pro-forma 2024 production forecast of 100 to 110 kboe/d 2

Organic growth potential to become largest producer in the UKCS by the early 2030s 3
Diverse and high-value portfolio of 37 producing fields including stakes in six of the ten largest UKCS fields 4
Enhanced production diversification with no hub representing over 20% of total production in 2H 2024
Material combined long-life 2P reserves and 2C resources of 632 million barrels of oil equivalent and an attractive resource to production ratio of 16 years 5

3. Enhances the Group's capabilities via Eni partnership

Combines the agility of an independent with the capabilities of a Major
Seeks to replicate the success and proven track record of material value creation of Eni's strategic satellite model in mature basins, e.g. Var Energi

Notes:

1. Welligence, NSAI Ithaca Energy CPR in relation to Ithaca Energy and NSAI Eni CPR in relation to the Eni UK Group, each as at 30 June 2024. Welligence's view of remaining reserves and resources based on an all producing/sanctioned assets in projects where they have confidence that they will progress and line of sight to FID.
1. 2024 pro forma production – 2024 production guidance from Ithaca Energy, NSAI Ithaca Energy CPR in relation to Ithaca Energy and NSAI Eni CPR in relation to the Eni UK Group, each as at 30 June 2024.
1. WoodMackenzie as at 26 March 2024, NSAI Ithaca Energy CPR in relation to Ithaca Energy and NSAI Eni CPR in relation to the Eni UK Group, each as at 30 June 2024.
1. Extracted from Wood Mackenzie on 26 March 2024; ranked by remaining reserves and resources.
1. NSAI Ithaca Energy CPR in relation to Ithaca Energy and NSAI Eni CPR in relation to the Eni UK Group, each as at 30 June 2024. The resource to production ratio is calculated by dividing the total aggregate 2P reserves and 2C resources of the Combined Group by the annual average rate of production of the Combined Group.

Transformative Business Combination with Eni UK

4. Supports attractive and sustainable shareholder returns

Combination accretive to EBITDAX with lower combined opex of \$23.2/boe (average 2025 to 2029)6 achieved through the delivery of operational hub and G&A synergies and to post-tax cash flow from operations (CFFO) through the delivery of fiscal synergies over the next five years
Strong cash flow generation with a potential \$10bn7 of total pre-tax cash flow from operations from 2P Reserves over the next five years (2025 to 2029) at \$88/bbl and 90p/therm
Disciplined and balanced capital allocation framework to invest, protect, return and evolve supporting long-term growth and attractive sustainable shareholder returns
Committed 2024 and 2025 dividend of 30% posttax CFFO with an ambition for special dividends to increase total shareholder distributions to up to \$500 million per annum8

5. Enhances balance sheet and financial strength

Increased scale from the Combination and greater debt capacity through the addition of Eni's unlevered assets provides access to more diverse pools and lower-cost sources of capital
Accretive to leverage position with a reduction in the Combined Groups' pro-forma Net debt to Adjusted EBITDAX to 0.23x, as at 31 December 2023
Combined utilisable c. \$6.0 billion of RFCT losses and c. \$5.0bn of SCT losses for the Combined Group as at 31 December 2023 to offset against future profits
Expected to improved credit rating from B+/B1 towards BB-/Ba in near-term
Increased financial strength to provide material firepower for growth and a potential pathway to investment grade credit rating

Notes:

1. The opex / bbl is calculated by dividing the total opex by the total production of the Combined Group. Cashflow from operations are calculated as revenue less opex per the NSAI Ithaca Energy CPR and the NSAI Eni CPR, each as at 30 June 2024.
1. Based on total pre-tax cash flow from operations from 2P reserves calculated based on the NSAI Ithaca Energy CPR and NSAI Eni CPR, each as at 30 June. Oil and gas prices calculated based upon the price parameters outlined in the NSAI Ithaca Energy CPR and NSAI Eni CPR, subject to the price adjustments set out therein.
1. All dividends are subject to operational performance and commodity prices as well as Combined Group refinancing and availability of distributable profits.

6. Supports responsible operations with ESG and decarbonisation focus

Delivers the oil and gas essential for energy security and affordability while cutting associated emissions
Enhances Ithaca Energy's GHG emissions intensity with a reduction in combined pro-forma CO2 e GHG emissions intensity to 21 kgCO2 e/boe (on a Scope 1 and 2 net equity basis)
Emissions reduction towards Net Zero target through near-term operational improvements and medium-to-long term portfolio transition

7. Strengthens leadership team and operational capabilities

Strengthened executive and operational teams, augmented by Eni, reflects the ambition, experience and operational rigour required to deliver the next phase of transformational growth
Experienced management and workforce with successful track record of safe operations, growth and value creation
Leveraging Eni's deep operational and technical capabilities via the Technical Services Agreement, to support and enhance organisational capabilities and support current and future development and growth plans

8. Supported by committed long-term shareholders

Aligned partnership between Delek and Eni in support of Ithaca Energy's long-term growth strategy
Shared shareholder ambition to enhance liquidity in the shares and support the investment proposition

Highlights

H1 2024 strategic highlights

The Group has made material progress in the first half of the year executing against its strategic objectives for 2024 across its BUY, BUILD and BOOST strategy with the aim of supporting long-term growth and maximising shareholder value.

Rosebank project progressed materially to multi-year development timeline including successful completion of major subsea campaign with the installation of all nine subsea structures ahead of schedule, in parallel with ongoing FPSO vessel modifications scopes where work is progressing to seek to maintain schedule
Captain Electrification technical Front-End Engineering Design (FEED) study completed with Final Investment Decision (FID) subject to fiscal and market conditions
Successfully awarded licence extension from 31 March 2024 to 31 March 2026 for Cambo field on 19 March, supporting the ongoing live farm-in processes to enable the future progression of Cambo and Fotla towards FID, subject to fiscal and market conditions

Boost

Successfully completed the Captain Enhanced Oil Recovery (EOR) Phase II project, executed on plan and within budget, with first Phase II polymer injection into the subsea wells commencing in May 2024 supporting an estimated peak response from the field in 2026
Continued high levels of activity at Captain, including rig recertification, in support of the topside drilling campaign scheduled to commence in Q3 2024
Completed W1 well workover at Erskine during July, reinstating the fifth production well at the field

Highlights continued

H1 2024 financial highlights

Adjusted EBITDAX of \$533.0 million (H1 2023: \$979.7 million), driven mainly by reduced production of 53.0 kboe/d (H1 2023: 75.8 kboe/d) and lower realised gas prices
Realised oil and gas prices (respectively) of \$87/boe and \$57/boe before hedging results and \$86/boe and \$92/boe after hedging results (H1 2023: \$85/boe and \$82/boe before hedging results and \$83/boe and \$125/boe after hedging results)
Operating costs, net of tanker costs and tariff income, reduced to \$263.3 million (H1 2023: \$272.1 million), reflecting the Group's stringent focus on cost control in an inflationary environment, with higher unit operating expenditure reflecting fixed cost nature of operating spend coupled with lower production volumes in the period
Statutory net income of \$105.7 million (H1 2023: \$159.6 million) including post-tax decommissioning liability related impairment charges of \$19.0 million (H1 2023: \$93.6 million of post-tax impairment charges principally related to GSA) and positively by post-tax reduction in contingent payment liabilities related to updated field development likelihoods of \$27.4 million
Robust net cash flow from operating activities of \$559.8 million (H1 2023: \$691.0 million)
H1 2024 producing asset capex of \$178 million and Rosebank capex of \$90 million reflecting material targeted investment across the Group's portfolio
Robust cash generation during H1 2024 supported the continued reduction of net debt with adjusted net debt of \$506.0 million (H1 2023: \$698.7 million)
Group leverage position of 0.40x adjusted net debt to adjusted EBITDAX (H1 2023: 0.35x)
Strong liquidity position of \$1,028.0 million reflecting a 30% increase (H1 2023: \$791.3 million)
First interim 2024 dividend of \$100 million declared and payable in September. Reaffirming dividend commitment in 2024 and 2025 of 30% post-tax CFFO with ambition for special dividends to increase total distributions to up to \$500 million per annum8

"We are pleased to report a strong period of cash flow generation. With a robust liquidity position at the end of H1 and increased financial strength from the addition of Eni UK's unlevered assets, following completion, we have significant financial firepower to support the delivery of the Group's strategy and returns to shareholders while supporting a potential pathway to investment grade."

Non-GAAP measures

Adjusted EBITDAX, operating costs, adjusted net debt, leverage and certain other reported metrics are non-GAAP measures that are not specifically defined under International Financial Reporting Standards or other generally accepted accounting principles. Further details are set out on pages 50 to 52.

^8. All dividends are subject to operational performance and commodity prices as well as Combined Group refinancing and availability of distributable profits.

Highlights continued

H1 2024 operational highlights

SAFETY

ZERO Serious incident and fatalities frequency (SIF-F)

DAILY PRODUCTION

Average H1 2024 production of 53.0 thousand barrels of oil equivalent per day (kboe/d)
- Q1 production of 58.7 kboe/d and Q2 production of 47.4 kboe/d
- H1 production split 69% liquids and 31% gas
Lower H1 production primarily reflects operational issues across our non-operated joint venture (NOJV) portfolio and non-operated infrastructure and planned turnaround scopes:
- As previously reported, non-operated Pierce field production impacted by the vessel remaining off-stream for the entirety of Q1. Returned to full production in Q2 and subsequently achieving high levels of uptime
- Non-operated Schiehallion field production impacted by: 1) previously reported weatherrelated downtime and outages caused by the Ocean Great White rig being off station, which will also have an impact on the timing of production wells later in 2024; and 2) operational issues on the Glen Lyon FPSO during Q2 restricting production capacity. The operator is working on a solution to address the issue with an expected return to full capacity in Q3
Previously reported compressor issues at Erskine's host facility (Lomond) significantly impacting production in H1, expected to return to production in H2
Turnaround activity at non-operated Jade field during Q2 to address J13 well productivity issues (ongoing)
Increase in unplanned production trips at Captain (operated) with remedial work ongoing to address backlog and reliability improvements

Outlook for 2024

Outlook for 2024 and management guidance

Alongside the publication of the Group's prospectus today, that will contain a full Competent Persons Report (CPR) prepared for Ithaca Energy plc and Eni UK by an independent reserves auditor, including field economic outputs, management provides the following updated FY 2024 guidance ranges (net to working interest) for Ithaca Energy on a Combined Group and standalone basis, based on an effective date of 30 June 2024.

Revisions in management guidance across production, Rosebank capex and cash tax are expected to have limited cash impact at current commodity prices of \$76/boe based on midpoint guidance ranges with management reaffirming its dividend commitments for 2024 and 2025 of 30% post-tax CFFO with an ambition for special dividends to increase total distributions to up to \$500 million per annum 8 :

• Production guidance:

FY 2024 Combined Group production of 76-81 kboe/d (revised from 80-87 kboe/d)
FY 2024 standalone production of 54-57 kboe/d (revised from 56-61 kboe/d), reflecting lower production volumes in H1
Net operating cost guidance:
- FY 2024 Combined Group net operating cost guidance range of \$650–730 million reaffirmed
- FY 2024 standalone net operating cost guidance range of \$540–590 million reaffirmed
Net producing asset capital cost guidance (excluding pre-FID projects and Rosebank development):
- FY 2024 Combined Group net producing asset capital cost guidance range of \$410-480 million reaffirmed
- FY 2024 standalone net producing asset capital cost guidance range of \$335-385 million reaffirmed

• Net Rosebank project capital cost guidance:

FY 2024 net Rosebank project capital cost guidance range lowered from \$190-230 million to \$170-195 million due to phasing of FPSO upgrades
Cash tax:

•

FY 2024 Combined Group cash tax guidance lowered from \$435-455 million to \$390-410 million
FY 2024 standalone cash tax guidance lowered from \$345-355 million to \$300-320 million largely due to prior year tax return submission processes including decommissioning loss carry back

COMBINED PRO-FORMA 2024 AVERAGE PRODUCTION 2

DIVIDEND COMMITMENT

30% Post-tax CFFO in 2024 and 2025

All dividends are subject to operational performance and commodity prices as well as Combined Group refinancing and availability of distributable profits.

Half Year 2024 performance in review

I am delighted to have joined Ithaca Energy in such a pivotal point in the Group's growth story and look forward to steering the business as it enters it next phase of transformational growth.

The publication of the prospectus marks a significant step towards completion of the Group's Business Combination with Eni UK anticipated in early Q4 2024, creating a dynamic growth player with significant organic and inorganic investment optionality."

YANIV FRIEDMAN EXECUTIVE CHAIRMAN

Delivering against the Group's 2024 strategic priorities

We enter the second half of the year in a position of strength having made material progress in the first half of the year delivering against our strategic objectives for 2024, most notably with the announcement of the Group's transformational Business Combination with substantially all of the upstream assets of Eni in the UK, creating a dynamic growth player. The Business Combination, expected to complete in early Q4 2024, enhances Ithaca Energy's position as a leading UKCS operator and highlights the Group's continued ambition for value-led organic and inorganic growth and delivering returns to shareholders.

Across our portfolio our focus remains on maximising the value of our diverse high-value and long-life assets via targeted investment in value-accretive organic opportunities in line with the Group's BUILD and BOOST strategy, delivering reserves growth and supporting our vision for sustainable long-term growth. Post completion of the Business Combination and through the Group's continued investment in key longlife assets such as Rosebank and Captain, the Group will materially grow its 2P reserve base to 342 mmboe3 from 254 mmboe at 31 December 2023.

Business Combination creates a dynamic growth player with significant optionality

In April 2024, Ithaca Energy announced its transformational Business Combination with Eni UK creating a significant growth player with the single largest resource base in the UK North Sea and underlying un-risked growth potential to become the largest producer in the UKCS by 20303 . The synergistic Business Combination brings together highlycomplementary portfolios with significant scale, balance and optionality creating a strategic platform for material long-term organic growth.

With a proven track record for value-accretive M&A, the Combination creates an enhanced platform for delivery of the Group's inorganic growth strategy in the North Sea and internationally. Ithaca Energy is well positioned to play a pivotal role in further North Sea consolidation, taking an agile response to continued market dislocation, and with access to Eni's global credentials and the expertise and relationships of its shareholders, supports the ability to broaden the Group's M&A strategy internationally, establishing additional options for value creation.

The Group announced a number of changes to its Board of Directors and Executive Management team in the first half of the year to strengthen its leadership and operational capabilities. Through the appointment of Yaniv Friedman as Executive Chairman, Luciano Vasques as Chief Executive Officer (on completion of the Combination) and Odin Estensen as Chief Operating Officer alongside Iain Lewis as incumbent Chief Financial Officer, the Group's strengthened executive team reflects the ambition, experience and operational rigour required to deliver the next phase of transformational growth. The Group's leadership and operational teams will be further augmented by senior leadership appointees and access to Eni's deep operational and technical capabilities via a Technical Services Agreement on deal completion.

The Business Combination further enhances the Group's balance sheet and financial strength. With the addition of Eni UK's unlevered assets, the Combined Group's increased scale, diversification and debt capacity provides access to more attractive and diverse pools of capital, creating material firepower to support the delivery of Ithaca Energy's BUY, BUILD and BOOST strategy while supporting a potential pathway to an investment grade credit rating.

Ithaca Energy's enhanced cash flow generation, with a potential \$10bn of total pre-tax cash flow from operations from 2P reserves over the next five years (2025 to 2029) at \$88/bbl, 90p/therm7 , together with its disciplined and capital allocation framework, supports the delivery of attractive sustainable shareholder distributions with a commitment to distribute 30% of post-tax CFFO and an ambition for special dividends to increase total shareholder distributions to up to \$500 million per annum in 2024 and 20258.

All dividends are subject to operational performance and commodity prices as well as Combined Group refinancing and availability of distributable profits.

As the Group enters its next phase of growth, it is supported by committed long-term shareholders and an aligned partnership between Delek and Eni in support of Ithaca Energy's long-term growth strategy. By combining the agility of an independent with the capabilities of a Major, the combination seeks to replicate the success and proven track record of material value creation of Eni's satellite model in mature basins.

BUILD: Continued progress across our highvalue development portfolio

Following a successful final investment decision and sanction of the Rosebank project in H2 2023, the project continues to progress in 2024 towards first production in 2026/27, delivering against the Group's strategy to BUILD a robust long-term portfolio of low carbon intensity assets.

Materially in line with the project's multi-year development timeline, work is progressing across the core project scopes including the upgrade of the Petrojarl Rosebank FPSO. In July 2024, the development achieved a key milestone, completing the major subsea campaign ahead of schedule with installation of all nine subsea structures on the seabed of the Rosebank field. In the second half of the year, the project focus will turn to rig readiness in support of the drilling rig mobilisation in Q1 2025. FPSO engineering and modification scopes continue to progress and are critical to delivering on the targeted first production date.

The Group remains committed to developing its pre-FID projects and is progressing live farm-down processes for its Cambo and Fotla interests. In the second half of the year, the Group will seek to complete development concept selection for Fotla, to support a final investment decision for the brownfield tie-back opportunity in the near-term, with FID subject to fiscal conditions.

BOOST: Successful delivery of Captain EOR Phase II project

In H1 2024, the Group achieved a major milestone at its flagship Captain field, successfully completing its EOR

Phase II project within budget and on schedule. The project seeks to build on the success of its platformbased EOR Phase I project expanding to the subsea area of the field with first polymer injection in the subsea wells achieved in May 2024, ahead of schedule.

Captain EOR phase II aims to significantly BOOST production at the field, doubling net production as it reaches peak production in 2026, making a material contribution to the Group's medium-term production growth. The pioneering polymer technology enhances reservoir sweep efficiency by injecting a watersoluble polymer into the reservoir to sweep previously bypassed and stranded oil, directing it toward adjacent production wells. By accelerating and maximising field life recovery, polymer technology provides significant decarbonisation benefits, with the potential to reduce carbon intensity by up to an estimated 40%.

High levels of activity at the Captain field continued throughout H1, with turnaround scopes executed in May and rig recertification activity ongoing in support of the topside drilling campaign scheduled for Q3. The campaign, that extends over a two-year duration, is targeting three new production wells, an injector well and the workover of two wells.

At the Group's operated Erskine field, a well workover was completed in July by the Valaris 213 jack-up drilling rig, successfully reinstating the fifth production well at the field returning the asset to full production capability. Following scheduled turnaround activity in August and remediation of compressor issues at the host Lomond field, the Erskine field is expected to return to full production in H2.

H1 operational performance

Our continued focus on personal and process safety, following a rise in recordable events in 2023, has resulted in a strong safety performance in the first half of the year. The Group recorded zero Tier 1 and Tier 2 process safety events or high-potential incidents and its serious incident and fatality rate remained at zero during the period.

Production averaged 53.0 kboe/d in the first half of 2024, split 58.7 kboe/d in Q1 and 47.4 kboe/d in Q2 (H1 2023: 75.8 kboe/d). Production in the period reflects the impact of operational issues experienced across our non-operated joint ventures and infrastructure together with planned shutdowns across the Group's operated portfolio. Production in the sixmonth period was split 69% oil and 31% gas.

The Group's operated assets accounted for 49% of total H1 2024 production (H1 2023: 54%) with production efficiency across the Group's operated portfolio recorded of 83% (excluding turnaround activity and downtime associated with non-operated infrastructure). Operated asset production efficiency has been impacted in the first half of the year by extended shut down periods at the Captain field and GSA area, the loss of water injection support at Alba that was rectified in Q2 and ongoing compressor issues at Erskine's host facility (Lomond) that are expected to be resolved in early H2, supporting a return to full production of our operated asset base.

Across our NOJV portfolio, production was impacted by a number of previously reported operational issues including the delayed start-up and curtailed production of the Pierce field (which has now returned to full production), productivity issues at the Jade J13 well (currently being remediated) and ongoing operational issues at Schiehallion. Production from the Schiehallion field has been restricted as a result of operational issues on the Glen Lyon FPSO, with the operator working on a solution to address the issue to deliver an expected return to full capacity in late Q3.

With all operated assets back to full production and the majority of non-operated joint venture and infrastructure issues in H1 resolved, the Group is expecting production rates of between 55-61 kboe/d in the second half of the year on a standalone basis.

Operating costs, net of tanker costs and tariff income, reduced to \$263.3 million (H1 2023: \$272.1 million), reflecting the Group's stringent focus on cost control in an inflationary environment, however, due to lower production volumes in the period and the fixed cost nature of its operating expenditure, represented an increase to net unit opex cost to \$27.3/boe (H1 2023: \$19.8/boe).

H1 2024 ADJUSTED EBITDAX \$0.5bn

H1 2024 LEVERAGE RATIO 0.40x Adjusted net debt to adjusted EBITDAX

The Group expects to materially reduce the average operating cost per barrel in the short to medium-term through transitioning its portfolio to earlier life assets with lower operating costs, such as Rosebank, together with the addition of Eni UK's low operating cost assets following completion of the Business Combination and the retirement of late-life high-opex assets.

Total net producing asset capital expenditure (excluding decommissioning) in H1 2024 of \$178 million (H1 2023: \$188 million) reflects material capital spend at Captain relating to the completion of the Captain EOR Phase II project and rig recertification scopes in support of the upcoming topside drilling campaign, representing over 50% of producing asset capital expenditure in the period. Net capex of \$90 million in support of the Rosebank development reflects continued high level of activity in the ongoing modification of the FPSO and subsea campaign, remaining in line with management expectations.

Decarbonisation focus

Ithaca Energy has made continued strides in the first half of the year towards delivering against its emissions reduction plan by pursuing operational optimisation projects that support the Group's short-term emissions reduction goals. Key decarbonisation initiatives, such as reinstating the second export gas compressor, power water pumps upgrades and flare gas recovery are progressing as planned at Captain with a flotel identified to enable work to progress in the second half of the year.

As the Group continues its decarbonisation journey to achieve its ambition of a 50% reduction in Scope 1 and 2 CO2 e emissions by 2030 (on a net equity basis), the focus remains on major projects like the potential electrification of our flagship Captain field. With over 70% of Captain's GHG emissions originating from power generation, partial electrification could significantly reduce emissions intensity making the Captain electrification project a meaningful step in helping Ithaca Energy meet its 2030 emissions reduction target.

The Group has successfully completed its FEED study, confirming the technical feasibility of the Captain electrification project and a Final Investment Decision

will be taken once the financial and commercial viability of the project has been established given the current political and fiscal environment. We are actively seeking assurances from the UK Government regarding the protection of the decarbonisation allowance for sanctioned projects, to enable an investment decision that would deliver substantial decarbonisation benefits in line with the North Sea Transition Deal.

For the first six months of 2024, the GHG emissions intensity (Scope 1 and 2), from our operated assets was 33.9 kgCO2 e/boe.

Robust cash flow generation and increased liquidity

During H1 2024, our diversified, high-quality asset base generated net cash flow from operating activities of \$559.8 million (H1 2023: \$691.0 million). This robust cash generation in the first half of the year supported the continued reduction in net debt, with the Group reporting adjusted net debt of \$506.0 million (H1 2023: \$698.7 million), representing an adjusted net debt to adjusted EBITDAX ratio of 0.40x at 30 June 2024 (H1 2023: 0.35x).

The Group successfully completed the semi-annual redetermination of its Reserves Based Lending facility (RBL) at the end of June securing borrowing base availability of \$659 million (31 December 2023: \$725 million), excluding RBL facilities utilised for letters of credits.

The Group continues to have sufficient available capital to support our capital allocation policy with a 30% growth in its liquidity position at 30 June 2024 to \$1,028.0 million (H1 2023: \$791.3 million), reflecting the reduction in adjusted net debt and availability of a capex carry facility. Ithaca Energy continues to monitor market conditions and evaluate potential refinancing options to optimise its capital structure and address upcoming debt maturities via the public debt capital markets.

Net income recorded in H1 2024 of \$105.7 million (H1 2023: \$159.6 million), was impacted negatively by post-tax decommissioning liability related impairment

Our focus in 2024, and beyond, will continue to be on high-grading investment across our range of growth opportunities to maximise sustainable shareholder value."

charges of \$19.0 million (H1 2023: \$93.6 million of post-tax impairment charges principally related to GSA) and positively by post-tax reduction in contingent payment liabilities related to updated field development likelihoods of \$27.4 million.

As we move into the second half of the year, we continue to take a proactive and disciplined approach to hedging, recognising the importance of balancing upside exposure to commodity prices while managing downside protection of our cash flows in line with the PROTECT pillar of our capital allocation policy. The Group has taken a progressive approach to its hedging policy in H1 with an evolution of the policy to include 25% hedge availability to wide zero cost collars to drive access to additional upside value potential. The Group has continued to build material hedge positions in the first six months of the year with 10.8 million barrels of oil equivalent (mmboe) hedged from H2 2024 into 2026 (58% oil) at an average price floor of \$78/bbl for oil and 96p/therm for gas. Beyond the period end, further material hedges have been placed with 16.8 mmboe hedged at 19 August 2024 at an average swap price of \$81/bbl for oil and 107p/therm for gas and an average collar price of \$75bbl for oil and 97p/therm for gas.

The importance of the Group's robust hedging policy has again been highlighted in the first half of the year with hedging gains recorded of \$98 million in the period (H1 2023: \$172 million).

In line with our capital allocation policy, we paid the third tranche of our 2023 dividend of \$134 million in April 2024, delivering on the Group's 2023 dividend target of \$400 million at IPO. The Group today declares the first interim 2024 dividend of \$100 million payable in September 2024. Ithaca Energy remains committed to its declared dividend policy in 2024 and 2025 of 30% post-tax CFFO with an ambition for special dividends to increase total shareholder distributions to up to \$500 million per annum 8 .

Energy Profits Levy

The UK oil and gas industry has continued to face substantial headwinds in the first half of 2024 with the UK Government signaling further fiscal changes for the sector. The new Chancellor's fiscal statement and policy paper, delivered on 29 July, set out the Government's intention, in line with the Party's election manifesto, to raise the Energy Profits Levy rate, taking the headline tax rate for the sector to 78%, its intentions to remove the Energy Profits Levy's investment allowance and further review Energy Profits Levy capital allowances, while extending the levy a further year to 31 March 2030. These changes are expected to become effective 1 November 2024.

The sector has now entered into a period of consultation with His Majesty's Treasury in relation to the Energy Profits Levy capital relief framework, ahead of the Chancellor's Autumn Statement. Ithaca Energy continues to actively and constructively engage with the UK Government, making representations as part of this formal process, to highlight the ongoing impact of the Energy Profits Levy to investment and the long-term damage further changes to the fiscal regime make to the achievability of the UK's energy security and decarbonisation objectives.

Yaniv Friedman Executive Chairman

21 August 2024

All dividends are subject to operational performance and commodity prices as well as Combined Group refinancing and availability of distributable profits.

Delivering results and developing optionality

Summary of financial results
Financial key performance indicators (KPIs)	H1 2024	H1 2023
Adjusted EBITDAX1 (\$m)	533.0	979.7
Statutory net income (\$m)	105.7	159.6
Adjusted net income1 (\$m)	124.7	253.2
Basic EPS (cents)	10.5	15.9
Net cash flow from operating activities (\$m)	559.8	691.0
Available liquidity1 (\$m)	1,028.0	791.3
Unit operating expenditure1 (\$/boe)	27.3	19.8
Adjusted net debt1 (\$m)	506.0	698.7
Adjusted net debt/adjusted EBITDAX1	0.40x	0.35x

Other KPIs	H1 2024	H1 2023

Total production (boe/d)	53,046	75,755
Tier 1 and 2 process safety events	0	1
Serious injury and fatality frequency	0	0

Non-GAAP measure.

Details of non-GAAP measures are set out on pages 50 to 52.

Operational and financial review

Financial performance: statutory net income, revenue, costs and charges and adjusted EBITDAX

Statutory net income was \$105.7 million (H1 2023: \$159.6 million) reflecting principally the lower production during the period as well as lower gas prices, and a lower level of "other gains" compared to H1 2023 partly offset by lower impairment charges and lower net finance costs in H1 2024.

Adjusted EBITDAX is a key measure of operational performance delivery in the business and amounted to \$533.0 million (H1 2023: \$979.7 million) mainly reflecting lower revenue in H1 2024 of \$841.9 million (H1 2023: \$1,248.1 million). The reduction in revenue was principally due to lower production and lower realised gas commodity prices compared to H1 2023.

Average realised oil prices for H1 2024 were \$87/boe before hedging results and \$86/boe after hedging results (H1 2023: \$85/boe before hedging results and \$83/boe after hedging results). Average realised gas prices for H1 2023 were \$57/boe before hedging results and \$92/boe after hedging results (H1 2023: \$82/boe before hedging results and \$125/boe after hedging results).

During the period, operating costs net of tanker costs and tariff income reduced to \$263.3 million (H1 2023: \$272.1 million). The increase in unit operating expenditure per boe compared to H1 2023 reflects the significant fixed cost nature of operating cost spend coupled with lower production in H1 2024.

Adjusted EBITDAX analysis

		H1 2024		H1 2023		FY 2023
Production	kboe/d	mmboe	kboe/d	mmboe	kboe/d	mmboe
Oil	34	6	47	8	43	16
Gas	16	3	26	5	24	9
Condensate	3	1	3	1	3	1
Total production	53	10	76	14	70	26
Revenues1	\$/boe	\$m	\$/boe	\$m	\$/boe	\$m
Oil revenue	87	546	85	650	85	1,330
Gas revenue	57	170	82	380	76	659
Condensate revenue	45	18	42	26	44	49
Oil and gas hedging gains	10	98	13	172	10	266
Total	86	832	90	1,228	90	2,303
Movement in oil and gas inventory	–	(5)	4	58	1	20
Tanker costs	(1)	(10)	(1)	(12)	(1)	(21)
Stella royalties	–	(1)	–	(3)	–	(4)
Total value from production	85	816	93	1,271	90	2,299
Costs
Operating costs	(27)	(263)	(20)	(272)	(20)	(524)
Routine G&A	(3)	(20)	(2)	(15)	(2)	(34)
Foreign exchange losses	–	–	–	(4)	(1)	(18)
Total operating cash costs	(30)	(283)	(22)	(291)	(23)	(576)
Adjusted EBITDAX2	55	533	71	980	67	1,723

Revenues in the above table exclude principally other income and put premiums on oil and gas derivative instruments.
Non-GAAP measure.

Revenue and adjusted EBITDAX	H1 2024	H1 2023
Production (boe/d)	53,046	75,755
	\$m	\$m
Oil sales	546.5	650.2
Gas sales	170.4	379.9
Condensate sales	18.7	26.4
Other income	9.7	17.4
Realised losses on oil derivative contracts	(6.7)	(12.5)
Put premiums on oil derivative instruments	(0.6)	(6.3)
Realised gains on gas derivative contracts	105.1	194.1
Put premiums on gas derivative instruments	(1.2)	(1.1)
Total revenue	841.9	1,248.1
Operating costs	(282.2)	(300.7)
Inventory movements and other items	(26.7)	32.3
Adjusted EBITDAX	533.0	979.7

Statutory net income was \$105.7 million (H1 2023: \$159.6 million) and adjusted net income was \$124.7 million (H1 2023: \$253.2 million). A reconciliation between statutory net income and adjusted net income is set out on page 18.

Total costs and charges

Total costs and charges amounted to \$652.4 million (H1 2023: \$999.4 million) and comprised:	H1 2024 \$m	H1 2023 \$m
Depletion, depreciation and amortisation	(252.9)	(384.1)
Operating costs	(282.2)	(300.7)
Movement in inventory	(5.1)	57.5
Royalties	(1.1)	(3.2)
Impairment charges on development and production assets	(35.5)	(328.4)
Exploration and evaluation expenses	(1.5)	(1.3)
Other gains	26.2	72.2
Administrative expenses	(20.0)	(14.9)
Net finance costs	(80.3)	(96.5)
Total costs and charges	(652.4)	(999.4)

Depletion, depreciation and amortisation charges were \$252.9 million (H1 2023: \$384.1 million). The year-on-year reduction was principally due to lower production in H1 2024. Depletion, depreciation and amortisation per barrel was \$26 (H1 2023: \$28).

Operating costs amounted to \$282.2 million (H1 2023: \$300.7 million) with the decrease driven mainly by lower production.

Movements in oil and gas inventories was a charge of \$5.1 million (H1 2023: credit of \$57.5 million) representing movements in underlift/overlift entitlement imbalances.

Impairment charges on development and production assets of \$35.5 million (H1 2023: \$328.4 million) principally reflects decommissioning revisions on assets which have either ceased production or have been fully written down. The charge in H1 2023 mainly comprised an impairment of development and production assets relating to the Greater Stella Area field as a result of lower future gas prices than previously forecast and a reduction in planned activity as a direct result of the EPL.

Exploration and evaluation expenses amounted to \$1.5 million (H1 2023: \$1.3 million) and principally relate to licence relinquishments during the period.

Other gains of \$26.2 million (H1 2022: \$72.2 million) comprise principally fair value gains on contingent consideration reflecting updated probabilities of certain future events occurring. The credit in H1 2023 was mainly due to gains on financial instruments and a historic claim relating to an acquisition.

Administrative expenses were \$20.0 million (H1 2023: \$14.9 million) with the increase principally due to costs relating to business combination completion activities.

Net finance costs were \$80.3 million (H1 2023: \$96.5 million) with the reduction principally due to lower levels of debt compared to H1 2023.

Financial performance: net income
	H1 2024 \$m	H1 2023 \$m
Profit before tax	189.4	248.7
Tax	(83.7)	(89.1)
Net income after tax	105.7	159.6
Impairment charges	35.5	328.4
Tax credit on impairment charges	(16.5)	(234.8)
Adjusted net income1	124.7	253.2

1. Non-GAAP measure.

Taxation

The tax charge for the period was \$83.7 million (H1 2023: \$89.1 million) with the reduction mainly due to lower pre-tax profits.

Earnings per share (EPS)

Statutory EPS was 10.5 cents (H1 2023: 15.9 cents) and adjusted EPS was 12.4 cents (H1 2023: 25.2 cents). Adjusted EPS eliminates items which distort period-on-period comparisons such as impairment charges and the tax effect of such items.

Shares in issue

As at 30 June 2024, there were 1,014.4 million (H1 2023: 1,006.6 million) shares in issue. The weighted average number of shares during the period for EPS calculations, excluding shares held by the Employee Benefit Trust, was 1,006.6 million (H1 2023: 1,006.6 million).

Dividends

A third interim dividend for 2023 of \$133.6 million was paid during the period (H1 2023: first interim dividend for 2023 of \$133.0 million).

Financial position: assets/liabilities/equity	30 June 2024 \$m	31 December 2023 \$m
Total assets	6,325.9	6,323.5
Total liabilities	(3,867.7)	(3,802.2)
Net assets and shareholders' equity	2,458.2	2,521.3

Assets

At 30 June 2024, total assets amounted to \$6,325.9 million (31 December 2023: \$6,323.5 million), and comprised current assets of \$821.7 million (31 December 2023: \$845.6 million) and non-currents assets of \$5,504.2 million (31 December 2023: \$5,477.9 million). The marginal increase in total assets was primarily due higher cash balances of \$134.5 million due to cash generation in H1 2024 and an increase in property, plant and equipment of \$48.2 million principally due to changes in decommissioning estimates, partly offset by a reduction in derivative financial instruments of \$104.5 million as a result of the utilisation of relatively highly-priced gas collars and swaps during H1 2024 and a decrease in trade and other receivables of \$67.3 million largely due to lower accrued income as a result of the lower production.

Liabilities

At 30 June 2024, total liabilities amounted to \$3,867.7 million (31 December 2023: \$3,802.2 million) including decommissioning provisions of \$1,923.1 million (31 December 2023: \$1,859.7 million) and gross borrowings of \$819.3 million (31 December 2023: \$748.2 million). The increase in total liabilities during the period was primarily due to the higher decommissioning liabilities as a result of revisions to estimates and the higher gross borrowings as a result of utilisation of the optional project capital expenditure facility, partly offset by reductions in trade and other payables due to reduced production, lower corporation tax payable and lower contingent consideration due to payments made and revisions to estimates in H1 2024.

Equity and reserves

At 30 June 2024, total equity and reserves amounted to \$2,458.2 million (31 December 2023: \$2,521.3 million). The reduction in equity and reserves during the period was primarily due to dividends paid of \$133.6 million and unfavourable hedging reserve movements of \$38.2 million partly offset by the profit for the period of \$105.7 million.

Financial position: cash
	H1 2024 \$m	H1 2023 \$m
Opening cash	153.2	253.8
Operating cash flows	559.8	691.0
Investing cash flows	(229.4)	(221.6)
Financing cash flows	(196.2)	(548.1)
Foreign exchange	0.3	1.2
Net cash flow	134.5	(77.5)
Closing cash	287.7	176.3
Undrawn borrowing facilities	740.3	615.0
Available liquidity	1,028.0	791.3

Operating cash flows

Net cash from operating activities amounted to \$559.8 million (H1 2023: \$691.0 million), reflecting working capital (favourable movements of \$84.2 million in H1 2024 compared to adverse movements of \$184.2 million in H1 2023) and lower production and pricing. The reduction in adjusted EBITDAX noted above was partly offset by the working capital movements and lower corporation tax payments.

Investing cash flows

Cash flow used in investing activities amounted to \$229.4 million (H1 2023: \$221.6 million), reflecting capital expenditure of \$210.3 million (H1 2023: \$218.0 million) driven mainly by Captain EOR Phase II and Rosebank.

Financing cash flows

Cash outflow from financing activities of \$196.2 million (H1 2023: \$548.1 million) with interest costs and lease payments of \$62.6 million (H1 2023: \$65.1 million), a net repayment of principal debt of \$nil (H1 2023: net repayment of \$350.0 million) and the payment of the third interim dividend for 2023 of \$133.6 million (H1 2023: first interim dividend for 2023 of \$133.0 million).

Cash balances were \$287.7 million (H1 2023: \$176.3 million) at the end of H1 2024 and available liquidity was \$1,028.0 million (H1 2023: \$791.3 million).

Going concern

Based on their assessment of the Group's financial position over the period to 30 September 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 condensed consolidated financial statements. Further details are set out in note 3.

Prior period adjustments

Deferred tax assets and retained earnings have been restated to increase the values of both by \$76.9 million at 31 December 2023, in order to correct the deferred EPL tax treatment of impairment charges recorded in Q4 of 2023. The unaudited restated consolidated statement of profit or loss for the year to 31 December 2023 is presented on page 23 and further details are set out in note 2.

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 30 June 2024, the following hedges were in place:

	H2 2024	2025	2026
Oil
Volume hedged (mmboe)	3.7	2.6	–
Weighted average floor hedged price (\$/bbl)	78	78	–
Gas
Volume hedged (mmboe)	1.7	2.7	0.1
Weighted average floor hedged price (p/therm)	109	88	92

Principal risks and uncertainties

The Group faces various risks that could result in events or circumstances that might threaten our business model, future performance, liquidity, solvency or reputation. Not all of these risks are completely within the control of the business and the Group may be affected by risks that have yet to manifest themselves or are not reasonably foreseeable at the present time.

For those identified risks, the Group has mitigation strategies to minimise the likelihood of the risk and reduce the impact as far as is practicable. Depending on the nature of the risk, the Group may elect to take or tolerate risk, treat risk with mitigating actions, transfer risk to third parties, or eliminate risk by ceasing certain operations or activities.

The Directors have reviewed the principal risks and uncertainties facing the Group and have concluded that those facing the Group for the remaining six months of the current financial year are unchanged from the risks set out in the 2023 Annual Report and Accounts, with the exception of the addition of a new risk in relation to the integration of the Eni UK businesses. In reaching this conclusion, the Directors considered changes in the internal and external environment during the intervening period which could threaten the Group's business model, future performance, liquidity, solvency or reputation.

The principal risks and uncertainties are as follows:

Major HSE incident
Cyber security breach
Access to capital
Capital project execution
Commodity price volatility
Production delivery issues
Energy transition and Net Zero delivery
Workforce recruitment and retention
Supply chain capacity and capability
Governmental regulatory, political and fiscal
Major compliance breach
Integration of the Eni UK businesses

The Group continues to assess the potential impact of the new Labour government, in particular in terms of fiscal policy. Details of taxation changes announced to date are set out in note 12.

In relation to the recent Finch case where the UK Supreme Court ruled that Environmental Impact Assessments should also take account of 'downstream' emissions resulting from a project, the Directors do not consider this to constitute a separate risk and, at this relatively early stage in proceedings, are assessing what impact this case might have on the existing principal risks.

Details of these principal risks and how they are being managed, other than the additional business integration risk, are set out on pages 84 to 90 of the 2023 Annual Report and Accounts.

Statement of Directors' responsibilities

The Directors confirm that, to the best of their knowledge:

Condensed consolidated financial statements have been prepared in accordance with IAS 34 Interim Financial Reporting as contained within UK adopted IFRS;
Half-yearly results statement includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and
Half-yearly results statement includes a fair review of the information required by DTR 4.2.8R (disclosure of material related parties' transactions and changes therein).

By order of the Board,

Iain C S Lewis Director 21 August 2024

Independent review report to Ithaca Energy plc

Conclusion

We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2024 which comprises:

The condensed consolidated statement of profit or loss;
The condensed consolidated statement of comprehensive income;
The condensed consolidated statement of financial position;
The condensed consolidated statement of changes in equity;
The condensed consolidated statement of cash flows; and
The related notes 1 to 19 to the condensed consolidated financial statements.

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2024 is not prepared, in all material respects, in accordance with United Kingdom adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Basis for Conclusion

We conducted our review in accordance with International Standard on Review Engagements (UK) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council for use in the United Kingdom (ISRE (UK) 2410). A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

As disclosed in note 2, the annual financial statements of the group are prepared in accordance with United Kingdom adopted international accounting standards. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with United Kingdom adopted International Accounting Standard 34 "Interim Financial Reporting".

Conclusion Relating to Going Concern

Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for Conclusion section of this report, nothing has come to our attention to suggest that the directors have inappropriately adopted the going concern basis of accounting or that the directors have identified material uncertainties relating to going concern that are not appropriately disclosed.

This Conclusion is based on the review procedures performed in accordance with ISRE (UK) 2410; however future events or conditions may cause the entity to cease to continue as a going concern.

Responsibilities of the directors

The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

In preparing the half-yearly financial report, the directors are responsible for assessing the company's ability to continue as a going concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the company or to cease operations, or have no realistic alternative but to do so.

Auditor's Responsibilities for the review of the financial information

In reviewing the half-yearly financial report, we are responsible for expressing to the company a conclusion on the condensed set of financial statements in the half-yearly financial report. Our Conclusion, including our Conclusion Relating to Going Concern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.

Use of our report

This report is made solely to the company in accordance with ISRE (UK) 2410. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.

Deloitte LLP Statutory Auditor London, United Kingdom 21 August 2024

Unaudited condensed consolidated statement of profit or loss For the three and six months ended 30 June and the year ended 31 December 2023

		Three months ended 30 June		Six months ended 30 June		Year ended 31 December
	Note	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000	2023 Restated1 \$'000
Revenue	4	361,586	603,793	841,851	1,248,109	2,319,811
Cost of sales	5	(262,282)	(327,480)	(541,371)	(630,391)	(1,317,010)
Gross profit		99,304	276,313	300,480	617,718	1,002,801
Impairment charges on development and production assets	11	(30,913)	(328,426)	(35,487)	(328,426)	(557,936)
Exploration and evaluation expenses	10	(1,467)	–	(1,467)	(1,334)	(13,634)
Administrative expenses		(12,063)	(5,057)	(19,990)	(14,935)	(34,259)
Other gains/(losses)	6	37,465	(18,752)	26,179	72,239	89,091
Profit/(loss) from operations before tax, finance income and finance costs		92,326	(75,922)	269,715	345,262	486,063
Finance income	7	2,480	899	4,518	2,139	5,688
Finance costs	7	(41,889)	(47,838)	(84,802)	(98,660)	(189,724)
Profit/(loss) before tax		52,917	(122,861)	189,431	248,741	302,027
Income tax	12	10,061	124,006	(83,712)	(89,155)	(9,473)
Profit for the period		62,978	1,145	105,719	159,586	292,554
		Three months ended 30 June		Six months ended 30 June		Year ended 31 December
Earnings per share (EPS)	Note	2024 Cents	2023 Cents	2024 Cents	2023 Cents	2023 Restated1 Cents
Basic	8	6.3	0.1	10.5	15.9	29.1
Diluted	8	6.2	0.1	10.4	15.7	28.7

The income tax charge, the profit for the year and EPS for the year ended 31 December 2023 have been restated. Further details are set out in note 2.

The results above are entirely derived from continuing operations.

The accompanying notes on pages 30 to 49 are an integral part of the condensed consolidated financial statements.

Unaudited condensed consolidated statement of comprehensive income

For the three and six months ended 30 June and the year ended 31 December 2023

		Three months ended 30 June		Six months ended 30 June		Year ended 31 December
	Note	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000	2023 Restated1 \$'000
Profit for the period		62,978	1,145	105,719	159,586	292,554
Items that may be reclassified to profit and loss
Fair value (loss)/gain on cash flow hedges	16	(47,235)	(13,242)	(113,696)	80,546	92,484
Fair value (loss)/gain on cost of hedging	16	(4,274)	12,959	(15,237)	2,632	3,116
Deferred tax credit/(charge) on cash flow hedges and cost of hedging	12	32,687	135	90,755	(62,292)	(71,700)
Other comprehensive (expense)/income		(18,822)	(148)	(38,178)	20,886	23,900
Total comprehensive income for the period		44,156	997	67,541	180,472	316,454

The profit for the year to 31 December 2023 has been restated. Further details are set out in note 2.

The accompanying notes on pages 30 to 49 are an integral part of the financial statements.

Unaudited condensed consolidated statement of financial position As at 30 June 2024 and 31 December 2023

	2024	2023 Restated1
Note	\$'000	\$'000

Unaudited condensed consolidated statement of financial position continued As at 30 June 2024 and 31 December 2023

	Note	2024 \$'000	2023 Restated1 \$'000
Non-current liabilities
Borrowings	13	(789,223)	(718,238)
Decommissioning liabilities	14	(1,813,283)	(1,752,652)
Lease liabilities		(14,988)	(660)
Contingent and deferred consideration	15	(224,464)	(258,700)
Derivative financial instruments	17	(4,884)	–
		(2,846,842)	(2,730,250)
Total liabilities		(3,867,707)	(3,802,187)
Net assets		2,458,162	2,521,345
Shareholders' equity
Share capital		11,540	11,540
Share premium		308,845	308,845
Capital contribution reserve		181,945	181,945
Own shares		(10,626)	(12,412)
Share-based payment reserve		16,614	15,494
Cash flow hedge reserve		7,192	39,818
Cost of hedging reserve		(1,484)	4,068
Retained earnings		1,944,136	1,972,047
Total equity		2,458,162	2,521,345

Deferred tax assets and retained earnings have been restated at 31 December 2023. Further details are set out in note 2.

The accompanying notes on pages 30 to 49 are an integral part of the condensed consolidated financial statements.

Approved on behalf of the Board on 21 August 2024:

Iain C S Lewis Director

Unaudited condensed consolidated statement of changes in equity

For the six months ended 30 June

	Share capital \$'000	Share premium \$'000	Capital contribution reserve \$'000	Own shares \$'000	Share-based payment reserve \$'000	Cash flow hedge reserve \$'000	Cost of hedging reserve \$'000	Retained earnings \$'000	Total \$'000
Balance at 1 January 2023	11,445	293,712	181,945	–	4,920	16,710	3,275	1,945,465	2,457,472
Dividends paid	–	–	–	–	–	–	–	(133,005)	(133,005)
Share-based payments	–	–	–	–	7,161	–	–	–	7,161
Comprehensive income for the period:
Profit for the period	–	–	–	–	–	–	–	159,586	159,586
Other comprehensive income	–	–	–	–	–	20,228	658	–	20,886
Total comprehensive income for the period	–	–	–	–	–	20,228	658	159,586	180,472
Balance at 30 June 2023	11,445	293,712	181,945	–	12,081	36,938	3,933	1,972,046	2,512,100
Balance at 31 December 2023 as previously stated	11,540	308,845	181,945	(12,412)	15,494	39,818	4,068	1,895,128	2,444,426
Prior period adjustment (note 2)	–	–	–	–	–	–	–	76,919	76,919
Balance at 31 December 2023 and 1 January 2024 as restated	11,540	308,845	181,945	(12,412)	15,494	39,818	4,068	1,972,047	2,521,345
Dividends paid	–	–	–	–	–	–	–	(133,630)	(133,630)
Share-based payments	–	–	–	1,786	1,120	–	–	–	2,906
Comprehensive income/(expense) for the period:
Profit for the period	–	–	–	–	–	–	–	105,719	105,719
Other comprehensive expense	–	–	–	–	–	(32,626)	(5,552)	–	(38,178)
Total comprehensive income/(expense) for the period	–	–	–	–	–	(32,626)	(5,552)	105,719	67,541
Balance at 30 June 2024	11,540	308,845	181,945	(10,626)	16,614	7,192	(1,484)	1,944,136	2,458,162

The accompanying notes on pages 30 to 49 are an integral part of the condensed consolidated financial statements.

Unaudited condensed consolidated statement of cash flows

For the three and six months ended 30 June

		Three months ended 30 June		Six months ended 30 June
	Note	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Cash provided by/(used in) operating activities:
Profit/(loss) before tax		52,917	(122,861)	189,431	248,741
Adjustments for:
Depletion, depreciation and amortisation	11	107,866	195,386	252,876	384,120
Impairment of capitalised exploration and evaluation expenditure	10	1,467	–	1,467	1,334
Impairment of property, plant and equipment		30,913	328,426	35,487	328,426
Changes in fair value of contingent and deferred consideration	15	(31,109)	26,103	(27,789)	1,725
Loan fee amortisation		1,127	1,103	2,254	2,254
Fair value losses/(gains) on derivatives	16	(9,153)	(16,990)	(828)	(38,660)
Prepaid put premiums		–	1,142	–	1,142
Accretion	7	18,813	19,763	37,464	37,912
Finance costs		21,949	26,072	45,085	56,355
Finance income	7	(2,481)	(899)	(4,519)	(2,139)
Unrealised foreign exchange on cash and cash equivalents		(849)	(1,582)	(308)	(1,219)
Share-based payment expenses		1,275	4,304	2,906	8,562
Decommissioning expenditure		(19,555)	(31,314)	(31,212)	(56,771)
Operating cash flows before movements in working capital		173,180	428,653	502,314	971,782
Decrease in inventories		20,276	5,909	9,891	2,818
Decrease in trade and other receivables		51,906	13,319	82,430	28,398
Decrease in trade and other payables		(17,986)	(109,161)	(8,122)	(215,466)
Operating cash flows		227,376	338,720	586,513	787,532
Corporation tax paid		–	–	(24,970)	(98,719)
Settlements of foreign exchange and commodity derivative financial instruments1		16,176	–	(6,254)	–
Finance income	7	2,481	899	4,519	2,139
Net cash from operating activities		246,033	339,619	559,808	690,952

The settlements of foreign exchange and commodity derivative financial instruments in the three months and six months ended 30 June 2023 were included in movements in receivables and payables (see note 16 for further details).

Unaudited condensed consolidated statement of cash flows continued

For the three and six months ended 30 June

	Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Cash used in investing activities:
Capital expenditure	(97,220)	(120,322)	(210,336)	(218,002)
Contingent consideration payment	(2,370)	(1,220)	(19,069)	(3,568)
Net cash used in investing activities	(99,590)	(121,542)	(229,405)	(221,570)
Cash used in financing activities:
Dividends paid	(133,630)	–	(133,630)	(133,005)
Payments for lease liabilities (principal)	(6,511)	(11,107)	(20,107)	(15,912)
Repayment of RBL loan	–	(100,000)	–	(350,000)
Bank interest and charges	(4,699)	(7,634)	(41,852)	(49,182)
Interest rate swaps	–	–	(638)	–
Net cash used in financing activities	(144,840)	(118,741)	(196,227)	(548,099)
Currency translation differences relating to cash	849	1,582	308	1,219
Increase/(reduction) in cash and cash equivalents	2,452	100,918	134,484	(77,498)
Cash and cash equivalents, beginning of period	285,247	75,406	153,215	253,822
Cash and cash equivalents, end of period	287,699	176,324	287,699	176,324

The accompanying notes on pages 30 to 49 are an integral part of the condensed 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.

2. Basis of preparation

The condensed consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standard 34 Interim Financial Reporting.

The condensed consolidated financial statements for the six months ended 30 June 2024 do not include all the information required for a full annual report and do not constitute statutory accounts within the meaning of section 434(3) of the Companies Act 2006. The condensed consolidated financial statements for the six month period ended 30 June 2024 are not audited but have been reviewed by the auditor whose review report is set out on page 22. The accounting policies adopted in the preparation of the H1 2024 condensed consolidated financial statements are consistent with those adopted and disclosed in the Group's 2023 Annual Report and Accounts. Comparative information for the year ended 31 December 2023 has been taken from the statutory accounts for that year, a copy of which has been delivered to the Registrar of Companies, with the exception of the prior period adjustments set out below. The auditor's report on those accounts was not qualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis and did not contain any statements under section 498(2) or (3) of the Companies Act 2006. A number of amendments to existing standards and interpretations were effective from 1 January 2024 but there was no impact on the H1 2024 condensed consolidated financial statements. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

The condensed 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 (\$'000), except when otherwise indicated.

In terms of segmental reporting, the Group currently operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area, being presently 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 presented to the Board and to the 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 uniform, and such operations existing in a single geographical area which is overseen by the same management and covered by the same regulations.

These H1 2024 condensed consolidated financial statements are to be read in conjunction with Ithaca Energy's Annual Report and Accounts for the year ended 31 December 2023, which contains additional accounting policy disclosures.

Prior period adjustments

During the preparation of the Q1 2024 condensed consolidated financial statements, management identified an incorrect calculation in the 2023 deferred EPL tax charge related to the impairment charge of \$229.5 million recorded in Q4 of 2023. As a result of this incorrect calculation, the tax charge and the profit for the year to 31 December 2023 were overstated and understated respectively by \$76.9 million, and the net deferred tax asset and retained earnings were both understated by \$76.9 million at 31 December 2023.

Details of amounts as previously stated, prior period adjustments and amounts as restated were:

Statement of financial position as at 31 December 2023:	As previously stated	Prior period adjustment	As restated
Deferred tax assets (\$'000)	627,738	76,919	704,657
Retained earnings (\$'000)	1,895,128	76,919	1,972,047
Net assets (\$'000)	2,444,426	76,919	2,521,345
Statement of profit or loss for the year to 31 December 2023:	As previously stated	Prior period adjustment	As restated
Income tax charge (\$'000)	(86,392)	76,919	(9,473)
Profit for the year (\$'000)	215,635	76,919	292,554
Basic EPS (cents)	21.4	7.7	29.1
Diluted EPS (cents)	21.2	7.5	28.7

3. Accounting policies

Basis of measurement

The condensed 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 IFRS) to fair value, including derivative instruments. Historical cost is generally based on the fair value consideration given in exchange for the assets or liabilities.

Going concern

Management closely monitors 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 condensed consolidated 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;
Reserves Based Lending (RBL) liquidity headroom of \$659 million (undrawn and available), plus \$262 million of cash as at the end of July 2024; and
Resilient operational performance and well-diversified portfolio.

Cash flow forecast – base case assumptions:		H2 2024	Q1 to Q3 2025
Average oil price	\$/bbl	84	80
Average gas price	p/th	91	95
Average hedged oil price (including floor price for zero cost collars)	\$/bbl	81	80
Average hedged gas price (including floor price for zero cost collars)	p/th	97	94

Owing to the ongoing fluctuations in commodity demand and price volatility, management prepared sensitivity analysis 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 meet its liabilities as they fell due. The mitigation strategies within the control of management include the reduction in uncommitted capital expenditure, variable operating cost savings in the low production scenario and the cancellation or deferral of future dividends. In addition, there is also the 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 to continue trading, throughout the period to 30 September 2025.

On 23 April 2024, the Group announced that it had entered into a combination agreement with Eni UK in relation to substantially all of the upstream assets of Eni in the UK in exchange for the issue of ordinary shares in Ithaca Energy plc. The Eni UK portfolio includes interests in 11 producing fields. The Eni UK portfolio is cash-generative and also adds significant debt capacity to the Group's existing RBL facility. As such, the Directors consider the business combination agreement as accretive to cash flows and supportive in the Directors' going concern assessment.

Based on their assessment of the Group's financial position in the period to 30 September 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 condensed consolidated financial statements.

Use of judgements and estimates

In preparing these H1 2024 condensed consolidated financial statements, management has made judgements and estimates that affect the application of accounting policies and the reported amounts of assets and liabilities and income and expenses. Actual results may differ from these estimates.

The significant judgements made by management in applying the Group's accounting policies, and the key sources of estimation uncertainty are the same as those described on pages 171 to 173 of the Group's 2023 Annual Report and Accounts. Judgements and estimates made in assessing the impact of climate change and the energy transition have not changed for the H1 2024 consolidated condensed financial statements. Details of these are set out on pages 163 and 164 of the 2023 Annual Report and Accounts.

3. Accounting policies continued

The only critical accounting judgement applied in the preparation of the H1 2024 condensed consolidated financial statements is whether or not there has been an indication of impairment in respect of the Cambo field. Management has reviewed the carrying value of the Cambo field of \$391 million (31 December 2023: \$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 assessing the announcements made to date by the new Labour Government and will continue to engage with governmental bodies in order to regain a more equitable fiscal landscape for the UK oil and gas industry.

4. Revenue

	Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Oil sales	243,691	336,821	546,453	650,176
Gas sales	81,486	152,735	170,414	379,883
Condensate sales	8,243	12,837	18,654	26,434
Other income	4,231	7,821	9,700	17,388
Realised losses on oil derivative contracts	(4,263)	(5,740)	(6,694)	(12,440)
Put premiums on oil derivative instruments	(266)	(2,730)	(648)	(6,330)
Realised gains on gas derivative contracts	29,616	103,191	105,124	194,140
Put premiums on gas derivative instruments	(1,152)	(1,142)	(1,152)	(1,142)
	361,586	603,793	841,851	1,248,109

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 period.

Revenue from two customers (30 June 2023: two customers) exceeds 10% of the Group's consolidated revenue arising from hydrocarbon sales for the six months ended 30 June 2024, representing \$601.2 million and \$85.4 million respectively (six months ended 30 June 2023: \$689.6 million and \$216.1 million respectively).

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

5. Cost of sales

	Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Movement in oil and gas inventory	(3,687)	18,709	(5,136)	57,546
Operating costs of hydrocarbon activities	(150,280)	(149,531)	(282,211)	(300,652)
Royalties	(449)	(1,273)	(1,148)	(3,165)
Depreciation on right-of-use assets (note 11)	(6,012)	(10,534)	(18,707)	(20,953)
Depletion, depreciation and amortisation (note 11)	(101,854)	(184,851)	(234,169)	(363,167)
	(262,282)	(327,480)	(541,371)	(630,391)

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

6. Other gains and losses

		Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
(Losses)/gains on financial instruments	6,603	13,521	(1,654)	27,485
Fair value gains/(losses) on contingent consideration	30,705	(26,103)	27,384	(1,725)
Net foreign exchange	157	(5,476)	449	(3,589)
Settlement of historic claim relating to an acquisition	–	(694)	–	50,068
	37,465	(18,752)	26,179	72,239

7. Finance costs and finance income

		Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Bank interest and charges	(5,763)	(12,165)	(12,714)	(28,964)
Senior notes interest	(14,024)	(14,024)	(27,817)	(27,895)
Loan fee amortisation	(1,127)	(1,103)	(2,254)	(2,254)
Interest on lease liabilities	(248)	(783)	(693)	(1,635)
Accretion	(18,813)	(19,763)	(37,464)	(37,912)
Other	(1,914)	-	(3,860)	-
Total finance costs	(41,889)	(47,838)	(84,802)	(98,660)

Interest income	2,480	899	4,518	2,139

During the six months to 30 June 2024, \$0.5 million of interest was capitalised into qualifying assets (six months to 30 June 2023: \$nil).

8. 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 period. Basic and diluted earnings per share are calculated as follows:

		Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Earnings for the period
Earnings for the purpose of basic and diluted earnings per share	62,978	1,145	105,719	159,586
Number of shares (million)
Weighted average number of ordinary shares for the purpose of basic earnings per share	1,006.6	1,006.6	1,006.6	1,006.6
Dilutive potential ordinary shares	9.2	6.9	9.2	6.9
Weighted average number of ordinary shares for the purpose of diluted earnings per share	1,015.8	1,013.5	1,015.8	1,013.5
Earnings per share (cents)
Basic	6.3	0.1	10.5	15.9
Diluted	6.2	0.1	10.4	15.7
9. Trade and other receivables
			30 June	31 December

Current	2024 \$'000	2023 \$'000
Trade receivables	7,331	19,968
Other receivables	19,392	24,369
Joint operations receivables	97,367	91,960
Accrued income	142,897	197,993
	266,987	334,290

Materially no trade and other receivables, including receivables from joint operations, are overdue by more than 90 days. The credit risk associated with trade receivables, accrued income, joint operations receivables and other receivables is considered to be insignificant. No Expected Credit Losses have been recognised in the current or prior year.

The decommissioning reimbursements, as set out on page 25, represent the equal and opposite of decommissioning liabilities, 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 this acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL (now Ithaca Oil and Gas Limited) 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.

10. Exploration and evaluation assets

	\$'000
At 1 January 2023	775,773
Additions	165,516
Transfers to development and production assets (note 11)	(379,301)
Write-offs/relinquishments	(13,634)
At 31 December 2023 and 1 January 2024	548,354
Additions	8,288
Change in decommissioning estimates	2,912
Write-offs/relinquishments	(1,467)
At 30 June 2024	558,087

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 \$1.5 million being expensed in the six months to 30 June 2024 (six months to 30 June 2023: \$1.3 million).

The principal component of exploration and evaluation assets at 30 June 2024 is the Cambo field with a carrying value of \$391 million (31 December 2023: \$391 million) which formed part of the Siccar Point Energy acquisition.

11. Property, plant and equipment

	Right-of-use operating assets \$'000	Development and production assets \$'000	Other fixed assets \$'000	Total \$'000
Cost
At 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 10)	30,774	348,527	–	379,301
Change in decommissioning estimates	–	157,224	–	157,224
At 31 December 2023 and 1 January 2024	156,169	7,976,764	47,640	8,180,573
Additions	75,129	212,519	83	287,731
Change in decommissioning estimates	–	48,845	–	48,845
At 30 June 2024	231,298	8,238,128	47,723	8,517,149
Depletion, depreciation, amortisation and impairment
At 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 charges	–	(559,472)	–	(559,472)
At 31 December 2023 and 1 January 2024	(85,515)	(4,808,701)	(28,151)	(4,922,367)
Depletion, depreciation and amortisation charge for the period	(18,707)	(231,520)	(2,649)	(252,876)
Impairment charges	–	(35,487)	–	(35,487)
At 30 June 2024	(104,222)	(5,075,708)	(30,800)	(5,210,730)
Net book value at 31 December 2023	70,654	3,168,063	19,489	3,258,206
Net book value at 30 June 2024	127,076	3,162,420	16,923	3,306,419

Impairment charges on development and production assets of \$35.5 million principally reflects decommissioning revisions on assets which have either ceased production or have been fully written down, mainly in relation to Alba. The impairment charge in the year to 31 December 2023 mainly comprised an impairment of development and production assets relating to the Greater Stella Area field as a result of lower future gas prices than previously forecast and a reduction in planned activity as a direct result of the EPL, and an impairment charge on Alba due to a reduction in estimated future production.

Additions to right-of-use assets in the six months to 30 June 2024 and 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.

Capital commitments at 30 June 2024 amounted to \$369.2 million (31 December 2023: \$507.0 million) and related principally to Rosebank and Captain at both dates.

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

12. Taxation

		Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Current tax
Current corporation tax credit/(charge)	(539)	(21,382)	2,991	(31,695)
True-up in respect of prior years	84,911	–	76,334	–
Current EPL tax charge	(14,644)	(96,543)	(72,790)	(223,051)
Total current tax credit/(charge)	69,728	(117,925)	6,535	(254,746)
Deferred tax
True-up in respect of prior years	(59,165)	371	(59,164)	(16,357)
Group tax (charge)/credit in the condensed consolidated statement of profit or loss	(13,034)	242,735	(43,616)	183,123
Group tax credit/(charge) in the condensed consolidated statement of other comprehensive income	32,687	135	90,755	(62,292)
Total deferred tax (charge)/credit	(39,512)	243,241	(12,025)	104,474
Deferred PRT credit/(charge) in the condensed consolidated statement of profit or loss	12,532	(1,175)	12,533	(1,175)
Total tax (charge)/credit through the condensed consolidated statement of profit or loss	10,061	124,006	(83,712)	(89,155)

12. 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:

	Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Accounting profit/(loss) before tax	52,917	(122,861)	189,431	248,741
At tax rate of 40% (2023: 40%)	(21,167)	49,144	(75,773)	(99,497)
Non-deductible (expense)/income	5,681	(24,158)	(5,013)	(6,085)
Financing costs not allowed for SCT	(216)	(133)	(455)	(530)
Ring Fence Expenditure Supplement	4,322	25,727	8,768	53,076
Deferred tax effect of investment allowance	3,613	10,859	(144)	18,886
True-up in respect of prior years	25,746	371	17,170	(16,357)
Deferred tax on EPL	3,820	160,887	42,879	189,389
Current tax on EPL	(14,644)	(96,543)	(72,790)	(223,051)
Net deferred tax PRT	7,520	(705)	7,520	(705)
Share schemes	(2,122)	(1,059)	(2,122)	(1,059)
Unrecognised tax losses	(2,492)	(384)	(3,752)	(3,222)
Total tax (charge)/credit recorded in the condensed consolidated statement of profit or loss	10,061	124,006	(83,712)	(89,155)

The Company is UK tax resident. The effective rate of tax applicable for UK ring fence oil and gas activities in both 2024 and 2023, was 40% (excluding the Energy Profits Levy of 35%) 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. 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 Energy Profits Levy was enacted on 14 July 2022 with further changes announced on 17 November 2022 such that the Levy was increased to 35% from 1 January 2023 until 31 March 2028 increasing the effective UK ring fence oil and gas tax rate to 75% and resulting in an additional current and deferred tax charge in the period. On 6 March 2024, it was announced that EPL will be extended by 1 year to 31 March 2029 and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024. These changes had not been substantively enacted at 30 June 2024 and is therefore not reflected in the results for the period.

Deferred tax at 30 June 2024 and 31 December 2023 relates to the following:

	30 June 2024 \$'000	31 December 2023 Restated1 \$'000
Deferred corporation tax liability	(1,735,190)	(1,868,022)
Deferred corporation tax asset	2,338,232	2,480,921
Deferred PRT asset	104,293	91,758
Net deferred tax asset	707,335	704,657

See note 2.

12. Taxation continued

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.

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

		31 December
	30 June	2023
	2024	Restated1
	\$'000	\$'000
At beginning of period	704,658	392,456
Profit or loss (charge)/credit	(90,248)	380,687
Other comprehensive income credit/(charge)	90,756	(71,700)
Deferred tax on decommissioning reimbursements	2,169	3,214
At end of period	707,335	704,657

See note 2.

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

		Six months ended 30 June
	2024 \$'000	2023 \$'000
Accelerated capital allowances	41,482	327,032
Tax losses	(166,056)	(146,427)
Decommissioning provision	23,206	30,783
Deferred PRT	(5,013)	470
Hedging	95,930	(86,672)
Share schemes	(2,007)	3,374
Investment allowances	433	(24,086)
	(12,025)	104,474

12. Taxation continued

Origination and reversal of temporary differences	(101,744)	(28,015)	441,281	311,522
At 31 December 2023 as previously stated	(107,701)	(36,703)	(1,800,537)	(1,944,941)
Prior period adjustment (note 2) At 31 December 2023 and 1 January 2024 as restated	– (107,701)	– (36,703)	76,919 (1,723,618)	76,919 (1,868,022)
True-up in respect of prior years	–	–	16,629	16,629
Origination and reversal of temporary differences	95,930	(5,013)	25,286	116,203
At 30 June 2024	(11,771)	(41,716)	(1,681,703)	(1,735,190)

		Decommissioning
Gross deferred corporation tax assets	Share schemes \$'000	provision \$'000	Tax losses \$'000	Hedges \$'000	Total \$'000
At 1 January 2023	–	666,052	1,972,174	(8,678)	2,629,548
Reclassification to deferred corporation tax liabilities	–	–	–	8,678	8,678
True-up in respect of prior years	177	–	(4,989)	–	(4,812)
Origination and reversal of temporary differences	3,802	55,654	(211,949)	–	(152,493)
At 31 December 2023 and 1 January 2024	3,979	721,706	1,755,236	–	2,480,921
True-up in respect of prior years	–	–	(75,794)	–	(75,794)
Origination and reversal of temporary differences	(2,007)	25,375	(90,263)	–	(66,895)
At 30 June 2024	1,972	747,081	1,589,179	–	2,338,232

Deferred PRT asset	Total \$'000
At 1 January 2023	21,721
Origination and reversal of temporary differences	70,037
At 31 December 2023 and 1 January 2024	91,758
Origination and reversal of temporary differences	12,535
At 30 June 2024	104,293

12. Taxation continued

The carrying value of the net deferred tax asset (DTA) and the deferred PRT asset at 30 June 2024 of \$603 million and \$104 million respectively (31 December 2023: \$613 million and \$92 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 is now largely complete. 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 and on 29 July 2024, it was announced that there would be a further extension to March 2030 and that the rate would increase from 35% to 38% from 1 November 2024. If these changes had been enacted at the balance sheet date, it is estimated that this would have reduced the net deferred tax asset by \$278 million. The Government also announced that they will reduce the extent to which capital allowance claims (including First Year Allowances) can be taken into account for calculating levy profits, however the manner and extent of this is unknown. Any adjustments to reduce capital relief will reduce the net deferred tax asset further.

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 adoption of this has not had 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.

13. Borrowings	30 June 2024	31 December 2023
	\$'000	\$'000
Current
Accrued interest costs on borrowings	(30,103)	(29,913)
Non-current
RBL facility	–	–
Senior unsecured notes	(625,000)	(625,000)
bp unsecured loan	(100,000)	(100,000)
Optional project capital expenditure facility	(68,731)	–
Unamortised long-term bank fees	3,037	4,555
Unamortised long-term senior notes fees	1,471	2,207
Total debt	(789,223)	(718,238)

Adjusted net debt, which does not include lease liabilities, is set out in Non-GAAP measures on page 51.

Details of covenants under the RBL facility and details of the new optional project capital expenditure facility are set out in note 20 to the 2023 Annual Report and Accounts. The Group was in compliance with all financial covenants of the RBL facility in all periods presented.

14. Decommissioning liabilities

	30 June	31 December
	2024 \$'000	2023 \$'000
Balance at beginning of period	(1,859,678)	(1,720,540)
Accretion	(42,885)	(74,621)
Additions and revisions to estimates	(51,757)	(160,069)
Decommissioning provision utilised	31,212	95,552
Balance at end of period	(1,923,108)	(1,859,678)
Current
Balance at beginning of period	(107,026)	(146,829)
Balance at end of period	(109,825)	(107,026)
Non-current
Balance at beginning of period	(1,752,652)	(1,573,711)
Balance at end of period	(1,813,283)	(1,752,652)

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. Whereas previously the Group used a uniform nominal discount rate over all future years, it has now revised its methodology to use a short-to-medium-term nominal discount rate and a long-term nominal discount rate. The Group uses a nominal discount rate of 4.21% for the first five years and 4.70% thereafter (31 December 2023: 4.60% for all years) and an inflation rate of 2.0% (31 December 2023: 2.0%) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. Revisions to estimates in the six months to 30 June 2024 and the year ended 31 December 2023 were due to changes in both cost estimates and discount rate assumptions.

The estimated H2 2024 and H1 2025 decommissioning spend of \$110 million (31 December 2023: estimated 2024 decommissioning spend of \$107 million) has been treated as a current liability as at 30 June 2024. The Group currently expects to incur decommissioning costs over the next 40 years. The current liability at 30 June 2024 of \$110 million (31 December 2023: \$107 million) includes \$45 million (31 December 2023: \$30 million) of decommissioning reimbursements which are shown separately as a current asset in the consolidated statement of financial position.

A reduction or an increase in the nominal discount rate used of 1% would increase or decrease the decommissioning liabilities by approximately \$211 million and \$179 million respectively (31 December 2023: \$223 million and \$188 million respectively).

15. Contingent and deferred consideration

	30 June 2024	31 December 2023
Current	\$'000	\$'000
Contingent consideration	(89,047)	(101,669)
Non-current	30 June 2024 \$'000	31 December 2023 \$'000
Contingent consideration	(157,009)	(194,721)
Marubeni deferred consideration	(67,455)	(63,979)
	(224,464)	(258,700)
	30 June 2024 \$'000	31 December 2023 \$'000
Cash flows relating to contingent and deferred considerations	(19,069)	(13,567)
Movement in contingent consideration is as follows:
	30 June 2024 \$'000	31 December 2023 \$'000
At start of period	(296,390)	(258,896)
Additions	–	(26,872)
Payments made	19,069	7,200
Accretion	(3,169)	(9,814)
Changes in fair value	34,434	(8,008)
At end of period	(246,056)	(296,390)

15. Contingent and deferred consideration continued

Movement in deferred consideration consideration is as follows:

	30 June 2024 \$'000	31 December 2023 \$'000
At 1 January	(63,979)	(67,904)
Payments made	–	6,367
Accretion	(3,476)	(2,442)
At end of period	(67,455)	(63,979)

Cash outflows in the six months to 30 June 2024 of \$19.1 million are in relation to the quarterly payments in consideration to the Marubeni and Siccar oil price triggers and payments in respect of the Rosebank FDP.

Details of movements in contingent and deferred consideration for the year to 31 December 2023 and sensitivities thereon are set out in notes 25 and 29 of the Group's 2023 Annual Report and Accounts. Changes in fair value in the six months ended 30 June 2024 relate to managements' reassessment of the likelihood of certain future events occurring.

16. 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 condensed 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 material assets of the Group are pledged as security against borrowings.

16. Financial instruments continued

The accounting classification of each category of financial instruments and their carrying amounts as at 30 June 2024 are set out below:

		Mandatorily	Derivatives
	Measured at	measured at fair value through	designated in hedge	Total carrying
	amortised cost \$'000	profit or loss \$'000	relationships \$'000	amount \$'000
Financial assets
Cash and cash equivalents	287,699	–	–	287,699
Trade and other receivables	261,349	–	–	261,349
Derivative financial instruments	–	–	52,785	52,785
Financial liabilities
Borrowings	(819,326)	–	–	(819,326)
Trade and other payables	(334,063)	–	–	(334,063)
Lease liabilities	(24,597)	–	–	(24,597)
Contingent and deferred consideration	(67,455)	(246,056)	–	(313,511)
Derivative financial instruments	–	(6,475)	(23,924)	(30,399)
				(920,063)

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 \$'000	Mandatorily measured at fair value through profit or loss \$'000	Derivatives designated in hedge relationships \$'000	Total carrying amount \$'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 liabilities	(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)

16. Financial instruments continued

The following table presents the Group's material financial instruments measured at fair value for each hierarchy level as at 30 June 2024:

	Level 1 \$'000	Level 2 \$'000	Level 3 \$'000	Total fair value \$'000
Contingent consideration	–	(21,664)	(224,392)	(246,056)
Derivative financial instrument asset	–	52,785	–	52,785
Derivative financial instrument liability	–	(30,399)	–	(30,399)

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 \$'000	Level 2 \$'000	Level 3 \$'000	Total fair value \$'000
Contingent consideration	–	(24,039)	(272,351)	(296,390)
Derivative financial instrument asset	–	157,307	–	157,307
Derivative financial instrument liability	–	(13,708)	–	(13,708)

Level 3 contingent consideration is valued on a discounted cash flow basis with the key inputs being commodity prices, the probability of certain future events occurring ("trigger events") and the discount rate.

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 \$20.7 million (31 December 2023: \$23.3 million). A 20% increase in the oil price would lead to an increase in contingent consideration of \$40.8 million (31 December 2023: \$41.0 million).

The forecast cash flows in the event of a trigger event occurring are discounted at a rate of 6.07% (31 December 2023: 4.6%).

The following table summarises the sensitivity of 20% change in probability of the trigger events 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	30 June 2024 \$'000	31 December 2023 \$'000
20% decrease in probability	90,844	97,119
20% increase in probability	(79,156)	(84,086)

A 1% increase in the discount rate would reduce the liability at 30 June 2024 by \$4.8 million (31 December 2023: \$5.3 million. A 1% decrease in the discount rate would increase the liability by the same amount at each date.

16. Financial instruments continued

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

	Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
Revaluation of forex forward contracts	8,272	3,540	(825)	5,000
Revaluation of interest rate swaps	–	(891)	(637)	(2,535)
Revaluation of commodity hedges	881	14,341	2,290	36,195
Total revaluation gain on financial instruments	9,153	16,990	828	38,660
Realised loss on forex forward contracts	(1,579)	(885)	(1,544)	(2,967)
Realised gain on interest rate swaps	–	2,324	638	3,850
Realised loss on commodity hedges	(971)	(4,908)	(1,574)	(12,058)
Total (loss)/gain on financial instruments	6,603	13,521	(1,654)	27,485

Cash flow hedge reserve

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

		Three months ended 30 June		Six months ended 30 June
Cash flow hedge reserve	2024 \$'000	2023 \$'000	2024 \$'000	2023 \$'000
At period start	23,203	40,325	39,818	16,710
Change in fair value of derivative instruments	(20,371)	84,210	(14,035)	262,021
Amounts recycled to revenue	(26,865)	(97,451)	(99,662)	(181,475)
Deferred tax on movement in period	31,225	9,854	81,071	(60,318)
Cash flow hedge reserve at 30 June	7,192	36,938	7,192	36,938

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:

Cost of hedging reserve	Three months ended 30 June		Six months ended 30 June
	2024 \$'000	2023 2024 \$'000 \$'000	2023 \$'000
At period start	1,327	694 4,068	3,275
Change in fair value of the intrinsic value of derivative instruments	(5,692)	9,087 (17,037)	(4,840)
Amounts recycled to revenue – oil put premiums	266	2,730 648	6,330
Amounts recycled to revenue – gas put premiums	1,152	1,142 1,152	1,142
Deferred tax on movement in period	1,462	(9,719) 9,684	(1,974)
Cost of hedging reserve at 30 June	(1,484)	3,933 (1,484)	3,933

17. Derivative financial instruments

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

	30 June 2024	31 December 2023
	\$'000	\$'000
Oil swaps – cash flow hedge	(3,925)	9,913
Oil collars – cash flow hedge	(3,121)	7,434
Gas swaps – cash flow hedge	14,144	47,232
Gas swaps – non-cash flow hedge	–	(2,290)
Gas collars – cash flow hedge	15,227	89,944
Interest rate swaps – non-cash flow hedge	–	637
FX forwards – non-cash flow hedge	(2,327)	(3,961)
FX forwards – cash flow hedge	(2,949)	–
FX collars – cash flow hedge	(1,356)	(3,335)
FX collars – non-cash flow hedge	–	(1,975)
Matured instruments not cash-settled – in-the-money	9,238	–
Matured instruments not cash-settled – out-of-the-money	(2,545)	–
	22,386	143,599

Accrued settlements for trades which have matured at the balance sheet date but not yet cash settled have been reclassed in the current year from other payables/other receivables (within trade and other payables and trade and other receivables respectively) to derivative financial instruments, to reflect the true asset and liability position relating to derivative financial instruments. The prior year equivalent of \$7.6 million payable and \$15.1 million receivable have not been adjusted for this change as it is not material and remains within other payables and other receivables as at 31 December 2023.

	30 June	31 December
	2024	2023
Maturity analysis of derivative financial instruments	\$'000	\$'000
Non-current assets	3,065	17,810
Current assets	49,720	139,497
Non-current liabilities	(4,884)	–
Current liabilities	(25,515)	(13,708)
	22,386	143,599

Judgements and estimates applied in the valuation of derivative instruments can be found in note 29 to the 2023 Annual Report and Accounts.

Derivative financial instruments that are with counterparties included within the RBL are subject to Master Netting Agreements.

18. Related party transactions

On 5 January 2024 Alan Bruce stepped down from his role as Chief Executive Officer and on 28 May 2024 Gilad Myerson stepped down from his role as Executive Chairman. Full details of the section 430 (2B) of the Companies Act 2006 disclosures in respect of Mr Bruce and Mr Myerson are available on the Group's website.

19. Subsequent events

The Prospectus in connection to the Eni UK business combination will be released concurrently with our H1 2024 results on 22 August 2024.

Alternative performance measures

Non-GAAP measures

The Group uses certain performance metrics that are not specifically defined under United Kingdom 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 H1 2024 condensed consolidated financial statements are set out below:

Adjusted EBITDAX: earnings before interest, tax, put premiums on oil and gas derivative instruments, revaluation of derivative contracts, depletion depreciation and amortisation, impairment charges, exploration and evaluation expenditure, fair value gains or losses on contingent consideration 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 comparable basis, period-on-period.

Adjusted EBITDAX is reconciled to profit after tax as follows:	H1 2024	H1 2023
Profit after tax	\$m 105.7	\$m 159.6
Taxation charge (note 12)	83.7	89.2
Depletion, depreciation and amortisation (note 5)	252.9	384.1
Impairment charges (note 11)	35.5	328.4
Net finance costs (note 7)	80.2	96.5
Oil and gas put premiums (note 4)	1.7	7.5
Revaluation of derivative contracts (note 16)	(0.8)	(38.6)
Exploration and evaluation expenses (note 10)	1.5	1.3
Historic claim relating to an acquisition (note 6)	–	(50.1)
Fair value (gains)/losses on contingent consideration (note 6)	(27.4)	1.8
Adjusted EBITDAX	533.0	979.7

Adjusted net income: profit after tax excluding non-cash impairment charges and the tax effect of these items. Adjusted net income, which is presented as it eliminates items which distort year-on-year comparisons, is reconciled to profit after tax as follows:

	H1 2024 \$m	H1 2023 \$m
Profit after tax	105.7	159.6
Impairment charges	35.5	328.4
Tax credit on impairment charges	(16.5)	(234.8)
Adjusted net income	124.7	253.2

Alternative performance measures continued

Adjusted earnings per share (EPS): adjusted net income divided by average shares for the period of 1,006.6 million (H1 2023: 1,006.6 million).

	H1 2024	H1 2023
Adjusted EPS (cents)	12.4	25.2

Adjusted net debt: consists of amounts outstanding under RBL facility, senior unsecured loan notes, bp unsecured loan and optional project capital expenditure facility 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:

	30 June 2024 \$m	30 June 2023 \$m
RBL drawn facility	–	(250.0)
Senior unsecured notes	(625.0)	(625.0)
bp unsecured loan	(100.0)	–
Optional project capital expenditure facility	(68.7)	–
Cash and cash equivalents	287.7	176.3
Adjusted net debt	(506.0)	(698.7)

Leverage ratio: adjusted net debt at the end of the period divided by adjusted EBITDAX for the preceding 12 months. The leverage ratio is considered to be an important measurement as it is indicative of the borrowing potential of the Group. The calculations are as follows:

	30 June 2024	30 June 2023
Adjusted net debt (\$m)	506.0	698.7
Adjusted EBITDAX (\$m)	1,275.9	1,988.4
Leverage ratio	0.40x	0.35x

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 is considered to be a key measure as it is indicative of the financial capacity of the Group. Available liquidity comprises:

	30 June 2024 \$m	30 June 2023 \$m
Cash and cash equivalents	287.7	176.3
Undrawn borrowing facilities	659.0	615.0
Undrawn optional project capital expenditure facility	81.3	–
Available liquidity	1,028.0	791.3

Alternative performance measures continued

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:

	H1 2024 \$m	H1 2023 \$m
Net cash flow from operating activities	559.8	691.0
Net cash used in investing activities	(229.4)	(221.6)
Bank interest and charges	(41.9)	(49.2)
Interest rate swaps	(0.6)	–
Group free cash flow	287.9	420.2

Unit operating expenditure: operating costs (excluding over/underlift) including tariff expense but excluding tariff income and tanker costs, divided by net production for the period. 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 5 as follows:

	H1 2024	H1 2023
Operating costs of hydrocarbon activities per note 5 (\$m)	282.2	300.7
Less tanker costs included within operating costs of hydrocarbon activities in note 5 (\$m)	(9.1)	(11.6)
Less tariff income included within other income in note 4 (\$m)	(9.8)	(17.0)
Operating costs used to calculate unit operating expenditure (\$m)	263.3	272.1
Production (mmboe)	9.65	13.71
Unit operating expenditure (\$/boe)	27.3	19.8

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

	H1 2024	H1 2023
Depletion, depreciation and amortisation per note 5 (\$m)	252.9	384.1
Production (mmboe)	9.65	13.71
DD&A (\$/boe)	26.2	28.0

Other key performance indicators

Total production: total hydrocarbons produced related to Ithaca Energy's equity in operated and non-operated fields. Total production in H1 2024 was 53,046 boe/d (H1 2023: 75,755 boe/d).

Tier 1 and 2 process safety events: process safety incidents as defined by API 465 Process Safety-Recommended Practice On Key Performance Indicators. There were no Tier 1 or 2 process safety events recorded in H1 2024 (H1 2023: 1).

Serious injury and fatality frequency: the number of serious injuries resulting in permanent impairment, as defined by IOGP, per million hours worked. There were no such incidents during H1 2024 (H1 2023: 0).

Ithaca Energy PLC

Registered office: 33 Cavendish Square London W1G 0PP

www.ithacaenergy.com

AI Terminal

Ithaca Energy PLC

5355_10-q_2024-08-22_595fa127-e479-46b8-a79e-861445224b25.pdf

H1 Report 2024 Results & trading update

Strategic execution supports long-term growth

Contents

H1 2024 strategic highlights

Financial highlights

Transformative Business Combination with Eni UK

1. Creates a platform for value-driven growth

2. Establishes a diverse and high-value portfolio at scale

3. Enhances the Group's capabilities via Eni partnership

Notes:

Transformative Business Combination with Eni UK

4. Supports attractive and sustainable shareholder returns

5. Enhances balance sheet and financial strength

Notes:

6. Supports responsible operations with ESG and decarbonisation focus

7. Strengthens leadership team and operational capabilities

8. Supported by committed long-term shareholders

Highlights

H1 2024 strategic highlights

Boost

Highlights continued

H1 2024 financial highlights

Non-GAAP measures

Highlights continued

H1 2024 operational highlights

Outlook for 2024

Outlook for 2024 and management guidance

• Production guidance:

• Net Rosebank project capital cost guidance:

COMBINED PRO-FORMA 2024 AVERAGE PRODUCTION 2

DIVIDEND COMMITMENT

Half Year 2024 performance in review

Delivering against the Group's 2024 strategic priorities

Business Combination creates a dynamic growth player with significant optionality

BUILD: Continued progress across our highvalue development portfolio

BOOST: Successful delivery of Captain EOR Phase II project

H1 operational performance

Decarbonisation focus

Robust cash flow generation and increased liquidity

Energy Profits Levy

Yaniv Friedman Executive Chairman

Delivering results and developing optionality

Operational and financial review

Financial performance: statutory net income, revenue, costs and charges and adjusted EBITDAX

Adjusted EBITDAX analysis

Total costs and charges

1. Non-GAAP measure.

Taxation

Earnings per share (EPS)

Shares in issue

Dividends

Assets

Liabilities

Equity and reserves

Operating cash flows

Investing cash flows

Financing cash flows

Going concern

Prior period adjustments

Derivative financial instruments

Principal risks and uncertainties

Statement of Directors' responsibilities

Independent review report to Ithaca Energy plc

Conclusion

Basis for Conclusion

Conclusion Relating to Going Concern

Responsibilities of the directors

Auditor's Responsibilities for the review of the financial information

Use of our report

Unaudited condensed consolidated statement of profit or loss For the three and six months ended 30 June and the year ended 31 December 2023

Unaudited condensed consolidated statement of comprehensive income

Unaudited condensed consolidated statement of financial position As at 30 June 2024 and 31 December 2023

Unaudited condensed consolidated statement of financial position continued As at 30 June 2024 and 31 December 2023

Unaudited condensed consolidated statement of changes in equity

For the six months ended 30 June

Unaudited condensed consolidated statement of cash flows

Unaudited condensed consolidated statement of cash flows continued