Full year results for the year to 31 December 2024

Harbour Energy plc

Full year results for the year to 31 December 2024

6 March 2025

Harbour Energy plc ("Harbour" or the "Company" or the "Group") today announces its results for the year ended 31 December 2024.

Actuals to 31 December 2024 reflect the completion of the Wintershall Dea transaction on 3 September 2024 and include approximately four months of contribution from the acquired portfolio.

Linda Z Cook, Chief Executive Officer, commented:

"2024 was a transformational year with the completion of the Wintershall Dea transaction, our fourth significant transaction since 2017. As a result, we achieved a step change in the scale, resilience and longevity of our business underpinning the potential for material free cash flow generation well into the next decade. At the same time, we delivered another year of solid operational and financial performance.

"Looking to 2025, we have had a strong start to the year. We continue to prioritise safe and efficient operations, mature our significant 2C resource base and maintain disciplined capital allocation. We remain excited about our future and look forward to realising the potential of our company for all our stakeholders."

Operational highlights

Financial highlights[1]

2025 outlook

Analyst and investor conference call and webcast

Harbour will host a Capital Markets Update today, including a presentation of its 2024 Full Year Results, at 9.00am (UK time). The link to register for the webcast, and the presentation, will be available on www.harbourenergy.com. A replay will be available on Harbour's website shortly after the event.

Details of the Capital Markets Update is outlined in a separate announcement issued this morning.

Forward looking statements

This statement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst Harbour believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond Harbour's control or within Harbour's control where, for example, Harbour decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward-looking statements.

Auditors Report

In accordance with the UK Listing Rule 6.4, the 2024 Auditors Report will be submitted to the Financial Conduct Authority via the National Storage Mechanism today and will be available for inspection at: http://data.fca.org.uk/#/nsm/nationalstoragemechanism

Performance

Solid operational performance materially enhanced by acquisition

Production averaged 258 kboepd (2023: 186 kboepd) during 2024, split c.40 per cent liquids, c.45 per cent European natural gas and c.15 per cent other natural gas.

The c.40 per cent increase in production in 2024 versus 2023 was driven by the acquisition of the Wintershall Dea assets. The acquisition completed in September resulting in our expanded and diversified global portfolio achieving rates of c.500 kboepd in the fourth quarter with material contributions from Norway, the UK and Argentina.

Production was also supported by new projects and development wells coming on-stream in the UK, Argentina and Norway in the second half of the year. Looking to 2025, production on a full year basis is expected to increase to between 450-475 kboepd reflecting a full 12 months' contribution from the acquired Wintershall Dea assets and broadly stable production in the UK. 

Absolute operating costs for 2024 were $1.6 billion (2023: $1.1 billion) which, on a unit of production basis, equated to $16.5/boe (2023: $16.4/boe). This reflects the addition of the lower cost Wintershall Dea portfolio offset by higher unit operating costs at our UK assets due to lower production volumes. In 2025, unit operating costs are expected to reduce to c.$14/boe, benefitting from a full year's contribution from the Wintershall Dea portfolio and continued management of our UK cost base.

2024 capital expenditure including decommissioning totalled $1.8 billion (2023: $1.0 billion). The increase on the prior year reflects the additional capital expenditure associated with the acquired Wintershall Dea assets, and accelerated capital investment in the UK ahead of anticipated changes to the UK fiscal regime. 2025 total capital expenditure is expected to be between $2.4-2.6 billion, reflecting 12 months of the Wintershall Dea portfolio partially offset by materially reduced capital investment in the UK.

Safe and responsible operations

A priority during the year was the safe transfer of the Wintershall Dea portfolio which we achieved in September. However, after consistently improving our safety record, 2024 saw Harbour's total recordable injury rate increase to 1.0 per million hours worked (2023: 0.7), in part reflecting the higher TRIR from the newly acquired assets for the last four months of 2024. Further, we recorded our first-ever Tier 1 process safety event - in Indonesia - along with three Tier 2 events (2023: zero). All events have been rigorously investigated, resulting in actions to improve performance with a particular focus on strengthening our process safety defences in Indonesia and reducing our TRIR in Germany. 

In 2024, our GHG intensity improved to 14 kgCO2e/boe, (2023: 22 kgCO2e/boe) on a net equity, pro forma basis, reflecting the lower emissions intensity of the acquired portfolio. We remain on track to halve our gross operated emissions by 2030.

Maximising the value of our producing assets

The majority of Harbour's capital programme is focused on infrastructure-led opportunities, converting reserves into production and cash flow. These opportunities are typically low risk, high return investments concentrated around our existing production hubs, predominantly in Norway, the UK, Argentina and Germany.

In the UK, 2024 saw Harbour accelerate drilling around its operated hubs, taking advantage of tax credits which expired before year end 2024. This included a return to drilling at the Britannia satellite fields, with the Callanish F6 infill well on-stream in July while, at AELE, the North West Seymour well started up production in September. At Jocelyn South, we made a gas condensate discovery which is being brought on-stream through Harbour's Judy platform post period end in Q1 2025. In addition, in November, Harbour delivered first oil from its operated Talbot project, a three well subsea tie-back to J-Area. The project marked a material milestone for Harbour and was completed on schedule, within budget and with no recordable injuries.

In Norway, we continued to mature our pipeline of high value, short cycle developments. This includes the Harbour-operated Maria Phase 2 project, a four well subsea tieback to existing infrastructure in the Maria field, with production start-up expected during summer 2025, and Dvalin North, a subsea tieback to Dvalin. At Dvalin North, fabrication of the subsea infrastructure is well advanced with development drilling expected to commence in 2026. Harbour has a proven exploration track record in Norway, helping to support reserve replacement. This continued in 2024 with six successes from six exploration and appraisal wells drilled, including the Storjo gas discovery and successful appraisal drilling at Adriana/Sabina, both potential tie-backs to the Skarv hub. 

In Argentina, Harbour holds a material non-operated position and is one of the country's largest gas producers. Production at our offshore CMA-1 concession in the Tierra del Fuego province was supported by the Fenix gas project, comprising a three well unmanned platform tied into existing CMA-1 facilities, which came on-stream ahead of schedule in September. Onshore in the Neuquén province, a multi-pad drilling campaign is ongoing to maintain gas production from our Aguada Pichana Este concession in the Vaca Muerta unconventional play. Production is currently constrained by offtake and local market capacity.

Elsewhere, in Germany, development activities across our three production hubs continued to support stable production. In Egypt, the two Raven West infill wells at West Nile Delta were progressed with production start-up from the first well achieved post period end in February 2025. In Indonesia, Harbour successfully amended its gas sales agreements with the Singapore buyers of Natuna Sea Block A gas, increasing the take-or-pay commitment under a tiered pricing structure, enabling higher production in the second half of 2024.

As at year end 2024, Harbour's proven and probable (2P) reserves on a working interest basis stood at 1.25 bnboe, more than three times higher than that at year end 2023 (2023: 0.36 bnboe). This increase was driven by the addition of 1.0 bnboe from the Wintershall Dea transaction, offsetting the impact of production by more than tenfold. 

Strategic investment options

A broad set of major projects with the potential for material reserves replacement

During 2024, Harbour's 2C resources more than tripled to 1.91 bnboe (2023: 0.52 bnboe), driven by the Wintershall Dea transaction and providing significant reserve replacement opportunities. Organic additions to our 2C resources included exploration success in Indonesia, Norway and the UK, partially offset by revisions to our UK resources, largely the result of changes to the fiscal environment.

Harbour's 2C resources are split c.40 per cent in high value, near infrastructure opportunities, mainly in Norway, the UK and Argentina; c.30 per cent in conventional offshore growth projects in Mexico and Indonesia; with the remaining c.30 per cent in the globally competitive, unconventional Vaca Muerta shale play, onshore Argentina.

In Mexico, through the Wintershall Dea transaction, Harbour increased its interest in the offshore Zama and Kan oil fields and obtained an interest in the offshore Polok and Najaal discoveries. At Zama, FEED on the approved unit development plan was substantially completed in 2024. The Zama partners are now in discussions with Pemex to optimise the development concepts and accelerate first oil. A positive final investment decision at Zama would result in significant 2C resource moving into 2P reserves, replacing the equivalent of over a year's worth of Group production. To the southwest of Zama, appraisal drilling was successfully completed at the Harbour operated Kan oil discovery in Block 30. Work to identify the optimum development concept will be undertaken during 2025.

In August, a multi-well exploration and appraisal campaign across our Andaman Sea acreage in Indonesia was completed and included material gas discoveries at Layaran and Tangkulo on Andaman South (Harbour 20 per cent). In addition, Harbour secured a 60 per cent operated interest in the Central Andaman licence, which includes an extension of the Layaran discovery. Harbour, together with its partners, is now evaluating potential development options, including an accelerated development at Tangkulo.

Argentina represents the largest single component of Harbour's 2C resources, with 770 mmboe of 2C resources. In Q4, Harbour signed a participation agreement to acquire a 15 per cent interest in Southern Energy SA which is looking to develop a 2.45 million tonnes per annum (mtpa) FLNG export project off the coast of the Rio Negro province. It is anticipated that the upstream partners in Southern Energy SA will supply the natural gas for the FLNG project, enabling Harbour's Argentina natural gas to access global LNG export markets. This marks a significant milestone towards unlocking the accelerated development of Harbour's huge natural gas resource in Argentina. Harbour also has an interest in the San Roque licence, which is in the oil window of the Vaca Muerta play, and discussions with partners for the potential development of the resource are ongoing. 

Building a competitive CCS business

Harbour's pipeline of potential CCS projects was strengthened in 2024 by the acquisition of the Wintershall Dea portfolio which added CO2 storage licences in Denmark, Norway and the UK, where we already have our Viking project. 

At Viking, FEED was substantially completed in 2024 and the Development Consent Order (DCO) for the proposed new onshore CO2 pipeline was submitted to the Secretary of State for approval in December. Clarity on commercial terms of the project is anticipated following the conclusion of the UK Government's Critical Spending Review in 2025. Viking's gross storage resource increased to 417 million tonnes as at 31 December 2024 (2023: 300 million tonnes), following the addition of the storage resources of two new CCS licences in Viking's vicinity awarded in 2023.

In December 2024, Harbour together with its partners announced a final investment decision for the Greensand Future project in Denmark, marking Harbour's first CCS project to reach FID. Greensand Future is a small, short cycle project with high returns, driven by the ability to reuse existing infrastructure and defer decommissioning at the Nini field. The project is targeting first injection from 2026. Harbour also has an interest in the cost-advantaged, onshore Greenstore CCS project in Denmark, which is being progressed through the appraisal work programme.

M&A remains a core part of our strategy

With the addition of the Wintershall Dea portfolio, we have a much wider organic investment opportunity set with the potential to support material production well into the next decade. However, M&A remains a core dimension of our strategy, and we will continue to leverage our capabilities in this area to strengthen our portfolio.

The opportunity set for M&A remains rich including potential asset sales from large companies following consolidation, private companies continuing to look for liquidity, and small companies seeking scale, access to capital and relevance with investors. We will however continue to be disciplined, prioritising high-quality assets which lengthen our reserve life, provide a balance of oil and gas, and increase our operational control while, at the same time, are supportive to our investment grade credit ratings.

We will also continue to actively manage our portfolio, ensuring our capital and resources are deployed in line with our strategy. To this end, we agreed the sale of our Vietnam business, post period end, and exited an uncompetitive CCS licence in the UK. 

Strong financial position

The acquisition of the Wintershall Dea assets is expected to deliver a step up in the scale and sustainability of our free cash flow, underpinned by our improved reserve life and expanded resource base. For 2024, Harbour delivered free cash flow of $0.1 billion for the year, before shareholder distributions and one-off acquisition-related costs. Cash flow is impacted by a number of period specific items including a material negative working capital movement, driven by the adjustment of our working capital cycle to the increased size of our business, significant planned shutdowns in Norway in September post completion, and payment of previously deferred UK taxes on 2023 earnings. 

The Board has declared a final dividend of $227.5 million in respect of the 2024 financial year to be paid in May 2025 equating to 13.19 cents per ordinary share, subject to shareholder approval. This is in line with the Board's commitment at the time of acquisition announcement to increase the annual dividend to $455 million and signals the Board's ongoing confidence in the scale and longevity of our free cash flow generation.

Harbour's debt structure was transformed over 2024 with the reserves-based debt facility replaced with unsecured, lower cost and more flexible bank facilities and bonds. Harbour's corporate and senior bond credit ratings were upgraded to investment grade from all leading credit rating agencies and in October, Harbour issued €1.6 billion of Euro denominated, investment grade bonds. At year-end 2024, net debt (before unamortised fees) stood at $4.7 billion with leverage, on a pro forma basis, of 0.7x.

Since becoming a public company in 2021, our sustained operational and financial delivery along with our disciplined approach to capital allocation enabled us to repay c.$2.9 billion of debt and return c.$1.2 billion to shareholders while retaining the flexibility to complete a transformational acquisition.

2025 Annual General Meeting (AGM) and Board update

Harbour Energy's Annual General Meeting will be held on Thursday 8 May 2025. The Notice of Meeting will be published alongside the full annual report and accounts in March 2025. Andy Hopwood will be standing down from the Board at the close of the AGM and will not therefore be put forward for re-election by shareholders. 

Harbour plans to seek authority from its shareholders at its upcoming AGM to conduct an off-market buyback of shares held by BASF, its largest shareholder. While BASF remain a significant shareholder, it is Harbour's intention to seek such authority each year from its shareholders to retain maximum flexibility. The Company is not obliged to exercise the authority or proceed with an off-market buyback once the authority has been approved.

Outlook1

Looking to 2025, Harbour will benefit from a full year's contribution from the Wintershall Dea assets resulting in another step up in production, a reduction in unit operating costs and increased free cash flow generation. In these times of continued geopolitical uncertainty and commodity price volatility, the resilience our more diverse and lower cost portfolio provides is ever more important. It is also why we aim for a balance of oil and gas and employ a disciplined and consistent approach to hedging. At Brent oil prices of $80/bbl and UK and European natural gas prices of $13/mscf, we expect to generate free cash flow of c. $1.0 billion1 in 2025. With a $5/bbl change in Brent oil prices or $1/mscf change in European natural gas prices impacting free cash flow by c.$115 million, we still expect to generate material free cash flow at current prices.

As we look to the future, we will continue to prioritise safe and efficient operations as we complete the integration of our new Business Units, mature our significant 2C resource base and maintain disciplined capital allocation. Our high-quality portfolio with significant optionality, financial strength and strong management team mean we are well-positioned for continued execution of our strategy and delivery of competitive shareholder returns.

1 2025 guidance/outlook assumes a US dollar to GBP sterling exchange rate of $1.25/£, US dollar to Euro exchange rate of $1.1/€ and a Norwegian NOK to US dollar exchange rate of NOK11/$. Free cash flow sensitivity assumes mid-point of production and capex guidance. A 1:1 conversion rate for $/mmbtu to $/mscf has been assumed.

Financial Review

Summary of financial results

1 2023 results throughout this financial review have been restated with respect to the Vietnam asset held for sale classification given the previous sales process did not conclude.

2 2024 reflects the impact of the Wintershall Dea portfolio. Europe includes UK, Norway and Germany with 2023 comparative restated to $/mscf. For Other gas, the 2023 comparative relates solely to the Indonesia business.

3 See Glossary for the definition of non-IFRS measures. Reconciliations between IFRS and non-IFRS measures are provided within this financial review.

Income Statement

1 Non-IFRS measure - see Glossary for the definition.

Revenue and other income

Total revenue and other income increased to $6,226 million (2023: $3,751 million). This was driven by higher production, primarily due to the Wintershall Dea transaction with the newly acquired portfolio contributing $2,021 million in the four months post completion, and increased commodity prices, especially European natural gas.

Revenue earned from hydrocarbon production activities increased to $6,097 million (2023: $3,680 million) after realised hedging losses of $18 million (2023: $911 million). This increase was mainly driven by higher production due to the acquired portfolio and higher post-hedging realised European natural gas prices. Of Harbour's total annual production of 258 kboepd and revenue of $6,226 million, 98 kboepd and $2,021 million revenue was delivered by the acquired portfolio in the four months post completion. 

Crude oil sales increased to $2,878 million (2023: $2,086 million) after realised hedging gains of $32 million (2023: losses of $93 million). This was driven by higher production volumes from the acquired portfolio as well as a higher realised post-hedging oil price of $82/bbl (2023: $78/bbl). Of Harbour's total annual crude oil production of 90 kboepd and total $2,878 million post-hedging crude oil revenue, 27 kboepd and $590 million was delivered by the acquired portfolio in the four months post completion.

Gas revenue was $2,936 million (2023: $1,415 million), split between European gas revenue of $2,644 million (2023: $1,284 million) including realised hedging losses of $50 million (2023: $818 million) and other gas revenue of $292 million (2023: $131 million). The increase in both categories is primarily due to the acquired portfolio. Of Harbour's total annual gas production of 149 kboepd, 67 kboepd was delivered by the acquired portfolio in the four months post completion with associated European and Other post-hedging gas revenue of $1,121 million and $174 million respectively. The realised post-hedging price for our European and other gas was $11/mscf (2023: $7/mscf) and $4/mscf (2023: $13/mscf), respectively. The fall in the realised other gas price reflects the lower price environments of the acquired portfolio.

Condensate revenue was $283 million (2023: $179 million) and tariff income $61 million (2023: $35 million). Other income amounted to $68 million (2023: $36 million) which includes partner recovery on lease obligations and government subsidies in Argentina.

Cost of operations

Cost of operations increased to $3,613 million (2023: $2,376 million, as restated) driven primarily by costs associated with the acquired assets and a negative movement in hydrocarbon inventories and over/underlift. Cost of operations includes operating costs of $1,612 million (2023: $1,171 million) and depreciation, depletion and amortisation expense of $1,704 million (2023: $1,414 million, as restated) as discussed below along with over/underlift movements and other items for an expense of $297 million (2023: $209 million, credit).

1 Non-IFRS measure - see Glossary for the definition.

Total operating costs increased to $1,555 million (2023: $1,115 million) driven by the four-month contribution of the acquired portfolio. However, they were materially unchanged on a unit of production basis at $16.5/boe (2023: $16.4/boe).

Depreciation, depletion and amortisation unit expense, which reflects the capitalised costs of producing assets divided by produced volumes, decreased to $18.5/boe (2023: $21.3/boe, as restated).

General and administrative expenses

General and administrative expenses amounted to $352 million (2023: $149 million). The increase was driven by the enlarged group, including expansion of our corporate centre, and additional and one-off M&A transaction costs of $119 million (2023: $33 million) associated with the Wintershall Dea acquisition.

EBITDAX1

EBITDAX1 was $4,006 million (2023: $2,675 million, as restated), with the increase driven by the four-month contribution of the acquired assets.

1 Non-IFRS measure - see Glossary for the definition.

The Group has recognised a net pre-tax impairment charge on property, plant and equipment of $352 million (2023: $176 million, as restated). Of this, $174 million was in respect of revisions to decommissioning estimates on mainly non-producing assets with no remaining book value. The remainder largely relates to impairments on three fields in the UK due to impacts from further changes to the UK Energy Profits Levy (EPL) and changes in life of field outlook.

During the year, the Group expensed $241 million (2023: $93 million) of exploration and appraisal activities. This covers exploration write-off expense of $173 million (2023: $57 million) including write-off of costs associated with projects in the UK ($79 million) and licence relinquishments in Norway ($64 million), and $40 million (2023: $29 million) costs primarily associated with carbon capture and storage activities.

Net financing costs

Finance income amounted to $173 million (2023: $104 million). The increase compared to 2023 is primarily due to unrealised foreign exchange gains of $118 million during the year which predominantly arose on the revaluation of the Group's tax liabilities due to the strengthening of the US dollar in the year.

Finance expenses amounted to $602 million (2023: $420 million). This included:

Earnings and taxation

Loss after tax amounted to $93 million (2023: $45 million profit, as restated). This resulted in a loss per ordinary voting share of 10 cents (2023: 6 cents, earnings, as restated) after taking into account the weighted average number of ordinary voting shares in issue of 990 million (2023: 804 million) following the issue of shares to BASF and LetterOne as part of the acquisition. After taking into consideration $15 million (2023: $nil) attributable to subordinated notes investors, loss after tax attributable to equity owners of the company amounted to $108 million (2023: $45 million gain attributable to equity owners of the company).

Harbour's tax expense increased to $1,312 million in 2024 (2023: $571 million, as restated), primarily driven by higher pre-tax profits resulting from the additional earnings contributed by the acquisition and specific UK adjustments due to the EPL. The tax expense comprises a current tax expense of $1,415 million (2023: $677 million) and a deferred tax credit of $103 million (2023: $106 million, credit).

The effective tax rate of 108 per cent (2023: 93 per cent, as restated) is materially higher than the statutory tax rate of 78 per cent (2023: 75 per cent). This is primarily due to several UK-specific exceptional items. Key contributors include the increase in UK decommissioning obligations in the period (15 per cent), the impairment of tangible and intangible assets in the UK (4 per cent) and the increase in the EPL rate from 35 per cent to 38 per cent (6 per cent).

Shareholder distributions

A final dividend with respect to 2023 of 13.00 cents per ordinary share was proposed on 7 March 2024 and approved by shareholders at the AGM on 9 May 2024. The dividend was paid on 22 May 2024 to all shareholders on the register as at 12 April 2024, totaling $100 million. An interim dividend was announced on 8 August 2024 at 13 cents per share and was paid on 25 September 2024 at a value of $99 million[2].

The Board is proposing a final dividend with respect to 2024 of 13.19 cents per voting ordinary share to be paid in pound sterling at the spot rate prevailing on the record date. This dividend is subject to shareholder approval at the AGM, to be held on 8 May 2025. If approved, the dividend will be paid on 21 May 2025 to shareholders as of 11 April 2025. The ex-dividend date is 10 April 2025. A dividend reinvestment plan (DRIP) is available to shareholders who would prefer to invest their dividends in the shares of the company. The last date to elect for the DRIP in respect of this dividend is 29 April 2025.

A DRIP is provided by Equiniti Financial Services Limited. The DRIP enables the Company's shareholders to elect to have their cash dividend payments used to purchase the Company's shares. More information can be found at www.shareview.co.uk/info/drip.

Statement of Financial Position

Assets

The increase in total assets of $20,405 million to $30,321 million (2023: $9,916 million, as restated) is mainly as a result of the acquisition, primarily property, plant and equipment of $10,011 million, exploration, evaluation and other intangible assets of $4,409 million and goodwill arising from purchase price allocation exercise of $3,845 million. Total assets include assets held for sale in respect of the Vietnam disposal of $277 million.

The goodwill of $3,845 million arises principally from the requirement to recognise undiscounted deferred tax liabilities for the difference between the fair value and the tax base of the acquired assets and liabilities assumed in the business combination. This goodwill will ultimately be charged to the income statement over time as an impairment charge, primarily as the deferred tax balances unwind.

Liabilities

The increase in total liabilities of $15,707 million to $24,070 million (2023: $8,363 million, as restated) is primarily driven by the recognition of the liabilities assumed as a result of the acquisition. Liabilities assumed included deferred tax liabilities of $5,500 million, borrowings net of transaction fees of $3,079 million, provisions of $2,940 million, trade and other payables of $1,159 million and current tax liabilities of $1,128 million. Additionally, the Group increased its borrowings by $1,914 million being $250 million drawn under the $3 billion revolving credit facility (RCF) and new issue of Euro-denominated bonds of $1,664 million (nominal €1,600 million). Total liabilities included liabilities directly associated with assets held for sale in respect of the Vietnam disposal of $233 million.

The net deferred tax position on the statement of financial position is a liability of $6,091 million (2023: $1,290 million, as restated). This is primarily made up of a deferred tax liability in respect of the future profits which will flow from our property, plant and equipment of $9,600 million offset by a deferred tax asset in respect of future tax relief on decommissioning spend of $2,791 million, fair value losses on derivatives of $336 million and tax losses of $288 million (before adjustment for assets held for sale).

Equity and reserves

Total equity increased by $4,698 million to $6,251 million (2023: $1,553 million, as restated) mainly due to the recognition of merger reserve of $3,457 million associated with the 921 million shares issued to BASF and LetterOne as part of the acquisition as well as the recognition of subordinated notes that were assumed as part of the acquisition of $1,548 million. Movements in equity also included unfavourable post-tax fair value movements on cash flow hedges of $166 million (2023: favourable of $792 million) and gains on currency translation of $130 million (2023: $103 million) all recognised in other comprehensive income. Equity was reduced by dividend payments of $199 million (2023: $190 million) in addition to the loss for the year.

Net debt

As at 31 December 2024, net debt of $4,424 million (2023: $207 million, as restated). This consisted of borrowings amounting to $5,512 million (2023: $500 million) net of unamortised fees of $283 million (2023: $7 million) less cash balances of $805 million (2023: $286 million, as restated). During the year the RBL facility was replaced by the RCF and, as at 31 December 2024, $250 million was outstanding. At the end of 2023 the drawdown in the RBL was $nil and there were $61 million of unamortised fees classified in debtors which were expensed in 2024. As part of the acquisition, $3,079 million worth of borrowings were assumed, and a $1,500 million bridge facility was used to complete the acquisition. This was subsequently refinanced into two Euro-denominated bonds amounting to $1,664 million (€900 million and €700 million, respectively). In addition, Harbour had surety bonds of $675 million (£540 million) at year end which provide cover for decommissioning securities.

Available liquidity, comprising undrawn portion of the RCF facility of $1.9 billion ($250 million debt and $0.9 billion letters of credit for decommissioning have been drawn) plus cash balances of $0.8 billion (2023: $0.3 billion), was $2.7 billion (2023: $1.6 billion) at the end of the year.

As at 31 December 2024, the leverage ratio1 was 1.1x (2023: 0.1x) which has increased primarily as a result of the significant increase in net debt due to the acquisition, as well as only four months of EBITDAX contribution from the acquired portfolio. The balance sheet is in a strong position supported by the RCF facility and investment grade credit ratings.

1 Non-IFRS measure - see Glossary for the definition.

Derivative financial instruments

We carry out hedging activity to manage commodity price risk. We have entered into both a series of fixed-price sales agreements and a financial hedging programme for both oil and gas, consisting of swap and option instruments. Hedges realised to date are in respect of both crude oil and natural gas.

The current hedging programme is shown below:

As at 31 December 2024, our financial hedging programme on commodity derivative instruments showed a pre-tax negative mark-to-market fair value of $476 million (2023: $18 million). Most of the commodity derivatives were designated as cash flow hedges, therefore, changes in fair value were reported in other comprehensive income.

For foreign exchange derivative instruments, the pre-tax negative mark-to-market fair value was $198 million (2023: $nil). Of this value, $173 million related to the cross-currency interest rate swaps designated as cash flow hedges relating to the euro bonds where €2.4 billion was hedged at a forward rate of between 1.1015 and 1.1209. The remaining $25 million related to FX forward contracts designated as fair value through income statement.

Acquisition of Wintershall Dea assets

On 3 September 2024, the Group closed the transaction to acquire substantially all of Wintershall Dea's upstream assets from BASF and LetterOne, including those in Norway, Germany, Denmark, Argentina, Mexico, Egypt, Libya and Algeria as well as Wintershall Dea's CCS licences in Europe. Under the purchase price allocation that was performed, the fair values of identifiable assets and liabilities of Wintershall Dea, and resulting goodwill, are as follows:

The goodwill of $3,845 million arises principally from the requirement to recognise undiscounted deferred taxes liabilities for the difference between the fair value and the tax base of the acquired assets and liabilities assumed in the business combination. This goodwill will ultimately be charged to the income statement over time as an impairment charge, primarily as the deferred tax balances unwind.

From the date of acquisition, the acquired assets contributed $2,021 million of revenue and $867 million to profit before tax from continuing operations of the Group. If the combination had taken place at the beginning of the year, revenue from continuing operations would have been $10,516 million and profit before tax from continuing operations for the Group would have been $3,017 million.

Statement of cash flows1

1 Table excludes financing activities related to debt principal movements.

2 Excludes net expenditure on business combinations of ($1,044 million, note 14 of the financial statements).

3 Interest and lease interest and capital payments only, excludes shareholder distributions.

4 Non-IFRS measure - see Glossary for the definition.

Net operating cashflow before tax was $3,114 million (2023: $2,588 million, as restated) reflecting the enlarged group. The timing and magnitude of tax payments impacted net cash from operating activities after tax which amounted to $1,615 million (2023: $2,150 million, as restated). Tax payments during the year were $1,499 million compared to $438 million in 2023 due to the enlarged portfolio and balancing payments for prior year UK EPL. UK EPL payments amounted to $732 million (2023: $402 million). 

Cash flow working capital movements were negative $494 million (2023: positive $205 million) as the increase in production within the enlarged business coupled with overdue receivables in Egypt and Mexico means we carry a materially higher net working capital position on our balance sheet at year end.

Capital investment was $1,322 million (2023: $718 million) which included property, plant and equipment additions of $884 million (2023: $496 million), exploration and evaluation additions of $359 million (2023: $202 million) and other intangible additions of $79 million (2023: $20 million). Cash outflow from financing activities totalled $500 million (2023: $409 million) split between interest payments of $181 million (2023: $150 million) and lease payments of $319 million (2023: $259 million).

Free cash flow was $118 million outflow after acquisition related costs of $235 million. Before these acquisition related costs free cash flow was $117 million inflow.

Shareholder distributions consist of dividends paid of $199 million (2023: $190 million). In 2023, shareholder distributions also included $249 million related to the repurchase of Harbour's own shares.

Cash and cash equivalent balances were $805 million (2023: $286 million, as restated) at the end of the year.

Capital investment is defined as additions to property, plant and equipment, fixtures and fittings and intangible exploration and evaluation assets, excluding changes to decommissioning assets.

1 Non-IFRS measure - see Glossary for the definition.

During the period, the Group incurred total capital expenditure of $1,828 million (2023: $989 million), split by capital investment $1,544 million (2023: $721 million) and decommissioning spend $284 million (2023: $268 million) respectively.

The capital investment for operated assets mainly consisted of; in the UK, project activity at Talbot (J-Area) and development drilling at J-Area, Callanish F6 (GBA), Greater Britannia appraisal at Leverett and discoveries at Gilderoy and Jocelyn South and North West Seymour (AELE); in Norway, multiple tieback projects at Maria, Dvalin North, Irpa, Alva Nord and Idun North plus Solveig; in Germany, continued development of the Mittelplate field; and in Mexico, the Kan-2 appraisal well.

For partner-operated assets, capital investment consisted primarily of; in the UK, drilling at Buzzard, Clair and Schiehallion; in Norway, drilling continued at Skarv and Njord; in Argentina, the offshore Fenix field development was completed; and in Egypt, drilling continued on the Raven West field infill wells. In Indonesia exploration and appraisal wells were drilled at Layaran and Tangkulo in South Andaman.

Refer to the Operational Review for more detail.

Principal risks

The Directors have identified several changes to the principal risks facing the company over the period, primarily as a result of how the Wintershall Dea transaction has diversified the portfolio and strengthened the financial position of the business. Notably, the principal risk recognised in the 2023 Annual Report as 'Access to capital' has been broadened to 'Financial Discipline' to encompass broader aspects of the financial management and control, while the unmitigated risk level of several principal risks has increased.

Post balance sheet events

On 23 January 2025 Harbour announced it had signed a Sale and Purchase Agreement to sell its Vietnam business, which includes the 53.125% equity interest in the Chim Sáo and Dua production fields, to EnQuest for $84 million. The effective date is 1 January 2024 with completion targeted during 2025. This agreement resulted in the Vietnam business unit being classed as asset held for sale as at 31 December 2024.

On 3 March 2025, the Finance Act 2025 was substantively enacted following its third reading in the UK Parliament. While the substantive enactment has no implications for the current accounting period, it confirms that the extension of the Energy Profits Levy to 31 March 2030 will be reflected in the Group's results for the interim period to 30 June 2025. If the Finance Act 2025 had been substantively enacted at the balance sheet date, the deferred tax liability at the end of the period would have increased by $306 million (further details are provided in note 8 of the financial statements).

Going concern

The Directors considered the going concern assessment period to be up to 31 December 2026. The Group monitors and manages its capital position and its liquidity risk regularly to ensure that it has access to sufficient funds to meet forecast cash requirements. Cash forecasts for management are regularly produced and sensitivities considered based on, but not limited to, the Group's latest life of field production and expenditure forecasts, management's best estimate of future commodity prices based on recent forward curves, adjusted for the Group's hedging programme and the Group's borrowing facilities.

The Group's ongoing capital requirements are financed by its $3.0 billion revolving credit facility (RCF), bonds and subordinated notes $1.6 billion, and surety bonds of $675 million (£540 million) which provide cover for decommissioning securities. The RCF is subject to financial covenants that require the ratio of consolidated total net debt, including letters of credit, to last twelve months (LTM) EBITDAX to be less than 3.5x and LTM EBITDA divided by interest expense to exceed 3.5x. Under the Group's base case, the RCF is forecast to have an undrawn balance of $3.0 billion through 2025 and 2026. When combined with drawn letters of credit and unrestricted cash the headroom is forecasted to be $2.5 billion in 2026 which provides a robust liquidity position.

The base case indicates that the Group is able to operate as a going concern with sufficient headroom and remain in compliance with its loan covenants throughout the assessment period.

The Group's going concern assessment is based on management's best estimate of forward commodity price curves and other economic assumptions, production and expenditure in line with approved asset base case, plus the ongoing capital requirements of the Group that will be financed by free cash flow, the existing RCF and bond financing arrangements. 

In line with the principal risks that have been identified to impact the financial capability of the Group to operate as going concern, a single downside sensitivity scenario has been prepared reflecting a reduction in:

throughout the entire assessment period. Management considers this represents a severe but plausible downside scenario appropriate for assessing going concern and viability.

In this downside scenario when applied individually and in aggregate to the base case forecast, the Group is forecast to have sufficient liquidity headroom throughout the assessment period and to remain in compliance with its financial covenants.

Reverse stress tests have been prepared reflecting reductions in each of commodity price and production parameters, prior to any mitigation strategies, to determine at what levels each would need to reach such that either the lending covenants are breached or liquidity headroom runs out. The results of these reverse stress tests demonstrated the likelihood that a sustained significant fall in commodity prices or a significant fall in production over the assessment period that would be required to cause a risk of funds shortfall or a covenant breach is remote.

Taking the above analysis into account and considering the findings of the work performed to support the statement on the long-term viability of the company and the Group, the Board was satisfied that, for the going concern assessment period, the Group is able to maintain adequate liquidity and comply with its lending covenants up to 31 December 2026 and has therefore adopted the going concern basis for preparing the financial statements.

By order of the Board,

Alexander Krane

Chief Financial Officer

5 March 2024

Financial Statements

Consolidated income statement

For the year ended 31 December 2024

Consolidated statement of comprehensive income

For the year ended 31 December 2024

Consolidated balance sheet

For the year ended 31 December 2024

The following notes form part of these financial statements.

The financial statements were approved by the board of directors and authorised for issue on 5 March 2025 and signed on its behalf by:

Alexander Krane

Chief Financial Officer

Consolidated statement of changes in equity

For the year ended 31 December 2024

1 The increase in the merger reserve represents the difference between the fair value and nominal value of the shares issues as consideration for the acquisition of the Wintershall Dea assets.

2 Disclosed net of deferred tax.

Consolidated statement of cash flows

For the year ended 31 December 2024

Notes to the condensed consolidated financial statements

1. Corporate information

Harbour Energy plc is a limited liability company incorporated in Scotland and listed on the London Stock Exchange. The address of the registered office is 4th Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United Kingdom.

The consolidated financial statements of Harbour Energy plc (Harbour or the company) and all its subsidiaries (the Group) for the year ended 31 December 2024 were authorised for issue by the board of directors on 5 March 2025.

On 3 September 2024, the Group completed the acquisition of substantially all of Wintershall Dea's upstream oil and gas assets, including those in Norway, Germany, Denmark, Argentina, Mexico, Egypt, Libya and Algeria as well as Wintershall Dea's CCS licences in Europe. Under IFRS 3 Business Combinations, the Group is the legal and accounting acquirer as it obtained control over the Wintershall Dea portfolio through the business combination: as it was the entity that issued equity and paid cash to effect the business combination; at completion then existing Harbour Energy shareholders held a majority of voting ordinary shares; and from completion, day-to-day management of the enlarged group has been led by existing Harbour Energy personnel, with no change to the executive directorship.

The Group has designated 1 September 2024 as the acquisition date (beginning of month) rather than the actual acquisition date of 3 September 2024 (during the month) as the events between the designated acquisition date and the actual acquisition date do not result in material changes in the amounts recognised.

The acquired Wintershall Dea portfolio results are fully consolidated in the financial statements from 1 September 2024, and all results prior to this date represent those of the legacy Harbour group only.

The Group's principal activities are the acquisition, exploration, development and production of oil and gas reserves in Norway, the UK, Germany, Mexico, Argentina, North Africa and Southeast Asia.

2. Material accounting policies

Basis of preparation

The consolidated financial statements have been prepared on a going concern basis in accordance with UK-adopted International Accounting Standards (IAS) in conformity with the requirements of the Companies Act 2006. The analysis used by the directors in adopting the going concern basis considers the various plans and commitments of the Group as well as various sensitivity and reverse stress test analyses. The results from the severe but plausible downside sensitivities and reverse stress tests with regard to production and commodity price assumptions, which in management's view reflect two of the principal risks, indicate that material changes within one year that would impact the going concern basis of preparation are remote.

In 2023, the Vietnam Business Unit was classified as an asset held for sale however because this deal did not complete the prior year accounts have been restated to classify the assets and liabilities back to their original balance sheet line items.

The presentation currency of the Group financial information is US dollars and all values in the Group financial information are presented in millions ($ million) and all values are rounded to the nearest 1 million, except where otherwise stated.

The financial statements have been prepared on the historical cost basis, except for certain financial assets and liabilities, including derivative financial instruments, which have been measured at fair value.

The accounting policies which follow set out those policies which apply in preparing the financial statements for the year ended 31 December 2024. All accounting policies are consistent with those adopted and disclosed in Harbour's 2023 Annual Report & Accounts.

Basis of consolidation

The consolidated financial statements comprise the financial statements of the company and its subsidiaries as at 31 December 2024. Subsidiaries are those entities over which the Group has control. Control is achieved where the Group has the power over the subsidiary, has rights, or is exposed to variable returns from the subsidiary and has the ability to use its power to affect its returns. All subsidiaries are 100 per cent owned by the Group, except for four entities holding interests in operations in North Africa and CCS projects which are accounted for as joint operations.

Profit or loss and each component of other comprehensive income (OCI) are attributed to the equity holders of the company and to the subordinated notes investors.

If the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest and other components of equity, while any resultant gain or loss is recognised in profit or loss. Any investment retained is recognised at fair value.

The results of subsidiaries acquired or disposed of during the year are included in the income statement from the effective date of acquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the financial statements of subsidiaries acquired to bring the accounting policies used into line with those used by other members of the Group.

All intra-group transactions and balances have been eliminated on consolidation.

Prior year adjustment

In August 2023, Harbour announced that it had entered into a sale and purchase agreement (SPA) to sell its business in Vietnam, which holds its 53.125 per cent interest in Chim Sáo and Dua producing fields to Big Energy Joint Stock Company for a consideration of $84 million. At 31 December 2023, the assets and liabilities of Vietnam were classified as assets held for sale (AHFS). The transaction, which had a long-stop date of 10 May 2024, could not be completed within the required timeframe, and was subsequently terminated on 13 May 2024, and as a result the Vietnam business was no longer classified as AHFS. The relevant amounts presented as AHFS in the 31 December 2023 consolidated financial statements have been reclassified. Each of the affected financial statement line items has been restated and the impact is summarised in the following table.

Balance sheet at 31 December 2023

From the point of classification as AHFS in August 2023, no depreciation was recorded. In addition, at 31 December 2023, a pre-tax impairment of $38 million was recognised as the fair value less cost to sell was below the carrying amount of the disposal group. As a result of the reclassification from AHFS, the impairment of $38 million has been reversed and additional depreciation covering the period August 2023 to December 2023 has been recorded, on property, plant and equipment of $14 million and on right-of-use assets of $5 million, with net deferred tax of $6 million associated with the impairment reversal and depreciation. As a result of the above adjustments, retained earnings increased by $13 million.

In December 2024, the Group entered into an exclusivity agreement to sell its business in Vietnam to EnQuest for a consideration of $84 million. The transaction has an effective date of 1 January 2024. As a result, the assets and liabilities of Vietnam have been classified as held for sale as at 31 December 2024 (see note 18).

Significant accounting judgements and estimates

The preparation of the Group's financial statements in conformity with UK-adopted IAS requires management to make judgements, estimates and assumptions at the date of the financial statements. Estimates and assumptions are continuously evaluated and are based on management experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to the carrying amount of the assets or liabilities affected in future periods.

In preparing these financial statements, management has made judgements and estimates that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expenses including those that have the potential to materially impact the balance sheet over the next twelve months. Actual results may differ from these estimates.

The significant judgements made by management in applying the Group's accounting policies, and the key sources of estimation uncertainty, were the same as those described in Harbour's 2023 Annual Report & Accounts, with the addition of the purchase price allocation that involved a number of judgements in regard to assessing the fair value of assets and liabilities acquired from Wintershall Dea.

Judgements

Key sources of estimation uncertainty

Details of the Group's critical accounting estimates are set out in these financial statements and are:

Disclosure regarding the judgements and estimates made in assessing the impact of climate change and the energy transition are described below and references to notes in the financial statements are provided.

The results from downside sensitivities prepared with regard to production and commodity price assumptions, which in management's view reflect the principal risks, indicate that material changes that would impact the carrying amounts of assets and liabilities within the next financial year are unlikely.

Impact of climate change on the financial statements and related disclosures

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

Harbour monitors global climate change and energy transition developments and plans. Management recognises there is a general high level of uncertainty about the speed and scale of impacts which, together with limited historical information, provides challenges in the preparation of forecasts and plans with a range of possible future scenarios, which may have the potential to materially impact the balance sheet.

The Group's strategic ambition is to achieve Net Zero by 2050 with an interim target of a 50 per cent reduction in Scope 1 and 2 emissions by 2030 against the 2018 baseline. This will be achieved through several opportunities, including operational efficiency improvements, targeted decarbonisation projects and the eventual cessation of production of mature fields. In addition, the company is investing in the development of CCS projects in the UK and Europe.

All new economic investment decisions include the cost of carbon, and opportunities are assessed on their climate-impact potential and alignment with Harbour Energy's net zero aspiration taking into consideration both GHG volumes and intensity. The acquisition during the year has helped to advance our energy transition objective by strategically shifting our portfolio towards natural gas. Over time this move is expected to notably reduce our greenhouse gas intensity on a net equity basis. The corporate modelling that supports the preparation of the financial statements (such as asset and goodwill impairment assessment, going concern and viability, deferred tax asset recoverability) includes project costs related to CCS, certain decarbonisation projects once sanctioned, other activities to reduce gross operated Scope 1 and 2 GHG emissions, the UK and EU Emissions Trading Scheme costs and carbon offset purchases. Emissions reduction incentives are part of staff remuneration through the annual bonus programme.

Climate change and the energy transition have the potential to significantly impact the accounting estimates adopted by management and therefore the valuation of assets and liabilities reported on the balance sheet. On an ongoing basis, management continues to assess the potential impacts on the significant judgements and estimates used in the preparation of the financial statements. Estimates adopted in the financial statements reflect management's best estimate of future market conditions where, in particular, commodity prices can be volatile. Commodity and carbon price curve assumptions are described below noting that there is consideration given to other assumptions, not exhaustively, such as foreign exchange and discount rates. Notwithstanding the challenges around climate change and the energy transition, it is management's view that the financial statements are consistent with the disclosures in the Strategic Report.

This note provides insight into how Harbour has considered the impact on valuations of key line items in the financial statements and how they could change based on the climate change scenarios and sensitivities considered. The scenarios presented show what the possible impact could be on the financial statements considering both high and low commodity and carbon price outlooks plus discount rates range. Importantly, these climate change scenarios do not form the basis of the preparation of the financial statements but rather indicate how the key assumptions that underpin the financial statements would be impacted by the climate change scenarios. They are also designed to challenge management's perspective on the future business environment. It is recognised that the reality of the nature of progress of energy transition will bring greater levels of disruption and volatility than these external scenarios expect and do not represent management's current best estimate.

The financial statements have been prepared using management's current best estimate for the foreseeable future, based on a range of economic forecasts and represented by the Harbour scenario oil price curve. Management regularly reviews these estimates and assumptions to ensure they align with the latest economic conditions and market information.

Property, plant and equipment, and goodwill

Transitioning to lower carbon energy as the energy transition progresses has the potential to significantly impact future commodity and carbon prices which would, in turn, affect the future operating and capital costs, estimates of cessation of production, useful lives, and consequently the recoverable amount of property, plant and equipment and goodwill.

The non-current assets of the Group, particularly goodwill and oil and gas assets within property, plant and equipment, are considered to be the most sensitive to the energy transition. The carrying value of these assets and goodwill notably increased during the year, primarily attributed to the completion of the Wintershall Dea acquisition in the second half of the year.

Depreciation, estimated useful life and risk of stranded assets

The energy transition and the rate of its progression may impact the remaining lifespan of assets. Typically, the Group's oil and gas assets are depreciated using a unit of production method, which is based on the ratio of production in the year to the commercial proven and probable reserves of the field, considering future capital development expenditures.

As at 31 December 2024, the Group's production plans for existing assets indicated that 44 per cent, 18 per cent and nil per cent of the commercial proven and probable reserves would remain by 2030, 2035, and 2050, respectively. Using the unit of production depreciation method, the carrying amounts for the oil and gas assets are depreciated in line with the depletion of reserves. An evaluation of the oil and gas assets as at 31 December 2024 indicated that the oil and gas assets would experience significant additional depreciation by 2030 and near-complete depreciation by 2035, based on the planned depletion of reserves.

This indicates that a substantial portion of proven and probable reserves are anticipated to be produced by 2035, resulting in lower risk of stranded assets being carried in the consolidated balance sheet. The Group's portfolio management approach aims to mitigate the risk of stranded assets in the event of a faster-than-expected structural decline in demand for oil and gas due to tighter environmental regulations, changes in market demands and global energy demand.

Impairment of property, plant and equipment, and goodwill

The important assumptions for impairment testing of goodwill and oil and gas assets applied to the life of fields production and cost profiles include commodity and carbon prices and discount rates. These key assumptions are carefully assessed by management, both in isolation and in aggregate, to ensure there is a fair and balanced view attained with minimal aggregate bias. These assumptions are inherently uncertain and may ultimately diverge from the actual amounts.

During the current year's impairment testing, the Harbour scenario utilised real long-term commodity price assumptions from 2028 for Brent crude at $78 per barrel (2023: $70 per barrel), UK NBP gas at 80 pence per therm (2023: 90 pence per therm), and a European gas price at 2 per cent higher than UK NBP. These were combined with short-term management forecasts reflecting benchmarked consensus and market forward curves at the year end.

Carbon costs are expected to evolve over time and are subject to significant uncertainty due to the rate of transition and the maturity of regulatory frameworks. For the carbon price, Harbour management's real forward price curve assumption in 2024 is $72 per tonne (2023: $63 per tonne), projected to increase to $182 per tonne (2023: $175 per tonne) by 2030. Sensitivity analysis was conducted using the IEA Net Zero carbon price curve, with a flat assumed foreign exchange rate of pound sterling to US dollar rate of £1:$1.30.

Sensitivity to changes in commodity price assumptions

Sensitivity analyses on the impairment of oil and gas assets and goodwill have been conducted using different commodity price scenarios to demonstrate the potential impact on their net book carrying values. It should be noted that the financial statements are based on the Harbour scenario. Impairment sensitivities have been developed using average -10 per cent and +10 per cent deviations from the Harbour scenario long-term crude and gas prices as well as selected published climate change price curves.

The sensitivity scenarios described below incorporate changes to the commodity price assumptions and assume that all other factors remain unchanged from the Harbour scenario used for the basis of preparation of the financial statements. Importantly, these sensitivities are stated before any management mitigation actions to manage downside risks if the scenarios were to occur.

The Sustainability review within the Annual Report, which will be released on 27 March 2025, discusses both transition and physical risk climate change scenarios. This analysis covers the transition risks and the graphs below show the crude oil, UK NBP gas price curves and European TTF gas price for the period to 2050 for the following IEA scenarios: Net Zero Emissions by 2050, Stated Policies and Announced Pledges.

All the scenario price curves are dependent on factors covering supply, demand, economic and geopolitical events and therefore are inherently uncertain and subject to significant volatility and hence unlikely to reflect the future outcome.

The crude price curves reflect the published IEA price curves for all periods. For UK NBP there are no IEA published price curves therefore management has derived the gas price curves by converting from the published IEA European gas price curve. This was achieved by converting from USD per mbtu to pence per therm and applying other known correlation coefficients between the European and UK gas markets. In addition, for the period 2025-2027, the derived gas price curve matches the Harbour scenario price curve to create a scenario that was considered reasonably plausible.

Pre-development assets are recorded in other intangible assets ahead of demonstration of commerciality and recognition of 2P reserves and hence are not included below, however they are subject to the same management rigour with the corporate models. The majority of such assets are in developing countries with a growing future demand for energy which may reduce the climate change impact from these pre-development assets.

The impact of the sensitivities on the carrying value of oil and gas assets and goodwill in the consolidated balance sheet are shown in the table below.

31 December 2024

31 December 2023

The 2024 results and sensitivities are dominated by the acquired Wintershall Dea portfolio which has substantially increased the goodwill and property, plant and equipment carrying values.

The +/-10 per cent price curves used in the Harbour scenarios adjust long-term prices from 2028.

Under the -10 per cent price to Harbour scenario for crude, there is a pre-tax impairment to oil and gas assets of $323 million and on goodwill an impairment of $45 million. For gas a pre-tax impairment of $2 million and on goodwill an impairment of $37 million.

For crude, under the IEA NZE 2050 scenario, there is a pre-tax impairment to oil and gas assets on of $2,528 million and on goodwill an impairment of $928 million. For gas, there is a pre-tax impairment to oil and gas assets of $131 million and on goodwill an impairment of $1,431 million.

For crude, under the IEA STEPS scenario, there is no pre-tax impairment to oil and gas assets or goodwill. For gas, there is a pre-tax impairment to oil and gas assets of $89 million and on goodwill an impairment of $997 million.

For crude, under the IEA APS scenario, there is a pre-tax impairment to oil and gas assets on of $415 million and on goodwill an impairment of $38 million. For gas there is a pre-tax impairment to oil and gas assets of $35 million and on goodwill an impairment of $1,114 million.

Sensitivity to changes in carbon price assumptions

The sensitivity scenarios described below incorporate changes to the carbon price assumptions and assume that all other factors remain unchanged from the Harbour scenario used for the basis of preparation of the financial statements. This sensitivity is stated before any management mitigation actions to manage downside risks if the scenarios were to occur.

The risk of stranded assets may increase in a higher carbon price scenario. Sensitivity analyses of the carrying value of Harbour's oil and gas assets and goodwill to carbon prices have been conducted based on the IEA NZE 2050 scenario. This aims to demonstrate the resilience of the assets' carrying values to higher long-term carbon prices than those reflected in the consolidated balance sheet.

This analysis covers the transition risks, and the graphs below show the carbon price per tonne for the period to 2050 for the IEA NZE 2050 scenario.

The scenario price curves are dependent on factors covering supply, demand, economic and geopolitical events and therefore are inherently uncertain and subject to significant volatility. As a result, they are unlikely to accurately predict future outcomes.

Applying the IEA NZE 2050 carbon price scenario for the entirety of the useful economic life of the assets resulted in a pre-tax impairment of $9 million (2023: $27 million) to oil and gas assets with no impairment to goodwill under this scenario.

Sensitivity to changes in discount rate assumptions

The discount rate applied for impairment testing of the fair value less cost of disposal is based on a nominal post-tax weighted average cost of capital (WACC) after considering both cost of debt and equity. In 2024, the Group's post-tax discount rate ranging from 8.75 per cent to 14.5 per cent (2023: 9.0 per cent to 12.4 per cent) is derived after considering relevant peer group's post-tax WACC and incorporating segment-specific risk.

Considering the discount rates, the Group deems a 1 per cent rise in the discount rate to be a reasonable potentiality for conducting sensitivity analysis, assuming that all other factors utilised in calculating the recoverable value for the carrying amount of goodwill and oil and gas assets remain unaltered.

A 1 per cent increase in the discount rate would result in an additional impairment of $113 million (2023: $24 million) to the oil and gas assets and on goodwill $10 million (2023: $1 million), and a 1 per cent decrease in the discount rate would have no impact on the impairment charge.

Intangible assets - exploration and evaluation assets

The energy transition has the potential to affect the future development or viability of exploration and evaluation prospects. A significant portion of the Group's exploration and evaluation assets relate to prospects that could either be tied back to existing infrastructure or are in developing countries with a growing future demand for energy which may reduce the climate change impact from these pre-development assets and hence require less capital investment as these assets are less exposed to the impacts of the energy transition compared to large frontier developments. At each balance sheet date, all exploration and evaluation prospects are reviewed against the Group's financial framework to ensure that the continuation of activities is planned and expected. There are no significant judgements and/or critical estimation uncertainty related to climate factors.

See Judgements: Exploration and evaluation expenditure and note 11 to the financial statements for further information.

Deferred tax assets

The potential impact of climate change and energy transition on balance sheet items is uncertain and may lead to significant changes in the estimations of parameters such as the useful life of assets and timing of cessation of production together with their related deferred tax balances.

Deferred tax assets are recognised to the extent that their recovery is considerable probable. In general, it is expected that sufficient forecasted taxable profits will be available for the recovery of deferred tax assets recognised at 31 December 2024 and expected to be recovered within the period of production for each asset and after taking into account deferred tax liabilities.

See note 8 Income Taxes for information on deferred tax balances.

Onerous contracts

Contracts may become onerous due to potential loss of revenue or heightened costs stemming from changes in climate change and energy transition regulations.

Management does not foresee any of its existing supply contracts becoming onerous based on the current production level and estimated useful lives of its assets.

Decommissioning cost and provisions

The energy transition may accelerate the decommissioning of assets which would result in an increase in the carrying value of associated decommissioning provisions. Whilst the Group currently expects to incur decommissioning costs over the next 40 years, we anticipate the majority of costs will be incurred between the next 10 to 20 years which will reduce the exposure to the impact of the energy transition.

In the current year, the undiscounted provision for decommissioning and restoration was $10.5 billion (2023: $6.6 billion), recognised on a discounted basis in the consolidated balance sheet.

The discount and inflation rates applied have taken into consideration the applicable rig rates and expected timing of cessation of production on each field. Therefore, the timing of decommissioning expenditures has not been materially brought forward and management do not consider that any reasonable change in the timing of decommissioning expenditure will have a material impact on the decommissioning provisions based on the production plans of existing assets.

Decommissioning cost estimates are based on the current regulatory and external environment. These cost estimates and recoverability of associated deferred tax may change in the future, including as a result of the energy transition. On the basis that all other assumptions in the calculation remain the same, a 10 per cent increase in the cost estimates, and a 10 per cent reduction in the applied discount rates used to assess the final decommissioning obligation, would result in increases to the decommissioning provision of approximately $852 million (2023: $456 million) and $286 million ($440 million), respectively. This change would be principally offset by a change to the value of the associated asset unless the asset is fully depreciated, in which case the change in estimate is recognised directly within the income statement.

See Key sources of estimation uncertainty: Decommissioning costs for further information.

Portfolio changes

Harbour expensed $75 million of costs in relation to CO2 emissions during 2024 (2023: $69 million) with the majority in relation to the UK Emissions Trading Scheme quotas net of allocated free quotas. Quotas in relation to future periods are recognised in intangible assets.

Harbour has investments in a number of CCS projects which are regarded as key to assisting in the energy transition. Projects are recognised in intangible assets once the projects are regarded as technically feasible and commercially viable; prior to this, costs are expensed to the income statement. In 2024 Harbour spent $72 million on CCS activities, capitalising $33 million and expensing $39 million.

Global oil and gas demand considerations

The transition to sustainable energy to mitigate climate change carries the potential to adversely impact commodity prices due to a global decrease in the demand for oil and gas, potentially leading to reduced revenue. Furthermore, investment in clean energy via the adoption of clean energy technologies could elevate production costs, thereby diminishing future profit margins.

Based on prevailing policies and regulatory frameworks, it is anticipated that the growth in global oil demand will decrease, but the demand for oil and gas is projected to continue as a crucial component of the energy mix for the foreseeable future. Natural gas is widely known as a key transition fuel. In the 2024 IEA World Energy Outlook report the demand for natural gas has been revised upwards in all scenarios compared to the previous year, reflecting stronger anticipated demand for gas to meet growth in electricity demand.

During the year, the Group produced 258 kboepd (2023: 186 kboepd), accounting for less than 0.3 per cent of global production. Consequently, the Group does not expect the ability to sell the volume of oil equivalent produced to be directly impacted by shifts in global oil and gas demand. Management remains committed to investing in a diversified oil and gas company.

Cost of carbon allowances

Harbour is part of the European and UK Emissions Trading Schemes (EU and UK ETS) and purchases carbon allowances to meet its regulatory obligations under the schemes. Harbour is entitled to receive a share of free allowances according to UK and EU ETS regulations. Allowances owned in excess of liabilities to date that are available to be used in future periods are recorded in other intangible assets and measured at cost. The costs for purchasing allowances are recorded in costs of operations matching emissions for the period. Accruals that are required for allowances to be purchased are measured at market price.

Segment reporting

The Group's activities consist of one class of business being the acquisition, exploration, development and production of oil and gas reserves and related activities and are split geographically and managed in nine Business Units: namely Norway, the UK, Germany, Mexico, Argentina, North Africa, Southeast Asia, CCS and Corporate.

Joint arrangements

A joint arrangement is one in which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.

Exploration and production operations are usually conducted through joint arrangements with other parties. The Group reviews all joint arrangements and classifies them as either joint operations or joint ventures depending on the rights and obligations of each party to the arrangement and whether the arrangement is structured through a separate vehicle. The Group's interest in joint operations, such as exploration and production arrangements, are accounted for by recognising its:

A joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties that have joint control of the arrangement have the rights to the arrangement's net assets. The results, assets and liabilities of a joint venture are incorporated in the consolidated financial statements using the equity method of accounting. During 2023, the Group did not have any interests in joint ventures. Note 33 describes the Group's interests in joint arrangements as at 31 December 2024.

Where the Group transacts with its joint operations, unrealised profits and losses are eliminated to the extent of the Group's interest in the joint operation.

Foreign currency translation

Each entity in the Group determines its own functional currency, being the currency of the primary economic environment in which the entity operates, and items included in the financial statements of each entity are measured using that functional currency.

The consolidated financial statements are presented in US dollars, which is also the parent company's functional currency.

Transactions recorded in foreign currencies are initially recorded in the entity's functional currency by applying an average rate of exchange. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange ruling at the reporting date. All differences are taken to the income statement.

Non-monetary assets and liabilities denominated in foreign currencies are measured at historic cost based on exchange rates at the date of the initial transaction and subsequently not retranslated.

On consolidation, the assets and liabilities of the Group's operations are translated at exchange rates prevailing on the balance sheet date. Income and expense items are translated at the average monthly exchange rates for the year. Equity is held at historic cost and is not retranslated. The resulting exchange differences are recognised as other comprehensive income and are transferred to the Group's currency translation reserve.

When an overseas operation is disposed of, such translation differences relating to it are recognised as income or expense.

Goodwill arising on the acquisition of a foreign operation and any fair value adjustments to the carrying amounts of assets and liabilities arising on the acquisition are treated as assets and liabilities of the foreign operation and translated at the closing rate.

Goodwill

In the event of a business combination or acquisition of an interest in a joint operation in which the activity constitutes a business, as defined in IFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents the difference between the aggregate of the fair value of purchase consideration transferred at the acquisition date and the fair value of the identifiable assets, liabilities and contingent liabilities acquired, less any non-controlling interest. If however, the fair value of the purchase consideration transferred is lower than the fair value of the identifiable assets and liabilities acquired, less non-controlling interest, the difference is recognised in the income statement as negative goodwill. The Group's goodwill is related to the requirement to recognise deferred tax for the difference between the assigned fair values and the related tax base ('technical goodwill'). The fair value of the Group's licences are based on post-tax cash flows or benchmarked multiples. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Goodwill is initially measured at cost. Following initial recognition, goodwill is measured at cost less any accumulated impairment. Goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group's operating segments. This is subsequently tested for impairment at the Group's operating segment level based on the aggregation of any headroom arising from asset impairment tests. Goodwill is treated as an asset of the relevant entity to which it relates, and accordingly non-US dollar goodwill is translated into US dollars at the closing rate of exchange at each reporting date.

Goodwill, as disclosed in note 10, is not amortised but is reviewed for impairment at least annually by assessing the recoverable amount of the operating segments to which the goodwill relates. Where the carrying amount of the operating segment and related goodwill is higher than the recoverable amount of the operating segment, an impairment loss is recognised in the income statement. The recoverable amounts of the operating segments have been determined on a fair value less costs to sell basis. Impairments are expected to arise as the deferred tax that gave rise to the goodwill initially naturally unwinds in the normal course of business. Impairment losses relating to goodwill cannot be reversed in future periods.

Pre-licence costs

Pre-licence costs are expensed in the period in which they are incurred.

Licence and property acquisition costs

Licence and property acquisition costs paid in connection with a right to explore in an existing exploration area are capitalised as exploration and evaluation costs within intangible assets.

Licence and property acquisition costs are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. If no future activity is planned or the related licence has been relinquished or has expired, the carrying value of the property acquisition costs is written off through the income statement. Upon recognition of proved reserves and internal approval for development, the relevant expenditure is transferred to oil and gas properties within development and production assets.

Exploration and evaluation costs

Once the legal right to explore has been acquired, costs directly associated with the exploration are capitalised as exploration and evaluation (E&E) intangible non-current assets until the exploration is complete and the results have been evaluated. If no potential commercial resources are discovered, the exploration asset is written off.

All such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at least annually. This is to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off through the income statement.

When proved reserves of oil or natural gas are identified and development is sanctioned by management, the relevant capitalised expenditure is first assessed for impairment and, if required, any impairment loss is recognised, then the remaining balance is transferred to oil and gas properties within development and production assets. No amortisation is charged during the exploration and evaluation phase.

Farm-outs - in the exploration and evaluation phase

The Group does not record any expenditure made by the farmee on its account. It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements but re-designates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.

Property, plant and equipment - oil and gas assets

Oil and gas development and production assets are accumulated generally on a field-by-field or cash-generating unit basis where infrastructure is shared. This represents expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets, as outlined in the intangible asset policy above, which is capitalised as oil and gas properties within development and production assets.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation and, for qualifying assets, where relevant, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

An item of development and production expenditure and any significant part initially recognised is derecognised upon disposal or when no future economic benefits are expected. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the income statement.

Expenditure on major maintenance includes refits, inspections or repairs comprising the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset, or part of an asset, that was separately depreciated and is now written off is replaced and it is probable that future economic benefits associated with the item will flow to the Group, the expenditure is capitalised. All other day-to-day repairs and maintenance costs are expensed as incurred.

Depreciation, depletion and amortisation (DD&A) of oil and gas assets

All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is provided generally on a field-by-field or cash-generating unit basis where infrastructure is shared, using the unit of production method by reference to the ratio of production in the year and the related commercial proven and probable reserves of the field, considering future development expenditures necessary to bring those reserves into production.

When there is a change in the estimated total recoverable proven and probable reserves of a field, that change is accounted for in the depreciation charge over the revised remaining proven and probable reserves.

Acquisitions, asset purchases and disposals

Acquisitions of oil and gas properties are accounted for using the acquisition method when the assets acquired, and liabilities assumed constitute a business.

Transactions involving the purchase of an individual field interest, or a group of field interests, which do not constitute a business, are treated as asset purchases irrespective of whether the specific transactions involve the transfer of the field interests directly or the transfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to the assets and liabilities purchased on an appropriate basis.

Proceeds on disposal are applied to the carrying amount of the specific intangible asset or oil and gas property disposed of and any surplus is recorded as a gain on disposal in the income statement.

Decommissioning

A provision for decommissioning is recognised in full when the related facilities are installed. The amount recognised is the present value of the estimated future expenditure. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related oil and gas property. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure is dealt with from the start of the financial year as an adjustment to the opening provision and the oil and gas property. The unwinding of the discount is included as a finance cost.

Non-oil and gas assets

Property, plant and equipment - fixtures and fittings and office equipment

Fixtures and fittings and office equipment are stated at cost less accumulated depreciation and impairment. Depreciation is provided for on a straight-line basis at rates sufficient to write off the cost of the assets less any residual value over their estimated useful economic lives. The depreciation periods for the principal categories of assets are as follows:

Intangible assets

Intangible assets principally comprise IT software/licences and carbon allowances. IT software/licences are carried at cost less any accumulated amortisation. These assets are amortised on a straight-line basis over their useful economic lives of between three and ten years. Carbon allowances are carried at cost and subject to impairment testing.

Impairment of non-current assets (excluding goodwill)

In accordance with IAS 36 Impairment of Assets, impairment tests are carried out on items of property, plant and equipment and intangible assets where there is an indicator of impairment, or an indicator identified that a prior year impairment may have reversed or decreased. Such indications may be based on events or changes in the market environment, or on internal sources of information.

Impairment and reversal indicators

Property, plant and equipment and intangible assets with finite useful lives are only tested for impairment when there is an indication that they may be impaired. This is generally the result of significant changes to the environment in which the assets are operated or when asset performance is significantly lower than expected.

The main impairment indicators used by the Group are described below:

Measurement of recoverable amount

The cash-generating unit (CGU) applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single CGU where the cash inflows of each field are interdependent. The carrying value of each CGU is compared against the expected recoverable amount of the asset, which is primarily determined based on the fair value less cost of disposal (FVLCD) method, where the fair value is determined from the estimated present value of the future net cash flows expected to be derived from production of commercial reserves. Standard valuation techniques are used based on the discount rates that reflect the specific characteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash flows.

Any impairment loss is recorded in the income statement under 'Impairment of property, plant and equipment'. Impairment losses recorded in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets subsequently increases above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a reversal of an impairment loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation) had no impairment loss been recognised in prior periods.

Non-current assets held for sale and discontinued operations

The Group classifies non-current assets and disposal groups as assets held for sale if their carrying amounts will be recovered principally through a sale transaction rather than through continuing use. Non-current assets and disposal groups classified as held for sale are measured at the lower of their carrying amount and fair value less costs to sell. Costs to sell are the incremental costs directly attributable to the disposal group, excluding finance costs and income tax expense. The criteria for held for sale classification is regarded as met only when the sale is highly probable, and the asset or disposal group is available for immediate sale in its present condition. Management must be committed to the plan to sell the asset and the sale expected to be completed within one year from the date of the classification. Actions required to complete the sale should indicate that it is unlikely that significant changes to the sale will be made or that the decision to sell will be withdrawn. Property, plant and equipment and intangible assets are not depreciated or amortised once classified as assets held for sale. Assets and liabilities classified as held for sale are presented separately as current line items in the balance sheet.

Financial assets

The Group uses two criteria to determine the classification of financial assets: the Group's business model and contractual cash flow characteristics of the financial assets. Where appropriate the Group identifies three categories of financial assets: amortised cost, fair value through profit or loss (FVTPL), and fair value through other comprehensive income (FVOCI).

Financial assets held at amortised cost

Financial assets held at amortised cost are initially measured at fair value plus transaction and subsequently measured using the effective interest (EIR) method and are subject to impairment. The EIR amortisation is presented within finance income in the income statement.

Cash and cash equivalents

Cash and cash equivalents comprise cash at bank and other short-term highly liquid investments that are held for the purpose of meeting short-term cash commitments, readily convertible to a known amount of cash and are subject to an insignificant risk of changes in value.

Impairment of financial assets

The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at FVTPL. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Group expects to receive, discounted at an approximation of the original effective interest rate.

ECLs are recognised in two stages:

For trade receivables and contract assets, the Group applies a simplified approach in calculating ECLs as allowed under IFRS 9: Financial Instruments. Provision rates are calculated based on estimates including the probability of default by assessing counterparty credit ratings, as adjusted for forward-looking factors specific to the debtors, the economic environment and the Group's historical credit loss experience.

Credit impaired financial assets

At each reporting date, the Group assesses whether financial assets carried at amortised cost and debt financial assets carried at FVOCI are credit impaired. A financial asset is 'credit impaired' when one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred.

Evidence that a financial asset is credit impaired includes the following observable data:

Financial liabilities

Financial liabilities are classified, at initial recognition, as financial liabilities at fair value through profit or loss, loans and borrowings, payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. All financial liabilities are recognised initially at fair value and, in the case of loans, borrowings and payables, net of directly attributable transaction costs which are capitalised and amortised over the term of the borrowings. Where borrowings have been fully repaid but the borrowing facility remains, directly attributable transaction costs that remain unamortised are presented within current and/or non-current assets.

Borrowings and loans

Interest-bearing bank loans and overdrafts are recorded at the proceeds received, net of direct issue costs. Finance charges, including premiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement using the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the year in which they arise.

Subordinated notes

Through the acquisition of the Wintershall Dea portfolio, the Group now holds two series of subordinated resettable fixed rate notes (subordinated notes) in the aggregate principal amount of €1,500 million, which were transferred to Harbour on completion of the acquisition. The subordinated notes are callable three months prior to the first reset date for the NC2026 series and six months prior to the first reset date for the NC2029 series, and have no maturity.

Based on their characteristics (mainly no mandatory repayment and no obligation to pay a coupon except under certain circumstances specified into the documentation of the subordinated notes) and in compliance with IAS 32: Financial Instruments: Presentation, the subordinated notes are wholly classified as equity. On completing the acquisition, the issued subordinated notes are recognised at fair value, based on market rate as of the acquisition date. Accrued interest payable to the subordinated notes investors increases equity, whereas the distribution of interest payments reduces equity.

Derecognition

A financial liability is derecognised when the obligation under the liability is discharged, cancelled, or expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as the derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised in the income statement.

Derivative financial instruments

The Group uses derivative financial instruments such as forward currency contracts, interest rate swaps, commodity option contracts and commodity swap arrangements, to hedge its foreign currency risks, interest rate risks and commodity price risks, respectively. Derivative financial instruments are initially recognised and subsequently remeasured at fair value. Certain derivative financial instruments are designated as cash flow hedges in line with the Group's risk management policies. When derivatives do not qualify for hedge accounting or are not designated as accounting hedges, changes in the fair value of the instrument are recognised within the income statement.

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

Cash flow hedges

The effective portion of gains and losses arising from the remeasurement of derivative financial instruments designated as cash flow hedges are deferred within other comprehensive income and subsequently transferred to the income statement in the period the hedged transaction is recognised in the income statement. When a hedging instrument is sold or expires, any cumulative gain or loss previously recognised in other comprehensive income remains deferred until the hedged item affects profit or loss or is no longer expected to occur. Any gain or loss relating to the ineffective portion of a cash flow hedge is immediately recognised in the income statement. Hedge ineffectiveness could arise if volumes of the hedging instruments are greater than the hedged item of production, or where the creditworthiness of the counterparty is significant and may dominate the transaction and lead to losses.

Fair values

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It is determined by reference to quoted market prices adjusted for estimated transaction costs that would be incurred in an actual transaction, or by the use of established estimation techniques such as option pricing models and estimated discounted values of cash flows.

For financial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques.

Under IFRS 9 Financial Instruments, embedded derivatives are not separated from a host financial asset, and are classified based on their contractual terms and the Group's business model.

Equity

Share capital

Share capital includes the total net proceeds, both nominal and share premium, on the issue of ordinary (voting and non-voting) and preference shares of the company.

Merger reserve

On 31 March 2021, Harbour Energy plc (formerly Premier Oil plc) acquired Chrysaor Holdings Limited as part of a reverse acquisition. Under the terms of the merger, Premier legally acquired Chrysaor through the issuance of consideration shares whilst Chrysaor was the acquirer for accounting purposes, primarily as a result of its ability to appoint the Board of the enlarged group. The merger reserve primarily represented Premier's opening balance on the legal reserve plus the fair value of the assets and liabilities acquired by Chrysaor. This was subsequently reduced following a capital restructuring in 2022.

On 3 September 2024, the company acquisition of the Wintershall Dea assets met the conditions to recognise the difference between the fair value and nominal value of the shares issues as consideration as merger reserve.

Capital redemption reserve

The capital redemption reserve represents the nominal value of shares transferred following the company's purchase of them.

Cash flow hedge reserve

The cash flow hedge and cost of hedging reserves represent gains and losses on derivatives classified as effective cash flow hedges. Upon the designation of option instruments as hedging instruments, the intrinsic and time value components are separated, with only the intrinsic component being designated as the hedging instrument and the time value component is deferred in other comprehensive income as a 'cost of hedging'.

Currency translation reserve

This reserve comprises exchange differences arising on consolidation of the Group's operations with a functional currency other than the US dollar.

Share-based payments

The Group has applied the requirements of IFRS 2 Share-Based Payment. The Group has share-based awards that are equity and cash settled as defined by IFRS 2. The fair value of the equity-settled awards has been determined at the date of grant of the award allowing for the effect of any market-based conditions. The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Group's estimate of shares that will eventually vest and adjusted for the effect of non-market based vesting conditions. For cash-settled awards, a liability is recognised for the goods or service acquired. This is measured initially at the fair value of the liability. The fair value of the liability is subsequently remeasured at each balance sheet date until the liability is settled, and at the date of settlement, with any changes in fair value recognised in the income statement.

Inventories

All inventories, except for petroleum products, are stated at the lower of cost and net realisable value. The cost of materials is the purchase cost, determined on weighted average cost basis. Petroleum products and underlift and overlift positions are measured at net realisable value using an observable year-end oil or gas market price, and are included in other debtors or creditors, respectively.

Leases

Leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group.

Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets which are no more than ten years.

The Group recognises right-of-use assets and lease liabilities on a gross basis and the recovery of lease costs from joint operations' partners is recorded as other income.

Liabilities arising from a lease are initially measured on a present value basis reflecting the net present value of the fixed lease payments and amounts expected to be payable by the Group assuming leases run to full term. The Group has applied judgement to determine the lease term for some lease contracts in which it is a lessee that include renewal options. The assessment of whether the Group is reasonably certain to exercise such options impacts the lease term, which significantly impacts the amount of lease liabilities and right-of-use assets recognised.

To determine the incremental borrowing rate, the Group where possible:

The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in the lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability is reassessed and adjusted against the right-of-use asset.

Lease payments are allocated between principal and finance cost. The finance cost is charged to the income statement over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.

Payments associated with short-term leases and leases of low value assets are recognised on a straight-line basis as an expense in the income statement. Short-term leases are leases with a lease term of 12 months or less.

For lease arrangements where all partners of a joint operation are considered to share the primary responsibility for lease payments under a lease contract, the Group recognises its share of the respective right-of-use asset and lease liability. This situation is most common where the parties of a joint operation co-sign the lease contract.

The Group recognises a gross lease liability for leases entered into on behalf of a joint operation where it has primary responsibility for making the lease payments. In such instances, if the arrangement between the Group and the joint operation represents a finance sublease, the Group recognises a net investment in sublease for amounts recoverable from non-operators whilst derecognising the respective portion of the gross right-of-use asset. The gross lease liability is retained on the balance sheet.

The net investment in sublease is classified as either trade and other receivables or long-term receivables on the balance sheet according to whether or not the amounts will be recovered within 12 months of the balance sheet date. Finance income is recognised in respect of net investment in subleases.

Provisions for liabilities

A provision is recognised when the Group has a legal or constructive obligation as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.

The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risk specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as part of finance costs in the income statement.

The estimated cost of dismantling and restoring the production and related facilities at the end of the economic life of each field is recognised in full when the related facilities are installed. The amount provided is the present value of the estimated future restoration cost. A non-current asset is also recognised. Any changes to estimated costs or discount rates are dealt with prospectively.

The Group recognises provision for the estimated CO2 emissions costs when actual emissions exceed the emission rights granted and still held. When actual emissions exceed the amount of emission rights granted, a provision is recognised for the exceeding emission rights based on the purchase price of allowances concluded in forward contracts or market quotations at the reporting date.

Group retirement benefits

The Group's various pension plans consist of both defined benefit and defined contribution plans. Payments to defined contribution retirement benefit plans are charged as an expense as they fall due. Payments made to state-managed retirement benefit schemes are dealt with as payments to defined contribution plans where the Group's obligations under the schemes are equivalent to those arising in a defined contribution retirement benefit plan.

The Group operates a defined benefit pension scheme, which requires contributions to be made to a separately administered fund. The cost of providing benefits is determined using the projected unit credit method, with actuarial valuations being carried out at each balance sheet date. Actuarial gains and losses are recognised immediately in the statement of comprehensive income.

The retirement benefit obligation recognised in the balance sheet represents the present value of the defined benefit obligation as reduced by the fair value of plan assets. Any asset resulting from this calculation is limited to the present value of available refunds and reductions in future contributions to the plan.

The Group participates in a legally independent multi-employer plan which is financed by employer and employee contributions as well as the return on plan assets. Since sufficient information is not available for this multi-employer plan, the Group accounts for the plan as if it was a defined contribution plan.

In the case of contribution-based defined benefit pension plans, the Group makes contribution payments to special-purpose funds as well as to life insurances. These contribution payments are recorded as expenses. Furthermore, for some of the Group`s contribution-based defined benefit pension plans, benefit obligations are recognised at the fair value of these funds, so far as the assets exceed the guaranteed minimum benefit amount.

If the assets do not exceed the guaranteed minimum benefit amount, benefit obligations for these contribution-based benefit plans are recognised in the guaranteed minimum benefit amount.

The defined benefit plans are administered by a separate fund that is legally separated from the acquired Wintershall Dea portfolio. The trustees of the pension fund are required by law to act in the interest of the fund and of all relevant stakeholders in the plans.

Trade payables

Initial recognition of trade payables is at fair value. Subsequently they are stated at amortised cost.

Taxes

Current tax

Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and laws used to compute the amount are those that are enacted or substantively enacted at the reporting date in the countries where the Group operates and generates taxable income.

Current income tax related to items recognised directly in other comprehensive income or equity is recognised in other comprehensive income or directly in equity, not in the income statement.

Management periodically evaluates positions taken in the tax returns with respect to situations in which tax regulations are subject to interpretation and establishes provisions where appropriate.

Deferred tax

Deferred taxation is recognised in respect of all temporary differences arising between the tax bases of the assets and liabilities and their carrying amounts in the financial statements with the following exceptions:

When the deferred tax liability arises from the initial recognition of goodwill or an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss and does not give rise to equal taxable and deductible temporary differences

Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when the related asset is realised or liability is settled, based on tax rates and laws enacted or substantively enacted at the reporting date. The carrying amount of the deferred income tax asset is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered. The Group reassesses any unrecognised deferred tax assets each year taking into account changes in oil and gas prices, the Group's proved and probable reserves and resources profile and forecast capital and operating expenditures.

Deferred income tax assets and liabilities are offset only if a legally enforceable right exists to offset current assets against current tax liabilities, the deferred income tax relates to the same tax authority and that same tax authority permits the Group to make a single net payment.

Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive income, in which case the deferred tax is also dealt with in other comprehensive income.

Revenue from contracts with customers

Revenue from contracts with customers is recognised when the Group satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. Revenue associated with the sale of crude oil, natural gas and natural gas liquids (NGLs) is measured based on the consideration specified in contracts with customers with reference to quoted market prices in active markets, adjusted according to specific terms and conditions as applicable according to the sales contracts. The transfer of control of oil, natural gas, natural gas liquids and other items sold by the Group occurs when title passes at the point the customer takes physical delivery. The Group principally satisfies its performance obligations at a point in time and the amounts of revenue recognised relating to performance obligations satisfied over time are not significant.

Over/underlift

Differences between the production sold and the Group's share of production result in an overlift or an underlift. Underlift positions are measured at net realisable value using an observable year-end oil or gas market price. Overlift positions are measured using the sales price that generated the overlift. Underlift and overlift positions are included in receivables or payables respectively. Movements during the accounting period are recognised within cost of sales.

Interest income

Interest income is recognised on an accruals basis, by reference to the principal outstanding and at the effective interest rate applicable.

Borrowing costs

Borrowing costs directly attributable to the acquisition, construction or production of an asset that necessarily takes a substantial period of time to get ready for its intended use or sale (a qualifying asset) are capitalised as part of the cost of the respective assets. Where the funds used to finance a project form part of general borrowings, the amount capitalised is calculated using a weighted average of rates applicable to relevant general borrowings of the Group during the period. All other borrowing costs are recognised in the income statement in the period in which they are incurred.

New accounting standards and interpretations

The Group applied for the first-time certain standards and amendments, which are effective for annual periods beginning on or after 1 January 2024 (unless otherwise stated). The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective.

Management anticipates that all relevant pronouncements will be adopted for the first period beginning on or after the effective date of the pronouncement. New standards, amendments and interpretations not adopted in the current year have not been disclosed as they are not expected to have a material impact on the Group's consolidated financial statements.

Classification of Liabilities as Current or Non-current and Non-current Liabilities with Covenants - Amendments to IAS 1

The amendments specify the requirements for classifying liabilities as current or non-current. The amendments clarify:

In addition, a requirement has been added to disclose when a liability arising from a loan agreement is classified as non-current and the entity's right to defer settlement is contingent on compliance with future covenants within twelve months.

The amendments had no impact on the Group's consolidated financial statements.

Lease Liability in a Sale and Leaseback - Amendments to IFRS 16

The amendments to IFRS 16 specify the requirements that a seller-lessee uses in measuring the lease liability arising in a sale and leaseback transaction, to ensure the seller-lessee does not recognise any amount of the gain or loss that relates to the right of use it retains. The amendments had no impact on the Group's consolidated financial statements.

Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7

The amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures clarify the characteristics of supplier finance arrangements and require additional disclosure of such arrangements. The disclosure requirements in the amendments are intended to assist users of financial statements in understanding the effects of supplier finance arrangements on an entity's liabilities, cash flows and exposure to liquidity risk.

The disclosure requirements in the amendments provide information about the impact of supplier finance arrangements on liabilities and cash flows, including terms and conditions of those arrangements, quantitative information on liabilities related to those arrangements as at the beginning and end of the reporting period and the type and effect of non-cash changes in the carrying amounts of those arrangements.

The amendments had no impact on the Group's consolidated financial statements.

3. Segment information

The chief operating decision maker, who is responsible for allocating resources and assessing performance of the Group's business segments, has been identified as the Chief Executive Officer.

Prior to the acquisition of substantially all of Wintershall Dea's upstream oil and gas assets, the Group's activities consist of one class of business being the acquisition, exploration, development and production of oil and gas reserves and related activities, and were split geographically and managed in two regions, namely 'North Sea' and 'International'. The North Sea segment included the UK and Norwegian continental shelves, and the 'International' segment included Indonesia, Vietnam and Mexico.

The operating segments have been modified following the acquisition of the Wintershall Dea portfolio and changes in the Group's structure effective from September 2024. The operating segments are now divided geographically and managed across nine business units: namely Norway, UK, Germany, Mexico, Argentina, North Africa, Southeast Asia, CCS and Corporate. The CCS segment includes Denmark.

Information on major customers can be found in note 4.