First Half Results for Six Months to 30 June 2023

Ithaca Energy PLC

23 August 2023

ITHACA ENERGY PLC

("Ithaca Energy", the "Company" or the "Group")

First Half Results for the Six Months to 30 June 2023

Strong H1 production performance, continued strategic and operational progress

Ithaca Energy, a leading UK independent exploration and production company, today announced its unaudited financial results for the six months ended 30 June 2023.

Financial key performance indicators (KPIs)
	H1 2023	H1 2022
Group adjusted EBITDAX¹ ($m)	979.7	907.4
Statutory net income ($m)	159.6	1,557.7
Adjusted net income¹ ($m)	253.2	233.4
Basic EPS (cents)	15.9	155.0
Net cash flow from operating activities ($m)	691.0	989.0
Available liquidity ¹ ($m)	791.3	320.4
Unit operating expenditure¹ ($/boe)	19.8	19.5
Adjusted net debt ¹ ($m)	698.7	1,414.6
Adjusted net debt/Group adjusted EBITDAX ¹	0.35x	0.91x
Other KPIs
Total production (boe/d)	75,755	66,685
Tier 1 / 2 process safety events	1	0
Serious injury and fatality frequency	0	0

¹ Non-GAAP measure as set out on pages 45 to 47.

H1 2023 Operational and strategic highlights

· Strong H1 production of 75.8 thousand barrels of oil equivalent per day (kboe/d), supporting full year 2023 production guidance (H1 2022: 66.7 kboe/d)

- Production growth driven by the contribution of producing asset additions from M&A transactions completed in the first half of 2022

- Production split 66% liquids and 34% gas

· Good progress made in H1 2023 against our BUY, BUILD and BOOST strategy preserving optionality across our portfolio with the aim of maximising value to shareholders

BUY

· Acquired the remaining 40% stake in the Fotla Discovery, together with three exploration licences, providing Ithaca Energy with full control over pre-final investment decision (FID) work and timing (subject to completion)

· Entered into marketing agreement with Shell U.K. Limited in relation to its interests in the Cambo field, representing a meaningful step towards securing an aligned joint venture partnership that would enable the future progression of the Cambo project towards FID, subject to regulatory and licensing approval processes and market conditions

BUILD

· Pre-FID work continues across the Group's high-value greenfield and brownfield development portfolio. Focus remains on finalising development plans and financing for Rosebank

· Positive exploration drilling results at K2 prospect, with the decision to proceed with an appraisal side-track (Ithaca Energy operated, working interest 50%) highlighting Ithaca Energy's impressive exploration track record

BOOST

· Production performance in H1 2023 driven by high production efficiency across our operated assets in Q2 of 93%

· Material project scopes completed at Captain Enhanced Oil Recovery (EOR) Phase II with four of the seven wells drilled. Critical EOR turnaround scopes scheduled for H2 2023

· Front End Engineering Design (FEED) activity ongoing to explore the potential for electrification of the Captain field, demonstrating our continued focus on decarbonisation initiatives across our portfolio

H1 2023 Financial highlights

· Announced second interim 2023 dividend of $133 million payable in September 2023, taking our total year to date interim 2023 dividend to $266 million, with targeted total dividend of $400 million reaffirmed for financial year 2023

· Group adjusted EBITDAX up 8% to $979.7 million (H1 2022: $907.4 million), driven by higher production, despite lower average oil and gas prices

· Realised oil and gas prices (respectively) of $85/boe and $82/boe before hedging results and

$83/boe and $125/boe after hedging results (H1 2022: $107/boe and $144/boe before hedging results and $93/boe and $105/boe after hedging results)

· Strong cost control, despite inflationary headwinds, delivering operating costs of $272.1 million ($19.8/boe (H1 2022: $19.5/boe)), allowing the Group to narrow its full year 2023 guidance range

· Adjusted net income of $253.2 million (H1 2022: $233.4 million)

· Statutory net income $159.6 million (H1 2022: $1,557.7 million) reflecting a $73.7 million post-tax impairment of the Greater Stella Area due to reduction in planned activity, as a direct result of the Energy Profits Levy (EPL) and falling gas prices; H1 2022 includes $1,324.3 million gain on bargain purchase which arose from the acquisitions of Marubeni UK and Siccar Point Energy

· Net cash flow from operating activities of $691.0 million (H1 2022: $989.0 million)

· Producing asset capex of $188 million, allowing the Group to reduce its full year 2023 guidance range

· Strong cash flow generation supporting further deleveraging of the balance sheet in the period. Adjusted net debt of $698.7 million at 30 June 2023 (31 December 2022: $971.2 million; 30 June 2022: $1,414.6 million)

· Group leverage position of 0.35x adjusted net debt to adjusted EBITDAX (30 June 2022: 0.91x)

· Successful redetermination of Reserves Based Lending (RBL) facility in June 2023

· Post period end, signed extension of bp offtake agreement and, in parallel, entered into new five- year $100 million loan facility agreement with bp (yet to be drawn)

Outlook

FY 2023 Management Guidance and Outlook

· Management provides the following updates to previously provided guidance ranges and activities for full year 2023 (FY 2023):

- Production guidance reaffirmed for FY 2023 of 68-74 kboe/d;

- Operating cost guidance narrowed at the lower end of the range for FY 2023 from $560-

$630 million to $560-$610 million; and

- Producing asset capital cost guidance for FY 2023 reduced from $400-$460 million to $390-

$435 million

· Turnaround activity across operated and non-operated base scheduled for Q3 2023

· Captain EOR Phase II project H2 2023 activities include the continued drilling of Area E wells before moving to Area D to commence drilling operations and turnaround activity in Q3 that will support polymer injection into the subsea wells in 2024

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

· Management reaffirms its commitment to targeted total dividend of $400 million for financial year 2023

Energy Profits Levy impact beyond 2023

· In June 2023, the UK government published terms of reference for the oil and gas fiscal regime review and committed to engaging with industry stakeholders. One of HM Treasury's stated objectives is to achieve a "simpler, more predictable, and stabler regime" (HM Treasury)

· In the meantime, until the fiscal regime is improved, as a direct result of the Energy Profits Levy, investment across our operated and non-operated portfolio has and will reduce, including the deferral and cancellation of certain 2023 and 2024 projects, impacting medium-term production outlook, with production in 2024 expected to be lower than 2023 levels. As part of the Group's strategy, we continue to leverage our M&A capabilities evaluating potential inorganic opportunities with the clear intention to increase our production in the medium-term

· We are in the process of working through our medium-term outlook, incorporating the full impact of EPL at an asset level and updating subsurface models for the latest production history along with the potential positive effect of new opportunities we are currently reviewing and we will share an updated view of our medium-term production outlook later in the year

Gilad Myerson, Executive Chairman, commented: "Ithaca Energy's robust H1 performance demonstrates continued strong delivery across our BUY, BUILD and BOOST strategy and our capital allocation policy in H1 2023. I am delighted to announce today the second tranche of our 2023 interim dividend, taking our total year to date dividend in 2023 to $266 million, in line with our commitment to shareholders at IPO.

The Energy Profits Levy continues to have a direct impact on investment in the UK North Sea and Ithaca Energy's own investment programme across its diverse high-quality operated and non-operated asset base. We continue to constructively engage with the UK government to highlight the impact of the current fiscal regime to the industry's outlook and to the UK government's stated energy security and Net Zero ambitions."

Alan Bruce, Chief Executive Officer, commented: "We are pleased to share a strong set of results for the first half of 2023, with growing Adjusted EBITDAX as a result of production of over 75 kboe/d in the period. Production efficiency across our operated assets has been high demonstrating our strong operational capabilities.

We continue to take a disciplined approach to capital investment including at our Captain asset where we are progressing the EOR Phase II project construction activities as well as evaluating emissions reduction options. We reported successful exploration drilling at our K2 prospect in July which further strengthens our high-quality development portfolio."

Ithaca Energy will host an in person and virtual presentation and Q&A session for investors and analysts at 09:00 (BST) today, 23 August 2023, accessible via our website: https://investors.ithacaenergy.com/

Half-year 2023 performance in review

Strong operational performance in H1 supports the Group's full year 2023 outlook

Continued focus on personal and process safety with one Tier 1/2 process safety event recorded as a result of a marine gas oil leak in the Captain FPSO power generation process. The Group's serious incident and fatality rate remained at zero during the period.

Production in the first half of 2023 rose to an average of 75.8 kboe/d (H1 2022: 66.7 kboe/d), driven by the contribution of producing asset additions from M&A transactions completed in the first half of 2022. Production in the six-month period was split 66% oil and 34% gas.

The Group's operated assets accounted for 54% of total H1 2023 production (H1 2022: 63%) with strong production efficiency across the Group's operated portfolio. In the second quarter production efficiency was 93% with the Captain field recording its longest ever production run between field outages.

H1 2023 non-operated production was impacted by the delayed start-up and curtailed production of the Pierce field and a number of unplanned outages at Schiehallion that have now been resolved.

As we enter the second half of the year, the Group will embark on a series of planned maintenance campaigns across its operated and non-operated asset base including a scheduled ~25-day turnaround at Captain, in preparation for the next stage of the EOR Phase II project.

With strong first half production performance; we reaffirm our 2023 production guidance of 68-74 kboe/d.

Operating costs in H1 2023 of $272.1 million (H1 2022: ($234.4 million), representing a broadly flat net unit opex cost of $19.8/boe (H1 2022: $19.5/boe).

During the first half of the year, the Group launched an internal cost optimisation project focused on maintaining tight control on expenditure across our operated and non-operated assets and corporate overhead costs.

In the medium-term, the Group has ambitions to materially reduce the average operating cost per barrel by transitioning our portfolio to earlier-life assets with lower operating costs.

Operating cost guidance narrowed at the lower end of the range for the year ended 31 December 2023 from $560-$630 million to $560-$610 million supported by stringent focus on ongoing cost control.

Total net producing asset capital expenditure (excluding decommissioning) in H1 2023 of $188 million reflects the material work scopes completed at Captain EOR Phase II during the first half of the year, with the Captain field representing approximately 68% of producing asset capital expenditure in the period.

Total capital spend in the year reflects lower scheduled activity across the Group's operated and non- operated assets, with the deferral and cancellation of capital project activities largely driven by EPL and the associated fiscal uncertainty.

Producing asset capital cost guidance reduced for the year ended 31 December 2023 from $400-$460 million to $390-$435 million, reflecting a further reduction to capital cost guidance in addition to the material reduction in guidance provided earlier in the year.

Targeted investment across our strategic pillars: BUY, BUILD and BOOST

With expertise extending across the full life-cycle of E&P operations, the Group has demonstrated its ability in the first half of 2023 to execute operations successfully across exploration, development and production activities.

During July, the Group announced successful exploration drilling at the K2 prospect together with the decision to proceed with follow on appraisal drilling. Results from the appraisal side-track are expected during September and will provide further data to determine a recoverable resource estimate and future development activity. The K2 prospect is an excellent demonstration of the Group's BUILD strategy targeting opportunities close to existing infrastructure to maximise value.

Across our portfolio, we continue to seek to BOOST the value of our assets, including infill drilling campaigns that provide short-cycle returns and near-term cash flow generation. At Alba, preparations were underway in the first half of the year to support an infill drilling campaign that will commence in the second half of the year.

Material progress was made during the first half of the year on executing Phase II of our pioneering polymer EOR project, that will maximise recovery rates from Captain and deliver on our strategy to BOOST field performance. The project reached a number of key milestones in H1 2023 including the successful installation of polymer injection pumps, installation of the subsea umbilical distribution structure and the commencement of Area E drilling operations. In the second half of the year, activities include laying flowlines and umbilicals, installation of piping cassettes and completion of Area E drilling before moving to Area D.

Enhanced oil recovery from Captain EOR Phase I continues to perform well with the first phase of polymer injection exceeding expectations with over 11 mmbbls recovered to date. We continue to refine the pioneering polymer formulation and the development of 5th and 6th generation polymer designs, which will continue to improve cost efficiency of the polymer flood by 10%.

With material work scopes completed, first injection of polymer to support EOR Phase II is expected in summer 2024. History matching of the latest field performance, together with reprocessed seismic, is currently being worked to provide an updated subsurface model to refine the polymer response of EOR Phase II. Initial results confirm no change to overall EOR Phase II reserve recovery but shows indications of the possibility for a longer path to peak response and plateau.

The Group continues to leverage our M&A capabilities (BUY) evaluating potential inorganic opportunities both in the UK and internationally. During the period, we entered into a marketing agreement with Shell

U.K. Limited, taking a meaningful step towards securing an aligned joint venture partnership that would enable the future progression of the Cambo project towards FID. Development options for Cambo continue to be evaluated to support submission of a field development application ahead of the associated licence milestone of 31 March 2024, subject to the outcome of the marketing campaign. In July, the Group announced the acquisition of the remaining 40% stake in the Fotla Discovery providing Ithaca Energy with full control over pre-FID work and timing.

The pace of investment across our pre-FID projects has slowed as we continue to engage with the UK government to highlight the impact of the Energy Profits Levy and fiscal uncertainty on our ability to make critical decisions on large scale capital investments. We remain committed to developing our pre-FID projects and continue to engage in a constructive manner with the UK government. During the first half of the year, the Group continued its work towards supporting a final investment decision at Rosebank and in the near-term, our focus remains on finalising development plans and financing arrangements for thproject, and on prioritising capital across our strategic pillars that will maximise shareholder returns in the current fiscal environment.

Meaningful decarbonisation activity

Ithaca Energy is committed to its ambitions of developing one of the lowest carbon emission portfolios in the UK North Sea by optimising our current portfolio in the short-term, and fundamentally transitioning the portfolio in the medium to long-term.

Significant progress has been made across our operated portfolio with operational improvements at FPF-1 and Captain and an ongoing turbine optimisation project at Alba. For the first six months of 2023, the GHG emissions intensity (Scope 1 and 2), from our operated assets was 24.5 kgCO2e/boe.

FEED activity commenced in April 2023 to explore the potential for electrification of the Group's flagship Captain field, following the successful conclusion of a pre-FEED study in Q1 2023. With over 70% of Captain's GHG emissions related to power generation, partial electrification of the asset has the potential to substantially reduce emissions intensity. The Captain electrification project is an important opportunity contributing to Ithaca Energy meeting its target of a 50% reduction in Scope 1 and 2 CO2e emissions by 2030. The delivery of the project is subject to accessing a suitable grid connection or alternative power source in a timely manner.

Robust cash flow generation and continued strengthening of the balance sheet

During H1 2023, our diversified, high-quality asset base generated net cash flow from operating activities of

$691.0 million. This strong cash flow generation supported the continued deleveraging of our balance sheet in the first half of the year, with the Group reporting adjusted net debt of $698.7 million, representing an adjusted net debt to adjusted EBITDAX ratio of 0.35x at 30 June 2023.

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 $865 million (31 December 2022: $925 million), excluding RBL facilities utilised for letters of credits. The Group continues to be well supported by a banking syndicate of nine financial institutions. The impact of the recently announced price floor, that would trigger the early sunset of the EPL based on oil prices dropping below $71.40 per barrel and gas prices below 54 pence per therm, was yet to be factored into borrowing base availability at redetermination.

Post period end, the Group signed an extension to its Offtake agreement with bp, and in parallel, entered into a new five-year $100 million term loan facility agreement with bp at a commercial interest rate, which is yet to be drawn. This new facility term provides capital out to 2028, supporting the development of pre- FID fields.

The Group continues to have sufficient available capital to support our capital allocation policy with a liquidity position at 30 June of $791.3 million (H1 2022: $320.4 million), prior to execution of the $100 million bp loan facility agreement.

Net income recorded in H1 2023 of $159.6 million, was impacted by a pre-tax impairment charge of $328.4 million (post tax $93.6 million), principally in relation to the Greater Stella Area and other gains of $72.2 million in the period. The impairment charge follows the decision not to proceed with further infill drilling at Harrier, as a direct result of the Energy Profits Levy and falling gas prices.

As we move into the second half of the year, we continue to take a disciplined approach to hedging, recognising the importance of balancing upside exposure to commodity prices while managing downside protection of our cash flows in line with the PROTECT pillar of our capital allocation policy. At 30 June 2023, the Group has a hedged position of 9.9 million barrels of oil equivalent (mmboe) (62% oil) from H2 2023 into 2025 at an average price floor of $73/bbl for oil and 161p/therm for gas. Following the period end, we have been active in placing further hedges on attractive terms and at 15 August our hedged position has increased to 11.5 mmboe (66% oil) from H2 2023 into 2025 at an average price floor of $73/bbl for oil and 159p/therm for gas.

In line with our capital allocation policy, we announced and paid the first tranche of our 2023 dividend of $133 million in March 2023. We are pleased to today declare the second tranche of our 2023 dividend of a further $133 million, payable in September this year, taking our total 2023 interim dividend to $266 million. Ithaca Energy remains committed to its declared dividend policy with a targeted 2023 total dividend of $400 million.

Outlook

Ithaca Energy remains committed to investing in its asset base in the UK North Sea and continues to constructively engage with the UK government to highlight the negative impact of the Energy Profits Levy to our investment programme and the consequential medium and long-term impact to the UK government's energy security and Net Zero ambitions.

New investment has been severely dampened across the UK North Sea in 2023, with operators delaying or cancelling projects given the competition for capital across global portfolios. While we maintain our 2023 production guidance, due to our continued strong operational performance, it is clear that we, like the rest of the industry, will feel the impact of lower investment on our medium-term production outlook below previously guided levels.

The Energy Profits Levy has already resulted in the deferral or cancellation of investment across the Group's operated and non-operated assets, including in the Greater Stella Area (impairment charges in Q2 2023), Montrose Arbroath Area and Elgin Franklin Area. As capital investment plans are being drawn up for 2024 and beyond, both Ithaca Energy and our diverse partner groups, are reconsidering the attractiveness of capital deployment opportunities in the context of an enduring Energy Profits Levy in what we would consider to be a return to normal commodity prices. As an inevitable consequence of the current fiscal environment, our medium-term production outlook will be impacted, such that we now anticipate production in 2024 to fall below 2023 levels. For example, the predominantly 100% Ithaca Energy owned Greater Stella Area is expected to produce over 5,000 boe/d less in 2024, with Energy Profits Levy related investment decisions driving the reduction. We are currently in the process of reviewing inorganic opportunities with the clear intention to increase our production in the medium-term.

Ithaca Energy is actively participating in the ongoing review of the Oil and Gas Fiscal Regime in pursuit of a stable and supportive fiscal regime, required to make critical investment decisions that will support the UK's future energy security. We strongly believe that further amendments are required to the Energy Profits Levy including the amendment, and legislation, of an appropriate price floor that reflects the seasonal nature and structural changes in gas markets.

In the period to June 2023, the Group incurred Energy Profits Levy charges of $223 million.

As we navigate the continued impact of the Energy Profits Levy to our operations, we remain value-focused and disciplined, investing only in opportunities across our BUY, BUILD and BOOST strategy that we believe have the potential to deliver growth and maximise shareholder value, including the pursuit of value- accretive inorganic opportunities that strengthen short to medium-term cash flows.

Enquiries

Ithaca Energy
Kathryn Reid - Head of Investor Relations, Corporate Affairs & Communications	kathryn.reid@ithacaenergy.com
FTI Consulting (PR Advisers to Ithaca Energy)	+44 (0)203 727 1000
Ben Brewerton / Nick Hennis	ithaca@fticonsulting.com

About Ithaca Energy plc

Ithaca Energy is a leading UK independent exploration and production company focused on the UK North Sea with a strong track record of material value creation. In recent years, the Company has been focused on growing its portfolio of assets through both organic investment programmes and acquisitions and has seen a period of significant M&A driven growth centred upon two transformational acquisitions in recent years. Today, Ithaca Energy is one of the largest independent oil and gas companies in the United Kingdom Continental Shelf (the "UKCS"), ranking second by resources.

With stakes in six of the ten largest fields in the UKCS and two of UKCS's largest pre-development fields, and with energy security currently being a key focus of the UK Government, the Group believes it can utilise its significant reserves and operational capabilities to play a key role in delivering security of domestic energy supply from the UKCS.

Ithaca Energy serves today's needs for domestic energy through operating sustainably. The Group achieves this by harnessing Ithaca Energy's deep operational expertise and innovative minds to collectively challenge the norm, continually seeking better ways to meet evolving demands.

Ithaca Energy's commitment to delivering attractive and sustainable returns is supported by a well-defined emissions-reduction strategy with a target of achieving net zero by 2040.

Ithaca Energy plc was admitted to trading on the London Stock Exchange (LON: ITH) on 14 November 2022.

-ENDS-

Financial performance: revenue, costs and charges and adjusted EBITDAX

Statutory net income was $159.6 million (H1 2022: $1,557.5 million) reflecting a $73.7 million post-tax impairment of the Greater Stella Area due to a reduction in planned activity as a direct result of the EPL as well as falling gas prices. H1 2022 included a $1,324.3 million gain on bargain purchase which arose on the Marubeni ans Siccar Point Energy acquisitions.

Adjusted EBITDAX is a key measure of operational performance delivery in the business and increased by 8.0% in H1 2023 to $979.7 million (H1 2022: $907.4 million) despite lower revenue in H1 2023 of $1,248.1 million (H1 2022:

$1,337.6 million). The reduction in revenue was principally due to changes in overlift and underlift positions relative to H1 2022 and lower commodity prices compared to H1 2022, partly offset by higher production in H1 2023 mainly due to acquisitions made during the first half of 2022. Increased production was delivered from new field equity production from acquisitions including from the MonArb area fields (from February 2022), and from the Jade, Elgin Franklin, Mariner and Schiehallion fields (from July 2022).

Average realised oil prices for H1 2023 were $85/boe before hedging results and $83/boe after hedging results (H1 2022: $107/boe before hedging results and $93/boe after hedging results). Average realised gas prices for H1 2023 were $82/boe before hedging results and $125/boe after hedging results (H1 2022: $144/boe before hedging results and $105/boe after hedging results).

The focus on cost was maintained during the period with unit operating expenditure increasing marginally to $19.8/boe (H1 2022: $19.5/boe) reflecting our disciplined cost management approach across the portfolio.

Adjusted EBITDAX analysis

H1 2023 H1 2022 FY 2022

Production Oil Gas NGL	kboe/d 47 25 3	mmboe 8 5 1	kboe/d 40 24 3	mmboe 8 4 0	kboe/d 43 24 4	mmboe 16 9 1
Total production	76	14	67	12	71	26
Revenues¹	$/boe	$m	$/boe	$m	$/boe	$m
Oil revenue	85	650	107	973	100	1,693
Gas revenue	82	380	144	605	149	1,348
NGL revenue	42	26	67	35	57	76
Oil and gas hedging gains/(losses)	13	172	(22)	(269)	(19)	(501)
Total	90	1,228	111	1,344	100	2,615
Movement in oil and gas stocks	4	58	(16)	(186)	(5)	(130)
Tanker costs	(1)	(12)	(1)	(11)	-	(18)
Stella royalties	-	(3)	-	(6)	-	(11)
Total value from production	93	1,271	94	1,141	94	2,457
Costs
Operating costs	(20)	(272)	(19)	(234)	(19)	(496)
Routine G&A	(1)	(15)	-	(6)	(1)	(28)
Forex gain/(loss)	-	(4)	-	6	(1)	(17)
Total operating cash costs	(21)	(291)	(19)	(234)	(21)	(540)
Adjusted EBITDAX²	71	980	75	907	73	1,916

1 Revenues in the above table exclude principally other income and put premiums on oil and gas derivative instruments.

2 Non-GAAP measure.

OPERATIONAL AND FINANCIAL REVIEW CONTINUED

Revenue and EBITDAX

H1 2023 H1 2022

Production (boe/d)	75,755	66,685
	$m	$m
Oil sales	650.2	973.3
Gas sales	379.9	605.0
NGL sales	26.4	35.3
Other income	17.4	18.8
Realised losses on oil derivative contracts	(12.5)	(125.9)
Put premiums on oil derivative instruments	(6.3)	(7.2)
Realised gains/(losses) on gas derivative contracts	194.1	(144.3)
Put premiums on gas derivative instruments	(1.1)	(17.4)
Total revenue	1,248.1	1,337.6
Operating costs	(300.7)	(263.2)
Inventory movements and other items	32.3	(167.0)
Adjusted EBITDAX	979.7	907.4

Statutory net income was $159.6 million (H1 2022: $1,557.7 million) and adjusted net income was $253.2 million (H1 2022: $233.4 million). A reconciliation between statutory net income and adjusted net income is set out on page 13.

Total costs and charges

Total costs and charges amounted to $999.4 million (H1 2022: credit of $403.8 million) and comprised: H1 2023$m H1 2022$m

Depletion, depreciation and amortisation	(384.1)	(297.4)
Operating costs	(300.7)	(263.2)
Movement in inventory	57.5	(186.1)
Royalties	(3.2)	(5.4)
Impairment	(328.4)	(7.6)
Exploration and evaluation	(1.3)	(9.5)
Other gains/(losses)	72.2	(27.5)
Administrative expenses	(14.9)	(26.7)
Gain on bargain purchase	-	1,324.3
Net finance costs	(96.5)	(97.1)
Total costs and charges	(999.4)	403.8

Depletion, depreciation and amortisation charges were $384.1 million (H1 2022: $297.4 million). The year-on-year increase is principally due to the acquisitions made during 2022. Depletion, depreciation and amortisation per barrel was $28 (H1 2022: $25) with the increase driven mainly by the acquisitions made during H1 2022.

Operating costs amounted to $300.7 million (H1 2022: $263.2 million) with the increase driven mainly by higher production.

Movements in oil and gas inventories was a credit of $57.5 million (H1 2022: charge of $186.1 million) representing movements in underlift/overlift entitlement imbalances.

Impairment charges of $328.4 million (H1 2022: $7.6 million) principally reflects 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 (see note 3 for further details).

Exploration and evaluation costs amounted to $1.3 million (H1 2022: $9.5 million) and principally relate to licence relinquishments during the period.

Other gains of $72.2million (H1 2022: losses of $27.5 million) comprise principally gains on financial instruments and a historic claim relating to an acquisition which was settled in Q1 2023. Administrative expenses were $14.9 million (H1 2022: $26.7 million) with the reduction principally due to non-recurring transaction costs in H1 2022.

Gain on bargain purchase in H1 2022 arose on the Marubeni and Siccar Point Energy acquisitions (see 2022 Annual Report and Accounts for further details).

Net finance costs were $96.5 million (H1 2022: $97.1 million) with the reduction principally due to lower interest on related party loans which were repaid during 2022 partly offset by higher bank interest and higher accretion on decommissioning liabilities as a result of a higher discount rate.

OPERATIONAL AND FINANCIAL REVIEW CONTINUED

Financial performance: net income

H1 2023

H1 2022

Profit before tax	248.7	1,741.3
Tax	(89.1)	(183.6)
Net income after tax	159.6	1,557.7
Gain on bargain purchase	-	(1,324.3)
Impairment charges	328.4	-
Tax credit on impairment charges	(234.8)	-
Adjusted net income¹	253.2	233.4

1 Non-GAAP measure.

Adjusted net income was broadly in line with H1 2022 despite the introduction of the EPL which added an incremental current tax charge of $223.1 million for the first half of 2023.

Financial position: assets/liabilities/equity

30 June 2023 $m 31 December 2022 $m

Total assets	6,365.4	6,759.6
Total liabilities	(3,853.3)	(4,302.1)
Net assets and shareholders' equity	2,512.1	2,457.5

Assets

At 30 June 2023, total assets amounted to $6,365.4 million (31 December 2022: $6,759.6 million), of which current assets were $878.6 million (31 December 2022: $988.7 million) and non-currents assets were $5,486.8 million (31 December 2022: $5,770.9 million). The decrease in total assets during the period was primarily due to a reduction in the carrying value of property, plant and equipment as the depreciation charge and impairment charges during the period were significantly higher than fixed asset additions, a $59.2m increase in exploration and evaluation assets primarily due to additions during the period as well as a $103.3m increase in deferred tax assets.

Liabilities

At 30 June 2023, total liabilities amounted to $3,853.3 million (31 December 2022: $4,302.1 million) including decommissioning provisions of $1,797.5 million (31 December 2022: $1,720.5 million) and borrowings of

$866.0 million (31 December 2022: $1,213.7 million). The decrease in total liabilities during the period was primarily due to lower borrowings of $347.7 million (see cash flow on page 14), a reduction in trade and other payables of

$190.5 million due to a lower level of unfavourably hedged commodity positions, lower overlift at 30 June 2023 and lower derivative financial instruments partly offset by an increase in current tax payable of $156.0 million principally due to EPL.

Equity and reserves

At 30 June 2023, total equity and reserves amounted to $2,512.1 million (31 December 2022: $2,457.5 million) The increase in equity and reserves during the period was primarily due to the retained profit for the period partly offset by the interim dividend paid in March.

Financial position: cash

H1 2023

H1 2022

Opening cash	253.8	44.9
Operating cash flows	691.0	989.0
Investing cash flows	(221.6)	(1,203.6)
Financing cash flows	(548.1)	332.7
Foreign exchange	1.2	(2.6)
Net cash flow	(77.5)	115.5
Closing cash	176.3	160.4
Undrawn borrowing facilities/restricted cash	615.0	160.0
Available liquidity	791.3	320.4

Operating cash flows

Net cash from operating activities amounted to $691.0 million (H1 2022: $989.0 million) after accounting for adverse working capital movements of $184.2 million (H1 2022: favourable movements of $156.7 million) primarily due to changes in the overlift/underlift position with the reduction principally due to the working capital movement compared to H1 2022.

Investing cash flows

Cash flow used in investing activities amounted to $221.6 million (H1 2022: $1,203.6 million) reflecting capital expenditure of $218.0 million (H1 2022: $230.3 million) driven mainly by the Captain development project. H1 2022 included investing cash flows related to acquisitions (net of cash acquired) of $957.5 million being primarily driven by the Siccar Point Energy ($926.7 million) acquisition.

Financing cash flows

Cash outflow from financing activities of $548.1 million (H1 2022: inflow of $332.7 million) with interest costs and lease payments of $65.1 million (H1 2022: $67.5 million), a net repayment of principal debt of $350.0 million (H1 2022: increase of $400.0 million) and the payment of the first interim dividend of $133.0 million (H1 2022: $nil).

Cash balances were $176.3 million (H1 2022: $160.4 million) at the end of the period and available liquidity was $791.3 million (H1 2022: $320.4 million).

OPERATIONAL AND FINANCIAL REVIEW CONTINUED

Subsequent events

On 11 July 2023, the Group announced that it had signed a Sale and Purchase Agreement to acquire the 40% stake in the Fotla Discovery that it doesn't already own and three exploration licences from Spirit Energy Resources Limited. The agreement, which is subject, amongst other things, to regulatory approval, will bring the Group's working interest in Fotla to 100% providing Ithaca Energy with full control over pre-final investment decision work and timing. The total transaction consideration of up to $14.6 million, comprises two capped contingent payments of which approximately two-thirds is payable on final investment decision and one-third on first production.

On 26 July 2023, Ithaca Energy announced successful well test results at the K2 prospect and as a result the Group, together with its joint venture partner, have decided to perform an appraisal sidetrack following the positive results in the main bore. The Group holds a 50% working interest in this licence with the remaining 50% working interest held by Dana Petroleum.

On 31 July 2023, the Group completed a new 5-year $100m unsecured loan agreement with bp at a commercial interest rate. Separately, a new offtake agreement was also completed with bp on that date which runs concurrently with the loan agreement.

Going concern

Based on their assessment of the Group's financial position over the period to 30 September 2024, the Directors believe that the Group will be able to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis of accounting in preparing the consolidated financial statements. Further details are set out in note 3.

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 2023, the following hedges were in place:

	H2 2023	2024	2025
Oil
Volume hedged (mmboe)	4.2	1.9	-
Weighted average floor hedged price ($/bbl)	71	78	-

Gas
Volume hedged (mmboe)	1.5	2.1	0.2
Weighted average floor hedged price (p/therm)	193	143	125

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 2022 Annual Report and Accounts. 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 and delivery

• Commodity price exposure and volatility

• Production delivery issues

• Energy transition and Net Zero delivery

• Workforce recruitment and retention

• Supply chain capacity and capability

• Governmental regulatory, political policy and fiscal risk

• Major compliance breach

Details of these principal risks and how they are being managed are set out on pages 64 to 68 of the 2022 Annual Report and Accounts.

STATEMENT OF DIRECTORS' RESPONSIBILITIES

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

• The condensed set of financial statements has been prepared in accordance with IAS 34 Interim Financial Reporting as contained within UK adopted IFRS;

• The 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

• The 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

22 August 2023

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 2023 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 2023 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 22 August 2023

	Note	2023 US$'000 (Unaudited)	2022 US$'000 (Unaudited)	2023 US$'000 (Unaudited)	2022 US$'000 (Audited)
Revenue	4	603,793	597,426	1,248,109	1,337,585
Cost of sales	5	(327,480)	(343,416)	(630,391)	(752,035)
Gross profit		276,313	254,010	617,718	585,550
Impairment charge	3	(328,426)	(7,608)	(328,426)	(7,608)
Exploration and evaluation expenses		-	(7,945)	(1,334)	(9,550)
Administrative expenses		(5,057)	(13,192)	(14,935)	(26,746)
Other gains/(losses)	6	(18,752)	(21,419)	72,239	(27,562)
Gain on bargain purchase		-	723,405	-	1,324,342
Profit/(loss) from operations before tax and net finance costs		(75,922)	927,251	345,262	1,838,426
Net finance costs	7	(46,939)	(47,606)	(96,521)	(97,081)
Profit/(loss) before tax		(122,861)	879,645	248,741	1,741,345
Income tax	12	124,006	(84,162)	(89,155)	(183,655)
Profit attributable to owners of the parent		1,145	795,483	159,586	1,557,690
Three months ended 30 June Six months ended 30 June
Earnings per share for profit attributable to the ordinary equity holders of the Company	Note	2023 Cents	2022 Cents	2023 Cents	2022 Cents
Basic earnings per share	8	0.1	79.1	15.9	155.0
Diluted earnings per share	8	0.1	79.1	15.7	154.8
The results above are entirely derived from continuing operations.
The accompanying notes on pages 26 to 44 are an integral part of the financial statements.

	Note	2023 US$'000 (Unaudited)	2022 US$'000 (Unaudited)	2023 US$'000 (Unaudited)	2022 US$'000 (Audited)
Profit for the period		1,145	795,483	159,586	1,557,690
Items that may be reclassified to profit and loss
Fair value gain/(loss) on cash flow hedges and cost of hedging	16	(283)	189,916	83,178	(267,082)
Deferred tax (charge)/credit on cash flow hedges and cost of hedging	12	135	(75,966)	(62,292)	106,833
Other comprehensive profit/(loss)		(148)	113,950	20,886	(160,249)
Total comprehensive profit attributable to owners of the parent		997	909,433	180,472	1,397,441
The accompanying notes on pages 26 to 44 are an integral part of the financial statements.

		30 June	31 December
		2023	2022
		US$'000	US$'000
	Note	(Unaudited)	(Audited)
Assets
Current assets
Cash and cash equivalents		176,324	253,822
Trade and other receivables	9	349,100	359,994
Decommissioning receivable	9	24,115	38,115
Prepaid expenses and decommissioning securities		7,748	9,055
Inventories		174,064	176,881
Derivative financial instruments	17	147,189	150,858
		878,540	988,725
Non-current assets
Decommissioning receivable	9	171,551	162,710
Exploration and evaluation assets	10	834,969	775,773
Property, plant and equipment	11	3,191,071	3,634,896
Deferred tax assets	12	495,715	392,456
Derivative financial instruments	17	9,668	21,191
Goodwill		783,848	783,848
		5,486,823	5,770,874
Total assets		6,365,363	6,759,599
Liabilities and equity
Current liabilities
Trade and other payables		(520,930)	(711,412)
Current tax payable		(262,705)	(106,678)
Decommissioning liabilities	14	(86,929)	(146,829)
Lease liability		(42,634)	(41,637)
Contingent and deferred consideration	15	(38,406)	(107,680)
Derivative financial instruments	17	(23,283)	(136,668)
		(974,887)	(1,250,904)

		30 June	31 December
		2023	2022
		US$'000	US$'000
	Note	(Unaudited)	(Audited)
Non-current liabilities
Borrowings	13	(865,984)	(1,213,731)
Decommissioning liabilities	14	(1,710,562)	(1,573,711)
Lease liability		-	(17,221)
Contingent and deferred consideration	15	(291,759)	(219,120)
Derivative financial instruments	17	(10,071)	(27,440)
		(2,878,376)	(3,051,223)
Total liabilities		(3,853,263)	(4,302,127)
Net assets		2,512,100	2,457,472
Shareholders' equity
Share capital		11,445	11,445
Share premium		293,712	293,712
Capital contribution reserve		181,945	181,945
Share-based payment reserve		12,081	4,920
Cash flow hedge reserve		36,938	16,710
Cost of hedging reserve		3,933	3,275
Retained earnings		1,972,046	1,945,465
Total equity		2,512,100	2,457,472
The accompanying notes on pages 26 to 44 are an integral part of the financial statements.
Approved on behalf of the Board on 22 August 2023:
IAIN C S LEWIS, Director

	Share capital	Share premium	Capital contribution reserve	Share-based payment reserve	Cash flow hedge reserve	Cost of hedging reserve	Retained earnings/ (accumulated losses)	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Balance at 1 January 2022	1	634,658	114,000	-	(242,791)	(4,862)	175,503	676,509
Total comprehensive income for the period:
Profit for the period	-	-	-	-	-	-	1,557,690	1,557,690
Other comprehensive expense	-	-	-	-	(43,649)	(116,600)	-	(160,249)
Total comprehensive income/(expense) for the period	-	-	-	-	(43,649)	(116,600)	1,557,690	1,397,441
Balance at 30 June 2022 (Audited)	1	634,658	114,000	-	(286,440)	(121,462)	1,733,193	2,073,950

Balance at 1 January 2023	11,445	293,712	181,945	4,920	16,710	3,275	1,945,465	2,457,472
Dividend	-	-	-	-	-	-	(133,005)	(133,005)
Share-based payment charge	-	-	-	7,161	-	-	-	7,161
Total 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
The accompanying notes on pages 26 to 44 are an integral part of the financial statements.

Three months ended 30 June Six months ended 30 June

Cash provided by/(used in) operating activities:

Note

2023

US$'000

(Unaudited)

2022

US$'000

(Unaudited)

2023

US$'000

(Unaudited)

2022

US$'000

(Audited)

Profit/(loss) before tax		(122,861)	879,645	248,741	1,741,345
Adjustments for:
Depletion, depreciation and amortisation	11	195,386	152,387	384,120	297,417
Exploration and evaluation expenses		-	7,945	1,334	9,550
Impairment charge		328,426	7,608	328,426	7,608
Increase in contingent/deferred consideration		26,103	14,449	1,725	14,449
Loan fee amortisation		1,103	1,127	2,254	2,282
Revaluation of financial instruments		(16,990)	12,294	(38,660)	18,676
Prepaid put premiums		1,142	-	1,142	-
Gain on bargain purchase		-	(723,405)	-	(1,324,342)
Hedging resets¹		-	(10,017)	-	(20,318)
Accretion		19,763	12,208	37,912	24,212
Bank interest and charges		26,072	49,366	56,355	52,920
Interest on related party loan		-	17,924	-	17,924
Interest rate swaps		-	(4,782)	-	(257)
Unrealised foreign exchange on cash and cash equivalents		(1,582)	2,585	(1,219)	2,585
Share-based payment expenses		4,304	-	8,562	-
Decommissioning expenditure		(31,314)	(7,894)	(56,771)	(11,689)
Operating cash flows before movements in working capital		429,552	411,440	973,921	832,362
Decrease in inventories		5,909	8,013	2,818	42,945
Decrease/(increase) in trade and other receivables		13,319	118,709	28,398	(58,228)
(Decrease)/increase in trade and other payables		(109,161)	167,142	(215,466)	171,954
Corporation tax paid		-	-	(98,719)	-
Net cash from operating activities		339,619	705,304	690,952	989,033

FOR THE THREE MONTHS ENDED 31 MARCH

Three months ended 30 June Six months ended 30 June

	Note	2023 US$'000 (Unaudited)	2022 US$'000 (Unaudited)	2023 US$'000 (Unaudited)	2022 US$'000 (Audited)
Cash used in investing activities
Capital expenditure		(120,322)	(153,091)	(218,002)	(230,338)
Acquisition of subsidiaries net of cash acquired		-	(1,017,270)	-	(957,452)
Contingent/deferred consideration payment		(1,220)	(4,237)	(3,568)	(15,864)
Net cash used in investing activities		(121,542)	(1,174,598)	(221,570)	(1,203,654)
Cash provided by/(used in) financing activities
Dividends paid		-	-	(133,005)	-
Payments for lease liabilities (principal)		(11,107)	(9,621)	(15,912)	(13,018)
Loan repayment (third party)		(100,000)	600,000	(350,000)	400,000
Bank interest and charges		(7,634)	(31,101)	(49,182)	(54,517)
Interest rate swaps		-	257	-	257
Net cash used in financing activities		(118,741)	559,535	(548,099)	332,722
Currency translation differences relating to cash		1,583	(1,736)	1,219	(2,582)
Increase/(reduction) in cash and cash equivalents		100,918	88,505	(77,498)	115,519
Cash and cash equivalents, beginning of period		75,406	71,863	253,822	44,849
Cash and cash equivalents, end of period		176,324	160,368	176,324	160,368
1. Hedging resets relate to the amortisation of the deferred reset gains which have been recycled to the current year profit and loss.
The accompanying notes on pages 26 to 44 are an integral part of the financial statements.

1. Nature of operations

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 17 Hanover Square, London, United Kingdom, W1S 1BN.

2. Basis of preparation

The condensed consolidated financial statements are prepared in accordance with United Kingdom adopted International Accounting Standard 34 Interim Financial Reporting as contained within UK Adopted IFRS.

The condensed consolidated financial statements for the six months ended 30 June 2023 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 2023 are not audited but have been reviewed by the auditor whose review report is set out on page 18. The accounting policies adopted in the preparation of the H1 2023 condensed consolidated financial statements are consistent with those adopted and disclosed in the Group's 2022 Annual Report and Accounts. Comparative information for the year ended 31 December 2022 has been taken from the statutory accounts for that year, a copy of which has been delivered to the Registrar of Companies. 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. Comparative information

for the six months ended 30 June 2022 has been taken from the audited Historical Financial Information included in the IPO Prospectus issued in November 2022. A number of amendments to existing standards and interpretations were effective from 1 January 2023, as was IFRS 17 Insurance Contracts, but there was no impact on the H1 2023 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 (US$'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 2023 condensed consolidated financial statements are to be read in conjunction with Ithaca Energy's Annual Report and Accounts for the year ended 31 December 2022, which contains additional accounting policy disclosure.

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.

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 financial statements on a going concern basis to be appropriate. This is due to the following key factors:

• Strong commodity markets and continuing robust commodity price backdrop despite lower prices during H1 2023 and a well hedged portfolio over the next 12 months;

• A new 5-year $100 million loan agreement with bp entered into after the end of the period (see note 19);

• Reserves Based Lending (RBL) liquidity headroom of $615 million ($250 million drawn versus $865 million available), plus $176 million of cash as at the end of June 2023; and

• Strong operational performance and well-diversified portfolio.

3. Accounting policies continued
Cash flow forecast - base case assumptions:		H2 2023	2024
Average oil price	$/bbl	84	82
Average gas price	p/th	88	126
Average hedged oil price (including floor price for zero cost collars)	$/bbl	72	77
Average hedged gas price (including floor price for zero cost collars)	p/th	190	143

Owing to the on-going 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 there was no reasonably possible scenario that would result in the business being unable to meet its liabilities as they fell due. The Group would still continue to comply with financial covenants and have sufficient liquidity throughout the period to 30 September 2024 to continue trading. In addition, mitigation strategies within the control of management include the reduction in uncommitted capital expenditure, variable opex savings in the low production scenario, the cancellation or deferral of future dividends and further potential to refinance the Group's borrowing arrangements.

Based on their assessment of the Group's financial position in the period to 30 September 2024, 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 H1 2023 condensed consolidated financial statements.

Use of judgements and estimates

In preparing these H1 2023 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 key sources of estimation uncertainty that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next year are the same as those described on page 150 of the Group's 2022 Annual Report and Accounts with the below exception. The only critical accounting judgement applied in the preparation of the H1 2023 condensed consolidated financial statements is whether there has been an indication of impairment in respect of the Cambo field, as discussed further below.

Estimates in impairment of oil and gas assets and goodwill

Determination of whether the Group's oil and gas assets (note 11) or goodwill have suffered any impairment requires an estimation of the recoverable amount of the cash generating unit (CGU) to which the oil and gas assets and goodwill have been allocated. Projected future cash flows are used to determine a fair value less cost to sell to establish the recoverable amount. Key assumptions and estimates in the impairment models relate to commodity prices that are based on an internal view of forward price curves that are considered to be a best estimate of what a market participant would use, discount rate which reflect management's best estimate of a market participant's post-tax weighted average cost of capital, and oil and gas reserves and resources on a risked basis as described in the 2022 Annual Report and Accounts. Management's best estimates of a market participant's view of pricing and discount rates are also supported by an independent consultant.

Following a quarterly review for indicators of impairment it was identified that there were indicators of impairment relating to the Greater Stella Area (GSA) CGU due to lower than previously forecast future gas prices as well as a reduction in planned activity as a direct result of the EPL. It was determined that the recoverable amount of the GSA CGU was $273.5 million compared to a carrying value of $568.2 million resulting in a pre-tax impairment charge of $294.7 million. Separately, a pre-tax impairment charge of $33.7 million arose primarily on higher decommissioning costs on Fionn and Anglia which are both fully depreciated and have ceased production. The total impairment charge in the six months to 30 June 2023 was therefore $328.4 million (six months to 30 June 2022: $7.6 million).

The H1 2023 impairment projections for GSA used a post-tax discount rate of 10.5% and the following nominal commodity price assumptions:
	H2 2023	2024	2025	2026	2027
Oil ($/bbl)	84	87	90	92	93
Gas (p/therm)	129	114	99	77	79

3. Accounting policies continued

Details of assumptions used for impairment testing for year ending 31 December 2022 and 31 December 2021 are set out on pages 165 and 166 of the 2022 Annual Report and Accounts.

With all other assumptions held constant, a 20% decrease in forecast revenues, illustrating lower commodity prices and/or production volumes, would result in a further post-tax impairment of GSA property, plant and equipment (PP&E) of $98 million. An increase of 1% in the discount rate assumption would not have a material impact on the post-tax impairment.

Management has reviewed the carrying value of the Cambo field and has concluded that due to ongoing initiatives, including those to address Shell's exit and the 31 March 2024 licence expiry, there are currently no indicators of impairment. Further details are provided in the Half Year 2023 Performance in Review.

Judgements and estimates made in assessing the impact of climate change and the energy transition have not materially changed for the H1 2023 consolidated condensed financial statements. Details of these are set out on pages 141 and 142 of the 2022 Annual Report and Accounts.

4. Revenue

Three months ended 30 June Six months ended 30 June

	2023 US$'000	2022 US$'000	2023 US$'000	2022 US$'000
Oil sales	336,821	474,968	650,176	973,326
Gas sales	152,735	199,261	379,883	604,996
NGL sales	12,837	20,338	26,434	35,297
Other income	7,821	7,337	17,388	18,782
Realised losses on oil derivative contracts	(5,740)	(73,043)	(12,440)	(125,908)
Put premiums on oil derivative instruments	(2,730)	(3,645)	(6,330)	(7,254)
Realised gains/(losses) on gas derivative contracts	103,191	(11,319)	194,140	(144,265)
Put premiums on gas derivative instruments	(1,142)	(16,471)	(1,142)	(17,389)
	603,793	597,426	1,248,109	1,337,585

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

Revenue from two customers (30 June 2022: one customer) exceeds 10% of the Group's consolidated revenue arising from hydrocarbon sales for the six months ended 30 June 2023, representing $689.6 million and $216.1 million respectively (six months ended 30 June 2022: $1,308.8 million).

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

5. Cost of sales

Three months ended 30 June Six months ended 30 June

2023

US$'000

2022

US$'000

2023

US$'000

2022

US$'000

Movement in oil and gas inventory

18,709

(62,011)

57,546

(186,076)

Operating costs

(149,531)

(126,211)

(300,652)

(263,180)

Royalties

(1,273)

(2,807)

(3,165)

(5,362)

Depreciation on right-of-use assets

(10,534)

(9,074)

(20,953)

(11,519)

Depletion, depreciation and amortisation

(184,851)

(143,313)

(363,167)

(285,898)

(327,480)

(343,416)

(630,391)

(752,035)

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

2023

US$'000

2022

US$'000

2023

US$'000

2022

US$'000

Gain/(loss) on financial instruments

13,521

(12,295)

27,485

(19,131)

Fair value losses on contingent consideration

(26,103)

(14,449)

(1,725)

(14,449)

Net foreign exchange

(5,476)

5,325

(3,589)

6,018

Settlement of historic claim relating to an acquisition

(694)

50,068

(18,752)

(21,419)

72,239

(27,562)

On 12 February 2023 the Group reached agreement on the settlement of a historic claim relating to an acquisition. Under the terms of the agreement Ithaca Energy received $50.1 million which was recognised in the condensed consolidated financial statements in Q1 2023.

7. Net finance costs

Three months ended 30 June Six months ended 30 June

2023

US$'000

2022

US$'000

2023

US$'000

2022

US$'000

Bank interest and charges

(12,165)

(11,533)

(28,964)

(21,332)

Senior notes interest

(14,024)

(27,895)

(27,894)

Loan fee amortisation

(1,103)

(1,127)

(2,254)

(2,282)

Interest on lease liabilities

(783)

(1,829)

(1,635)

(1,829)

Interest on related party loan

(5,024)

(17,924)

Accretion

(19,763)

(12,208)

(37,912)

(24,212)

Realised gains on interest derivative contracts

257

Interest income

899

(253)

2,139

Other

(1,865)

(46,939)

(47,606)

(96,521)

(97,081)

There was no interest capitalised into qualifying assets in either the six months to 30 June 2023 or the six months to 30 June 2022.

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

2023

US$'000

2022

US$'000

2023

US$'000

2022

US$'000

Earnings for the period:

Earnings for the purpose of basic earnings per share

1,145

795,483

159,586

1,557,690

Effect of dilutive potential ordinary shares

Earnings for the purpose of diluted earnings per share

1,145

795,483

159,586

1,557,690

Number of shares (million)

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

1,006.6

1,005.2

1,006.6

1,005.2

Dilutive potential ordinary shares

6.9

0.9

6.9

0.9

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

1,013.5

1,006.1

1,013.5

1,006.1

Earnings per share (cents)

Basic

0.1

79.1

15.9

155.0

Diluted

0.1

79.1

15.7

154.8

9. Trade and other receivables
Current	30 June 2023 US$'000	31 December 2022 US$'000
Trade receivables	41,350	31,906
Other receivables	47,901	14,210
Joint venture receivables	125,837	99,800
Accrued income	134,012	214,078
	349,100	359,994

The Group regularly monitors all customer receivable balances outstanding in excess of 90 days for expected credit losses (ECLs). The Group applies a simplified approach in calculating ECLs as allowed under IFRS 9. Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, the economic environment and the Group's historical credit loss experience. Substantially all trade and other receivables are current, being defined as less than 90 days, and as such no ECLs have been recognised in the current or prior year as the ECL is considered immaterial.

Non-current	30 June 2023 US$'000	31 December 2022 US$'000
Decommissioning reimbursement	171,551	162,710
Current	30 June 2023 US$'000	31 December 2022 US$'000
Decommissioning reimbursement	24,115	38,115

The decommissioning reimbursement represents 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 the CNSL acquisition, Chevron have the obligation to provide the security and remain financially responsible for the decommissioning obligations of CNSL in relation to these interests. As the payment is virtually certain this has been accounted for under IAS 37 as a reimbursement asset.

10. Exploration and evaluation assets
	US$'000
At 1 January 2022	116,355
Additions	42,168
Acquisitions	706,558
Transfers to development and production assets (note 11)	(75,005)
Write offs/relinquishments	(14,303)
At 31 December 2022 and 1 January 2023	775,773
Additions	60,530
Write offs/relinquishments	(1,334)
At 30 June 2023	834,969

10. Exploration and evaluation assets continued

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 $1.3 million being expensed in the six months to 30 June 2023 (six months to 30 June 2022: $14.3 million).

The principal exploration and evaluation assets at 30 June 2023 and 31 December 2022 are Cambo and Rosebank, which formed part of the Siccar Point Energy acquisition in 2022.

11. Property, plant and equipment

Right-of-use operating assets

Development and production assets

Other fixed assets

Total

US$'000

Cost

At 1 January 2022

9,210

5,838,178

40,293

5,887,681

Additions

89,717

362,844

5,619

458,180

Acquisitions

1,115,023

Transfers from exploration and evaluation assets (note 10)

75,005

Change in decommissioning estimates

(278,398)

At 31 December 2022 and 1 January 2023

98,927

7,112,652

45,912

7,257,491

Additions

268,217

504

268,721

At 30 June 2023

98,927

7,380,869

46,416

7,526,212

Depletion, depreciation, amortisation and Impairment

At 1 January 2022

(5,429)

(2,909,695)

(13,824)

(2,928,948)

Depletion, depreciation and amortisation charge for the year

(37,438)

(615,261)

(10,248)

(662,947)

Impairment charge

(30,700)

At 31 December 2022 and 1 January 2023

(42,867)

(3,555,656)

(24,072)

(3,622,595)

Depletion, depreciation and amortisation charge for the period

(20,953)

(359,562)

(3,605)

(384,120)

Impairment charge

(328,426)

At 30 June 2023

(63,820)

(4,243,644)

(27,677)

(4,335,141)

Net book value at 31 December 2022

56,060

3,556,996

21,840

3,634,896

Net book value at 30 June 2023

35,107

3,137,225

18,739

3,191,071

The transfers from exploration and evaluation assets to development and production assets in the year to 31 December 2022 relates to the Abigail and Jade South wells. At the point of transfer these assets were tested for impairment and none was found.

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

As at 30 June 2023 the Group had capital commitments of $89.0 million (31 December 2022: $52.3 million). The key components at 30 June 2023 relate to the Captain Enhanced Oil Recovery (EOR) project. At 31 December 2022, the commitments related primarily to the Captain EOR project and drilling at the Shaw field.

12. Taxation

Three months ended 30 June Six months ended 30 June

2023

US$'000

2022

US$'000

2023

US$'000

2022

US$'000

Current tax

Current corporation tax charge

(21,382)

(31,695)

Current EPL tax charge

(96,543)

(223,051)

Total current tax charge

(117,925)

(254,746)

Deferred tax

Adjustment in respect of prior period

371

(16,357)

(1)

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

242,735

(62,620)

183,123

(162,112)

Group tax (charge)/credit in consolidated statement of other comprehensive income

135

(75,966)

(62,292)

106,833

Total deferred tax credit/(charge)

243,241

(138,586)

104,474

(55,280)

Deferred PRT charge in consolidated statement of profit or loss

(1,175)

(21,542)

(1,175)

(21,542)

Total tax credit/(charge) through consolidated statement of profit or loss

124,006

(84,162)

(89,155)

(183,655)

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

2023

US$'000

2022

US$'000

2023

US$'000

2022

US$'000

Accounting profit/(loss) before tax

(122,861)

879,645

248,741

1,741,345

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

49,144

(351,858)

(99,497)

(696,538)

Non-deductible (expense)/income

(24,158)

259,885

(6,085)

484,888

Financing costs not allowed for Supplementary Charge

(133)

(507)

(530)

(1,015)

Ring Fence Expenditure Supplement

25,727

17,490

53,076

34,888

Deferred tax effect of investment allowance

10,859

3,719

18,886

7,253

Prior year adjustment

371

(1)

(16,357)

(1)

Deferred tax on EPL

160,887

189,389

Current tax on EPL

(96,543)

(223,051)

Net deferred tax PRT

(705)

(12,926)

(705)

(12,926)

Share Schemes

(1,059)

Unrecognised tax losses

(384)

(3,222)

(204)

Total tax credit/(charge) recorded in the consolidated statement of profit or loss

124,006

(84,162)

(89,155)

(183,655)

12. Taxation continued

The Company is UK tax resident. The effective rate of tax applicable for UK ring fence oil and gas activities in 2023, was 40% (excluding the Energy Profits Levy ("EPL") of 35%) (2022: 40% excluding EPL of 25%) 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 recognise deferred PRT assets are made to reflect updated expectations of reversal against profits subject to the 0% PRT rate. The EPL 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 fenced oil and gas tax rate to 75%.

Deferred tax at 30 June 2023 and 31 December 2022 relates to the following:
	30 June	31 December
	2023 US$'000	2022 US$'000
Deferred corporation tax liability	(1,958,159)	(2,258,813)
Deferred corporation tax asset	2,433,327	2,629,548
Deferred PRT asset	20,547	21,721
Net deferred tax asset	495,715	392,456

Deferred tax assets primarily relate to decommissioning liabilities, brought forward tax losses, and accumulated losses and profits related to derivative contracts. Deferred tax liabilities primarily relate to accelerated capital allowances on property, plant and equipment and accumulated losses and profits related to derivative contracts.

The gross movement on the deferred tax account in the balance sheet is as follows:
	30 June	31 December
	2023 US$'000	2022 US$'000
At 1 January	392,456	220,918
Profit or loss credit/(charge)	165,551	(1,024,889)
Other comprehensive income charge	(62,292)	(200,455)
Business combinations	-	1,396,882
At end of period	495,715	392,456

12. Taxation continued

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

		6 months ended 30 June 2023 US$'000	6 months ended 30 June 2022 US$'000
Accelerated capital allowances		327,032	23,129
Tax losses		(146,427)	(212,316)
Abandonment provision		30,783	5,941
Deferred PRT		470	8,617
Hedging		(86,672)	119,349
Share Schemes		3,374	-
Investment Allowances		(24,086)	-
Net movement in the period		104,474	(55,280)
	Deferred corporation tax on	Accelerated tax
Gross deferred corporation tax liabilities	deferred PRT US$000	depreciation US$000	Total US$000
At 1 January 2022	(12,861)	(675,279)	(688,140)
Prior year adjustment	-	(4,347)	(4,347)
Reclassification of decommissioning assets	-	(436,771)	(436,771)
Business combinations	-	(647,743)	(647,743)
Origination and reversal of temporary differences	4,173	(485,985)	(481,812)
At 31 December 2022	(8,688)	(2,250,125)	(2,258,813)
Prior year adjustment	-	(7,307)	(7,307)
Origination and reversal of temporary differences	470	307,493	307,963
At 30 June 2023	(8,218)	(1,949,939)	(1,958,157)

12. Taxation continued
	Shares schemes	Abandonment provision	Tax losses	Hedges	Total
Gross deferred corporation tax assets	US$000	US$000	US$000	US$000	US$000
At 1 January 2022	-	197,666	500,282	178,956	876,904
Prior year adjustment	-	-	3,706	-	3,706
Reclassification of decommissioning asset	-	436,772	-	-	436,772
Business combinations	-	156,212	1,858,706	38,406	2,053,324
Origination and reversal of temporary differences	-	(124,598)	(390,520)	(226,040)	(741,158)
At 31 December 2022	-	666,052	1,972,174	(8,678)	2,629,548
Prior year adjustment	177	-	(12,141)	2,721	(9,243)
Origination and reversal of temporary differences	3,198	30,783	(134,286)	(86,672)	(186,977)
At 30 June 2023	3,375	696,835	1,825,747	(92,629)	2,433,328
Deferred PRT asset					Total $000
At 1 January 2022					32,154
Origination and reversal of temporary differences					(10,433)
At 31 December 2022					21,721
Origination and reversal of temporary differences					(1,175)
At 30 June 2023					20,546

The carrying value of the net deferred corporation tax asset at 30 June 2023 of $475 million (31 December 2022: $371 million) and the deferred PRT asset of $21 million (31 December 2022: $21 million) are supported by estimates of the Group's future taxable income, based on the same price and cost assumptions as used for impairment testing.

An EPL or "the 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 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 no impact on the tax values.

The Group's deferred tax assets are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised, including as a result of Group re-organisations and asset transfers. In accordance with IAS 12 Income Taxes, the Group assesses the recoverability of its deferred tax assets at each period end.

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 accounting periods starting on or after 31 December 2023. The Group has applied the exception under IAS 12 to recognising and disclosing information about deferred tax assets and liabilities related to top-up income taxes, therefore there is no impact on the tax values reported.

13. Borrowings
	30 June	31 December
	2023 US$'000	2022 US$'000
Non-current
RBL facility	(250,000)	(600,000)
Senior unsecured notes	(625,000)	(625,000)
Unamortised long-term bank fees	6,073	7,591
Unamortised long-term senior notes fees	2,943	3,678
Total debt	(865,984)	(1,213,731)
Accrued interest on borrowings is included within accruals.
Adjusted net debt, which does not include lease liabilities, is set out in Non-GAAP measures on page 46.
Details of covenants under the RBL facility are set out in note 20 to the 2022 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
	2023 US$'000	2022 US$'000
Balance at 1 January	(1,720,540)	(1,641,489)
Business combination additions	-	(390,530)
Accretion	(36,485)	(52,592)
Additions and revisions to estimates	(97,238)	298,564
Decommissioning provision utilised	56,772	65,507
Balance, end of period	(1,797,491)	(1,720,540)
Current
Balance, beginning of period	(146,829)	(94,640)
Balance, end of period	(86,929)	(146,829)
Non-current
Balance, beginning of period	(1,573,711)	(1,546,849)
Balance, end of period	(1,710,562)	(1,573,711)

The total future decommissioning liability represents the estimated cost to decommission, in situ or by removal, the Group's net ownership interest in all wells, infrastructure and facilities, based upon forecast timing in future periods. The Group uses a discount rate of 4.25% (31 December 2022: 4.25%) and an inflation rate of 2.0% (31 December 2022: 2.0%) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. Revisions to estimates in the six months ended 30 June 2023 were due to changes in cost estimates and in the year ended 31 December 2022 were due to changes in both cost estimates and discount rate assumptions. Further details including a sensitivity on the impact of a change in the discount rate are set out in the 2022 Annual Report and Accounts.

The estimated decommissioning spend in H2 2023 and H1 2024 of $87 million has been treated as a current liability as at 30 June 2023 (31 December 2022: estimated 2023 spend of $147 million). The Group currently expects to

incur decommissioning costs over the next 40 years.

15. Contingent and deferred consideration
Current	30 June 2023 US$'000	31 December 2022 US$'000
Contingent consideration	(32,220)	(101,559)
Petrofac deferred consideration	(6,186)	(6,121)
	(38,406)	(107,680)
Non-current	30 June 2023 US$'000	31 December 2022 US$'000
Contingent consideration	(229,319)	(157,337)
Deferred consideration	(62,440)	(61,783)
	(291,759)	(219,120)
Movement in contingent consideration and deferred consideration is as follows:
	30 June	31 December
	2023 US$'000	2022 US$'000
At beginning of period	(326,800)	(75,090)
Business combinations	-	(304,846)
Utilisation	3,568	66,132
Reversal	-	1,100
Accretion	(5,208)	(9,801)
Changes in fair value	(1,725)	(4,295)
At end of period	(330,165)	(326,800)

Cash outflows in the six months to 30 June 2023 of $3.6 million are in respect of MOGL deferred consideration and the cash outflows in the year to 31 December 2022 of $66.1 million are in relation to the consideration payable on Petrofac GSA transaction and three quarterly payments in consideration to the MOGL oil price trigger.

Details of movements in contingent and deferred consideration in the year to 31 December 2022 and sensitivities thereon are set out in note 25 of the Group's 2022 Annual Report and Accounts.

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 consolidated statement of profit or loss. Valuation policies and procedures and sensitivities on the fair values of financial instruments are set out in the 2022 Annual Report and Accounts.

All of the Group's assets are pledged as security against borrowings. The accounting classification of each category of financial instruments and their carrying amounts as at 30 June 2023 are set out below:
	Measured at	Mandatorily measured at fair value through	Derivatives designated in hedge	Total carrying
	amortised cost $'000	profit or loss $'000	relationships $'000	amount $'000
Financial assets
Cash and cash equivalents	176,324	-	-	176,324
Trade and other receivables	349,100	-	-	349,100
Derivative financial instruments	-	3,710	153,147	156,857
Financial liabilities
Borrowings	(865,984)	-	-	(865,984)
Trade and other payables	(452,364)	-	-	(452,364)
Lease liability	(42,633)	-	-	(42,633)
Contingent and deferred consideration	(68,626)	(261,539)	-	(330,165)
Derivative financial instruments	-	(20,382)	(12,973)	(33,355)
				(1,042,220)

16. Financial instruments continued The accounting classification of each category of financial instruments and their carrying amounts as at 31 December 2022 are set out below:
	Measured at	Mandatorily measured at fair value through	Derivatives designated in hedge	Total carrying
	amortised cost $'000	profit or loss $'000	relationships $'000	amount $'000
Financial assets
Cash and cash equivalents	253,822	-	-	253,822
Trade and other receivables	359,994	-	-	359,994
Derivative financial instruments	-	7,125	164,924	172,049
Financial liabilities
Borrowings	(1,213,731)	-	-	(1,213,731)
Trade and other payables	(618,460)	-	-	(618,460)
Lease liability	(58,858)	-	-	(58,858)
Contingent and deferred consideration	(67,904)	(258,896)	-	(326,800)
Derivative financial instruments	-	(57,546)	(106,563)	(164,109)
				(1,596,093)
The following table presents the Group's material financial instruments measured at fair value for each hierarchy level as of 30 June 2023:
	Level 1 US$'000	Level 2 US$'000	Level 3 US$'000	Total fair value US$'000
Contingent consideration	-	(46,067)	(215,472)	(261,539)
Derivative financial instrument asset	-	156,857	-	156,857
Derivative financial instrument liability	-	(33,354)	-	(33,354)
The following table presents the Group's material financial instruments measured at fair value for each hierarchy level as of 31 December 2022:
	Level 1 US$'000	Level 2 US$'000	Level 3 US$'000	Total fair value US$'000
Contingent consideration	-	(35,650)	(223,246)	(258,896)
Derivative financial instrument asset	-	172,049	-	172,049
Derivative financial instrument liability	-	(164,109)	-	(164,109)

16. Financial instruments continued

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

Three months ended 30 June Six months ended 30 June
	2023 US$'000	2022 US$'000	2023 US$'000	2022 US$'000
Revaluation of forex forward contracts	3,540	(14,862)	5,000	(19,131)
Revaluation of interest rate swaps	(891)	-	(2,535)	-
Revaluation of commodity hedges	14,341	2,110	36,195	-
	16,990	(12,752)	38,660	(19,131)
Realised loss on forex contracts	(885)	-	(2,967)	-
Realised gain on interest rate swaps	2,324	-	3,850	-
Realised loss on commodity hedges	(4,908)	457	(12,058)	-
Total gain/(loss) on financial instruments	13,521	(12,295)	27,485	(19,131)
Hedging reserve The table below presents the total gain/(loss) on financial instruments that has been disclosed through the statement of comprehensive income:
Three months ended 30 June Six months ended 30 June
Hedging reserve	2023 US$'000	2022 US$'000	2023 US$'000	2022 US$'000
Revaluation gain/(loss) on derivative contracts	352	197,212	83,813	(249,485)
Realised gain/(loss) on derivative contracts	77,106	(111,517)	157,755	(312,156)
Amounts recycled to revenue	(81,613)	84,362	(165,862)	270,173
Amounts recycled to revenue - oil put premiums	2,730	3,645	6,330	7,254
Amounts recycled to revenue - gas put premiums	1,142	16,471	1,142	17,389
Amounts recycled to finance costs - interest put premiums	-	(257)	-	(257)
Total gain/(loss) on financial instruments	(283)	189,916	83,178	(267,082)

17. Derivative financial instruments

30 June

31 December

2023

US$'000

2022

US$'000

Oil swaps - cash flow hedge

7,396

(28,685)

Oil swaps - non-cash flow hedge

(2,891)

(15,027)

Oil collars - cash flow hedge

2,382

(21,983)

Gas swaps - cash flow hedge

36,590

19,797

Gas swaps - non-cash flow hedge

(10,118)

(29,271)

Gas puts - cash flow hedge

8,974

9,746

Gas collars - cash flow hedge

84,832

79,489

Interest rate swaps - non-cash flow hedge

3,698

7,125

FX forwards - non-cash flow hedge

(7,360)

(13,250)

123,503

7,941

Maturity analysis of derivative financial instruments

30 June

2023

US$'000

31 December

2022

US$'000

Non-current assets

9,668

21,191

Current assets

147,189

150,858

Non-current liabilities

(10,071)

(27,440)

Current liabilities

(23,283)

(136,668)

123,503

7,941

Judgements and estimates applied in the valuation of derivative instruments can be found in note 3 to the 2022 Annual Report and Accounts.

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

18. Related party transactions

Gilad Myerson and Alan Bruce, who are Directors of Ithaca Energy plc, are participants in the Company's Share Incentive Plan. On 6 June 2023 both Mr Myerson and Mr Bruce purchased 202 ordinary shares of £0.01 each as a deduction from their respective salaries, with the Company matching 101 ordinary shares of £0.01 each, to each participant at a market rate of £1.48015 per share.

19. Subsequent events

Non-GAAP measures

The Group uses certain performance metrics that are not specifically defined under International Financial Reporting Standards or other generally accepted accounting principles. These non-GAAP measures which are presented

in the H1 2023 condensed consolidated financial statements are defined below:

Adjusted EBITDAX: earnings before interest, tax, put premiums on oil and gas derivative instruments, revaluation of forex forward contracts, revaluation of commodity hedges, depletion depreciation and amortisation, impairment charges or reversals, exploration and evaluation expenditure, fair value gains/(losses) on contingent consideration, gain on bargain purchase and transaction costs. This measure is considered as an indicator of underlying financial performance as it excludes accounting (e.g. depreciation) and financing deductions. It is also commonly used by stakeholders as a comparable metric of core profitability. Adjusted EBITDAX is reconciled to profit after tax as follows:

	H1 2023 $m	H1 2022 $m
Profit after tax	159.6	1,557.7
Taxation charge	89.2	183.7
Gain on bargain purchase	-	(1,324.3)
Depletion, depreciation and amortisation	384.1	297.4
Impairment charge	328.4	7.6
Net finance costs	96.5	97.1
Oil and gas put premiums	7.5	24.8
Revaluation of foreign exchange forward contracts	(5.0)	18.7
Revaluation of commodity hedges	(33.6)	-
Exploration and evaluation expenses	1.3	9.5
Fair value loss on contingent consideration	1.8	14.4
Transaction costs	-	20.8
Historic claim relating to an acquisition	(50.1)	-
Adjusted EBITDAX	979.7	907.4

Adjusted net income: Profit after tax excluding non-cash bargain purchase credits, material impairment charges or reversals and the tax effect of these items where applicable. Adjusted net income, which is presented as it

eliminates items which distort period-on-period comparisons, is reconciled to profit after tax as follows:	H1 2023 $m	H1 2022 $m
Profit after tax	159.6	1,557.7
Gain on bargain purchase	-	(1,324.3)
Impairment charge	328.4	-
Tax credit on impairment charge	(234.8)	-
Adjusted net income	253.2	233.4

Adjusted EPS: Adjusted net income divided by the average number of shares for the period of 1,006.6 million (H1 2022: 1,005.2 million): H1 2023

H1 2022

Non-GAAP measures continued

Adjusted net debt: consists of amounts outstanding under RBL facility and senior secured loan notes less cash and cash equivalents excluding lease liabilities and intragroup debt arrangements or liabilities represented by letters of credit and surety bonds. Adjusted net debt comprises:

	30 June 2023 $m	30 June 2022 $m
RBL drawn facility	(250.0)	(750.0)
Senior unsecured notes	(625.0)	(825.0)
Cash and cash equivalents	176.3	160.4
Adjusted net debt	(698.7)	(1,414.6)
Leverage ratio: adjusted net debt at the end of the period divided by adjusted EBITDAX for the preceding 12 months. The calculations are as follows:
	30 June 2023	30 June 2022
Net debt ($m)	698.7	1,414.6
Adjusted EBITDAX ($m)	1,988.4	1,562.7
Leverage ratio	0.35x	0.91x

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 less restricted cash. Available liquidity comprises:

	30 June 2023 $m	30 June 2022 $m
Cash and cash equivalents	176.3	160.4
Restricted cash	-	(15.0)
Undrawn borrowing facilities	615.0	175.0
Available liquidity	791.3	320.4

Non-GAAP 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. Group free cash flow reconciles to net cash flow from operating activities as follows:

	H1 2023 $m	H1 2022 $m
Net cash flow from operating activities	691.0	989.0
Net cash used in investing activities	(221.6)	(1,203.7)
Add back acquisitions	-	957.5
Bank interest and charges	(49.2)	(54.5)
Group free cash flow	420.2	688.3

Unit operating expenditure: operating costs (excluding over/underlift) including tariff expense less tariff income and tanker costs divided by net production for the period. Operating costs for this calculation reconcile to note 5 as follows:

	H1 2023 $m	H1 2022 $m
Operating costs per note 5	300.7	263.2
Less Tanker costs (included within operating costs in note 5)	(11.6)	(10.2)
Less Tariff income (included within other income in note 4)	(17.0)	(18.6)
Operating costs used to calculate unit operating expenditure	272.1	234.4

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

Other key performance indicators

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

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

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

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