Full-year results for the year to 31 December 2023

Harbour Energy PLC

07 March 2024

 

Harbour Energy plc

Full-year results for the year to 31 December 2023

7 March 2024

Harbour Energy plc ("Harbour" or the "Company" or the "Group") today announces its results for the year ended 31 December 2023.

Harbour operational highlights

§ Production of 186 kboepd (2022: 208 kboepd), split 52% natural gas/48% liquids and within guidance

§ Operating costs of $16/boe (2022: $14/boe), in line with guidance

§ Total recordable injury rate reduced to 0.7 per million hours worked (2022: 0.8)

§ Total 2P reserves and 2C resources increased to 880 mmboe (2022: 865 mmboe) reflecting reserve additions at our operated UK hubs and international exploration success, partially offset by production 

§ Continued momentum on Harbour's UK CCS projects, Viking and Acorn, with both projects awarded Track 2 status; estimated independently verified net CO₂ storage capacity in excess of 200 million tonnes

§ Announced transformational acquisition of the Wintershall Dea asset portfolio (the "Acquisition")

Harbour financial highlights^[1]

§ Realised, post hedging oil and UK gas prices of $78/bbl and 54p/therm (2022: $78/bbl and 86p/therm)

§ Revenue of $3.7 billion (2022: $5.4 billion), reflecting lower natural gas prices and production

§ Profit before tax of $0.6 billion (2022: $2.5 billion); profit after tax of $32 million (2022: $8 million) reflecting an effective tax rate of 95% (2022: 100%)

§ Free cash flow (post-tax, pre-distributions) of $1.0 billion (2022: $2.1 billion)

§ Returned $249[2] million through share buybacks in addition to the $200 million annual dividend, resulting in $1 billion of shareholder distributions since becoming a public company in April 2021

§ Net debt reduced to $0.2 billion (2022: $0.8 billion) with $2.7 billion of net debt reduction since April 2021; leverage reduced to 0.1x (2022: 0.2x)

§ Proposed final dividend of $100 million, in line with $200 million annual dividend policy and equating to 13 cents per share (2022: 12 cents), reflecting dividend per share growth for the full year 2023 of c.9%

2024 and 2025 outlook for Harbour[3]

§ Production guidance of 150-165 kboepd reiterated; production to end February of c.172 kboepd

§ 2024 unit operating cost guidance unchanged at c.$18/boe; total capital expenditure guidance reiterated at $1.2 billion

§ Free cash flow is expected to be marginally positive^[4] in 2024, after estimated cash tax of $1.0 billion, assuming commodity prices of $85/bbl Brent and reduced UK gas prices of 70p/therm

§ For 2025, production levels and operating costs are expected to be similar to 2024 while total capital expenditure is anticipated to be materially lower; Harbour continues to expect to generate significant free cash flow in 2025, resulting in a net cash position by year end

§ Harbour has hedged c.50% and c.25% of its 2024 UK gas and liquids volumes at 67p/therm and $84/bbl and c.25% and c.15% of its 2025 UK gas and liquids volumes at 90p/therm and $77/bbl[5], respectively

Acquisition of Wintershall Dea Asset Portfolio on track to complete in Q4 2024

In December, Harbour announced the acquisition of substantially all of Wintershall Dea's upstream assets for $11.2 billion. The Acquisition will transform Harbour into one of the world's largest and most geographically diverse independent oil and gas companies, adding material positions in Norway, Germany, Argentina and Mexico.

Since the announcement, significant progress has been made on the various approvals and workstreams required for completion:

§ Irrevocable undertakings from shareholders to vote in favour of the Acquisition increased, and currently represents c.35% of Harbour's issued share capital as at 6 March 2024

§ Harbour is on track to publish the prospectus and shareholder circular and to hold the shareholder meeting to approve the Acquisition in Q2 2024

§ Successful bondholder vote to amend certain terms and conditions of Wintershall Dea's c.$4.9 billion investment grade bonds and subordinated notes; over 80% of bondholders participated in the vote and the amendments were approved with significant bondholder support[6]

§ Successful syndication of the proposed $3 billion RCF and $1.5 billion bridge facility with strong support from both existing relationship banks and new banks resulting in oversubscription for both facilities

§ Submission of filings in the relevant jurisdictions for substantially all the regulatory, anti-trust and foreign direct investment approvals required for completion have been made and are progressing as expected

Harbour continues to expect the Acquisition to complete in Q4 2024.

Linda Z Cook, Chief Executive Officer, commented:

"Harbour materially advanced its strategy during 2023. We improved our safety performance, generated material free cash flow, and progressed our international growth opportunities and CCS projects, while maintaining our capital discipline. This enabled continued shareholder returns over and above our base dividend while retaining the flexibility that allowed us to announce a transformational acquisition in December.

"We remain focused on the successful completion of the Wintershall Dea acquisition and the ongoing safe and efficient management of our existing portfolio. We are excited about our future as we look to continue to build a geographically diverse, large scale, independent oil and gas company focused on safe and responsible operations, value creation and shareholder returns."

Enquiries
Harbour Energy plc
Elizabeth Brooks, Head of Investor Relations	[phone]
Brunswick
Patrick Handley, Will Medvei	[phone]

Analyst and investor conference call and webcast

Harbour will host a live webcast today at 9.00am (UK time) which will be available via its website www.harbourenergy.com. A conference call is also available for those unable to join the webcast:

Dial in: [phone]; Access Code: 038726.

A replay will be available on Harbour's website shortly after the event.

Summary of 2023 performance

Operational performance in line with guidance

Production averaged 186 kboepd (2022: 208 kboepd), split 52 per cent natural gas and 48 per cent liquids and in line with guidance. In the UK, we delivered higher production from our operated J-Area hub, supported by new wells on-stream around the end of 2022, while our operated Greater Britannia Area (GBA) continued to outperform expectations. This was offset by the deferral of drilling at partner-operated hubs resulting in fewer wells on-stream later in the year. Production was also impacted by some extended shutdowns in the second half of the year, including at our operated AELE hub and the East Irish Sea assets.

Operating costs for the year were $1.1 billion (2022: $1.1 billion), reflecting active management of our cost structure, including a reduction of staff in our UK operations and the further development of strategic supply chain partnerships and consolidation of contracts.  On a unit of production basis, operating costs were higher at $16/boe (2022: $14/boe) due to lower production. 2023 total capital expenditure was c.$1.0 billion (2022: $0.9 billion) reflecting higher international exploration activity offset in part by the deferral of certain UK opportunities in response to the Energy Profits Levy (EPL).

Safe and responsible operations

In 2023, Harbour delivered an improved safety performance with our Total Recordable Injury Rate reduced to 0.7 (2022: 0.8) per million hours worked.  In addition, we achieved two firsts for Harbour: zero lost time injuries and no serious (Tier 1 or 2) process safety events. This improvement was supported by the company-wide Back to Basics safety campaign initiated in 2022 and now fully embedded throughout our business.

In 2023, our gross operated greenhouse gas emissions reduced to 1.3 million tonnes, representing a c.30 per cent reduction compared to 2018, while our GHG intensity increased to 23 kgCO₂e/boe (2022: 21 kgCO₂e/boe) due to lower production. In January 2024, we signed the United Nations Environment Programme Oil and Gas Methane Partnership 2.0 memorandum of understanding.

During 2023, we successfully plugged and abandoned seven wells bringing the total that Harbour has decommissioned in the UK since 2014 to 161. Harbour also executed numerous seabed clearance and remediation campaigns during the year with onshore dismantlement and processing of removed infrastructure resulting in a recycling rate in excess of 97 per cent.

Maximising the value of our UK producing assets

The majority of Harbour's capital programme is focused on infrastructure-led opportunities designed to optimise production and cash flow. These opportunities are typically low risk, high return, short cycle investments with low GHG intensity.

Within our operated portfolio, we delivered first gas from Tolmount East in November, increasing production rates from Tolmount. At J-Area we completed development drilling at Talbot, a three-well subsea tie-back to the Judy platform with first oil on track for around the end of 2024. We also approved plans to drill a well and retrofit three producing wells for gas lift, targeting improved recovery from the Judy Chalk. At our AELE hub, we approved an infill well at North West Seymour which, together with plant modifications, is expected to extend producing life of the Armada field beyond 2030.

At our operated Greater Britannia Area, Harbour progressed plans to return to drilling at the satellite fields, including an infill well at Callanish which spudded in February 2024, and an appraisal well at Brodgar. In addition, we successfully appraised the Leverett gas discovery in 2023 with the potential development via a subsea tie-back to the Britannia platform now being evaluated.

In our partner-operated portfolio, Beryl production was boosted by initial high rates from two new wells online in the second quarter. However, production on a full year basis was impacted by the operator's decision to pause further subsea and platform drilling in response to the EPL. Production from our West of Shetland assets was supported by four wells drilled across Clair Phase One and Clair Ridge, and a further three wells at Schiehallion. Further drilling at both Clair and Schiehallion is planned for 2024. In addition, the operator continues to optimise the Clair Phase 3 development, which is expected to target Clair South.

As at 31 December 2023, Harbour's proven and probable (2P) reserves on a working interest basis were 361 mmboe (2022: 410 mmboe). This reflects the impact of production (c.68 mmboe)  partially offset by over 20 mmboe of additions across our UK operated J-Area, AELE and GBA hubs following the approval of several new wells.

Attractive international growth projects with potential for material reserves replacement

During 2023 we continued to invest in our international growth opportunities in Mexico and Indonesia.  These have the potential to materially add to our reserves and production and diversify our company over time.

In Mexico, the unit development plan for Zama was approved by the regulator in June and the Zama unit partners have formed an integrated project team to manage the delivery of the development. Good progress was also made on the various commercial agreements. FEED is planned to begin in 2024. The Zama unit has the potential to add reserves equivalent to a year's worth of Harbour's current production. South west of Zama, in Block 30, we made a significant oil discovery with the Kan-1 well in April. The appraisal plan has been approved by the regulator with drilling scheduled for the second half of 2024. In parallel, early engineering studies are being undertaken on a potential Kan development.

In Indonesia, we made a significant gas discovery at Layaran-1 on the South Andaman licence (Harbour 20 per cent interest) in December following the Timpan-1 gas discovery on the Andaman II licence (Harbour 40 per cent operated interest) in 2022. Post year end, the rig moved to drill the Halwa and Gayo prospects on Andaman II where operations are nearing completion. The Halwa-1 well encountered low gas saturations while a small gas discovery has been made at Gayo. Once the Gayo testing programme is complete, the rig will return to South Andaman to drill the shallower Tangkulo prospect to the south of Layaran aiming to prove up additional volumes. In addition, Mubadala, operator of South Andaman, intends to add a fifth well to the campaign to appraise the Layaran discovery.

Harbour's 2C resource increased to 519 mmboe as at 31 December 2023 (2022: 455 mmboe), driven by the addition of the Layaran gas discovery and the Kan oil discovery. As a result, 2023 saw significant growth in our international (non-UK) resource base which now accounts for over 60 per cent of our 2C resources, underpinning future potential reserve replacement and diversification of our company.

Investing in CCS to enable the energy transition

2023 saw good momentum on our two UK CCS projects - the Harbour-led Viking CCS project (Harbour 60 per cent interest) and Acorn (Harbour 30 per cent non-operated interest) with both awarded Track 2 status as part of the UK Government's regulatory process. These projects have a critical role to play in the UK's transition to a lower carbon economy and provide a potential long-term stable income stream for Harbour. 

The Harbour-led Viking project aims to transport and store 10 million tonnes of CO₂ emissions per annum by 2030 and up to 15 million tonnes per annum by 2035, making it one of the largest planned CCS projects in the world.  The project allows for scalable transportation and storage of CO₂ emissions from the Humber, the UK's most industrial emissions intensive region, and also for shipped CO₂ emissions from emitters both in the UK and in Europe.

Material progress on Viking during 2023 included: the Development Consent Order for the 55 km onshore CO₂ transportation pipeline being submitted and accepted for examination; the award of two CCS licences adjacent to Harbour's existing Viking licences, potentially increasing the project's independently verified 300 million tonnes of gross storage capacity by more than 50 per cent; and the project securing its first potential CO₂ shipping customer.  In addition, bp joined the project as a partner in early 2023, with a 40 per cent interest.  Post year end, in January, the FEED contract was awarded, marking another important milestone for Viking as it progresses towards a final investment decision.

The Acorn CCS project plans to transport CO₂ from emitters across Scotland to storage reservoirs offshore, targeting at least five million tonnes of CO₂ per year by 2030. There is also the potential for shipped CO₂ volumes via the Peterhead port. In September 2023, the project was awarded two further CCS licences, covering the East Mey and Acorn East areas. FEED on the Transportation and Storage System is expected to commence in 2024 ahead of a potential investment decision.

Strong financial position and disciplined capital allocation

During 2023, we generated significant free cash flow of c.$1 billion, enabling Harbour to reduce its net debt to $0.2 billion from c.$0.8 billion at the end of 2022. We also successfully amended and extended on favourable terms our RBL facility which was undrawn as at year end. This strong financial position allowed our Board to return $249 million through share buybacks during the year, in addition to our $200 million annual dividend. 

The Board has declared a final dividend of $100 million in respect of the 2023 financial year to be paid in May 2024, equating to 13 cents per share, subject to shareholder approval. Given our share buyback programme, this represents full year on year dividend per share growth of 9 per cent.

Since becoming a public company in 2021, our sustained operational and financial delivery along with our disciplined approach to capital allocation has enabled us to reduce our net debt by $2.7 billion and return c.$1 billion to shareholders while retaining the flexibility to reach agreement on a transformational acquisition.

A transformational acquisition aligned with our strategy

On 21 December 2023, Harbour announced the acquisition of substantially all of Wintershall Dea's upstream oil and gas assets for $11.2 billion. The Acquisition will be funded through porting of existing investment grade bonds from Wintershall Dea, Harbour equity and cash.

The Acquisition is expected to increase our production to c.500 kboepd[7] and adds significant positions in Norway, Germany, Argentina and Mexico. Importantly, the Acquisition will lengthen our reserve life and is accretive across all key metrics on a per share basis, supporting enhanced and sustainable shareholder returns. In addition, the Acquisition advances our energy transition goals, significantly lowering our GHG emissions intensity and expanding our already strong CCS interests into new European markets. Further, the Acquisition is expected to transform our capital structure and deliver investment grade credit ratings upon completion.

The Acquisition is subject to Harbour shareholder approval and we plan to publish a prospectus and shareholder circular setting out the details of the shareholder meeting to approve the Acquisition in the second quarter of 2024. Harbour has received irrevocable undertakings from shareholders which, as at 6 March 2024, represented c.35 per cent of our issued share capital to vote in favour of the acquisition. 

The Acquisition is also subject to, amongst other things, regulatory, anti-trust and foreign direct investment approvals. Substantially all necessary filings required for such approvals have been submitted in the relevant jurisdictions, including in the UK and Germany, and are progressing as expected.  

Regarding the financing of the transaction, in February 2024, Harbour and Wintershall Dea's finance subsidiaries successfully completed a bondholder vote to amend certain terms and conditions of Wintershall Dea's c.$4.9 billion investment grade bonds and subordinated notes to reflect the anticipated group structure. Over 80 per cent of bondholders participated in the vote and the amendments were approved with significant bondholder support across all five bond tranches. The consent is subject to final technical implementation.

In March 2024, Harbour successfully completed the syndication of the $3 billion revolving credit facility (RCF) and $1.5 billion bridge facility with strong support from both existing relationship banks and new banks resulting in oversubscription for both facilities. This reflects strong lender support for Harbour's strategy going forward and is testament to the high-quality credit profile of the pro forma company.

Harbour continues to expect the Acquisition to complete in the fourth quarter of 2024.

Outlook

On a standalone basis and before any contribution from the Acquisition and assuming a Brent oil price of $85/bbl and a reduced UK gas price of 70p/therm[8], we expect to be marginally free cash flow positive for 2024. This is after a higher capital investment programme to support future production and c.$1.0 billion of cash tax payments, reflecting the full utilisation of our available UK corporate tax losses in the first half of 2024 and phasing of UK EPL payments.

Looking to 2025, we anticipate production remaining broadly stable, with increased volumes from new wells and projects substantially offsetting natural decline, and our total capital expenditure to be materially lower. As a result, we expect to generate significantly higher free cash flow in 2025 compared to 2024 and to build a net cash position by year end. 

As we look to the future, we have a strong balance sheet, our asset base is generating robust cash flow and we have good momentum on our organic growth opportunities and UK CCS projects. At the same time, we are on track to complete the acquisition of the Wintershall Dea asset portfolio in the fourth quarter of 2024 which will transform our scale and asset diversification as well as our capital structure.

Our ambition to grow through M&A remains unchanged and we are well positioned for future opportunities. However, we will maintain our disciplined approach to capital allocation, balancing any future growth opportunities alongside a commitment to an investment grade balance sheet and competitive shareholder returns. 

Financial Review

Summary of financial results

Analysis of these key metrics are discussed in detail across the following pages of the Financial Review.

	Units	2023	2022
Production and post-hedging realised prices
Production	kboepd	186	208
Crude oil	$/boe	78	78
UK natural gas	p/therm	54	86
Indonesia natural gas	$/mscf	13	14
Income statement
Revenue and other income	$ million	3,751	5,431
EBITDAX1	$ million	2,675	4,011
Profit before taxation	$ million	597	2,462
Profit after taxation	$ million	32	8
Basic earnings per share	cents/share	4	1
Other financial key figures
Total capital expenditure1	$ million	969	908
Operating cash flow	$ million	2,144	3,130
Free cash flow1	$ million	1,042	2,105
Shareholder returns paid1	$ million	439	552
Net debt1	$ million	(213)	(704)
Leverage ratio1	times	0.1	0.2

¹ See Glossary for the definition of non-IFRS measures. Reconciliations between IFRS and non-IFRS measures are provided within this review.

Income Statement

	2023  $ million	2022  $ million
Revenue and other income	3,751	5,431
Cost of operations	(2,357)	(2,845)
EBITDAX1	2,675	4,011
Operating profit	913	2,541
Profit before tax	597	2,462
Taxation	(565)	(2,454)
Profit after tax	32	8
	Cents /share	Cents /share
Basic earnings per share	4	1

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

Revenue and other income

Total revenue and other income decreased to $3,751 million (2022: $5,431 million). This was driven by lower commodity prices, especially UK natural gas prices, and reduced production.  

	2023  $million	2022 $million
Revenue and other income	3,751	5,431
Crude oil	2,086	2,792
Gas	1,415	2,322
Condensate	179	238
Tariff income and other revenue	35	38
Other income	36	41

Revenue earned from hydrocarbon production activities decreased to $3,680 million (2022: $5,352 million) after realised hedging losses of $911 million (2022: $3,185 million). This decrease was mainly driven by lower post-hedging realised UK natural gas prices and reduced production volumes. 

Crude oil sales decreased to $2,086 million (2022: $2,792 million) after realised hedging losses of $93 million (2022: $753 million). This was driven by lower production volumes, with our realised post-hedging oil price stable at $78/bbl (2022: $78/bbl).

Gas revenue was $1,415 million (2022: $2,322 million), split between UK natural gas revenue of $1,284 million (2022: $2,142 million) including realised hedging losses of $818 million and international gas revenue of $131 million (2022: $180 million). The realised post-hedging price for our UK and Indonesia gas was 54 pence/therm (2022: 86 pence/therm) and $13/mscf (2022: $14/mscf), respectively.

Other income amounted to $36 million (2022: $41 million) which includes partner recovery on related lease obligations and a receipt related to the Viking CCS Development Agreement entered into with bp in March 2023.

Cost of operations

Cost of operations decreased to $2,357 million (2022: $2,845 million) driven primarily by a positive movement in hydrocarbon inventories and (over)/underlift.

	2023  $million	2022  $million
Operating costs
Field operating costs	1,171	1,114
Non-cash depreciation on non-oil and gas assets	(26)	(26)
Tariff income	(30)	(30)
Total operating costs	1,115	1,058
Operating costs per barrel ($ per barrel)1	16.4	13.9
Movement in over/underlift balances and hydrocarbon inventories	(225)	181
Depreciation, depletion and amortisation (DD&A) before impairment charges
Depreciation of oil and gas properties (cost of operations only)	1,395	1,508
Depreciation of non-oil and gas properties	35	37
Amortisation of intangible assets	-	1
Total DD&A	1,430	1,546
DD&A before impairment charges ($ per barrel)1	21.1	20.4

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

Total operating costs were flat year on year at $1,115 million (2022: $1,058 million) driven by strong cost control in an inflationary environment. Operating costs were higher on a unit of production basis at $16.4/boe (2022: $13.9/boe) due to lower production volumes.

Depreciation, depletion and amortisation (DD&A) unit expense, which reflects the capitalised costs of producing assets divided by produced volumes, was $21.1/boe (2022: $20.4/boe).

EBITDAX¹

EBITDAX¹ was $2,675 million (2022: $4,011 million), with the reduction mainly driven by lower revenue.

	2023  $million	2022  $million
Operating profit	913	2,541
Depreciation, depletion and amortisation	1,430	1,546
Impairment/(impairment reversal) of property, plant and equipment	214	(170)
Impairment of goodwill	25	-
Exploration and evaluation expenditure, and new ventures	36	42
Exploration costs written-off	57	64
Gain on disposal	-	(12)
EBITDAX1	2,675	4,011

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 $214 million (2022: $170 million net reversal). Approximately half of this is in respect of revisions to decommissioning estimates on mainly non-producing assets with no remaining net book value. The balance relates to the announced sale of our Chim Sao asset in Vietnam and an impairment on two UK North Sea assets, one driven primarily by a significant reduction in the gas price outlook compared to the 2022 year-end view, and the other by a revised decommissioning cost profile. In addition, there is a goodwill impairment of $25 million in respect of the Vietnam assets.

During the year, the Group expensed $93 million (2022: $106 million) for exploration and appraisal activities. This includes exploration write-off expense of $57 million (2022: $64 million) mainly in relation to the Ix-1EXP well in Mexico, the JDE well in Norway and costs associated with licence relinquishments and uncommercial well evaluations and a further $29 million (2022: $28 million) in relation to our UK CCS projects.

Net financing costs

Finance income amounted to $104 million (2022: $279 million), including derivative gains of $68 million (2022: $48 million loss) related to changes in the fair value of an embedded derivative within one of the Group's gas contracts. The reduction in finance income compared to 2022 is mainly due to unrealised foreign exchange gains of $202 million in 2022 which predominately arose on the revaluation of open sterling denominated gas hedges as a result of the weakening of sterling against the US dollar in the period.

Finance expenses amounted to $420 million (2022: $358 million). This included interest expense incurred on debt facilities of $42 million (2022: $98 million), the reduction reflecting the impact of lower drawn down debt partially offset by higher interest rates. Other financing expenses include the unwinding of the discount on decommissioning provisions of $156 million (2022: $65 million) which increased due to higher cost estimates and bank and financing fees of $100 million (2022: $91 million) and $57 million of foreign exchange losses as a result of the strengthening of sterling in the year (2022: $202 million of foreign exchange gains).

Earnings and taxation

Profit after tax amounted to $32 million (2022: $8 million profit). This resulted in earnings per share of 4 cents  (2022: 1 cent ) after taking into account the weighted average number of ordinary shares in issue of 804 million (2022: 900 million) following the share buyback programme.

Harbour's tax expense decreased in 2023 to $565 million (2022: $2,454 million). The 2022 charge included a one-off non-cash charge of $1,469 million as a result of the revaluation of the deferred tax position on the balance sheet following the introduction of the Energy Profits Levy (EPL) in the UK. The tax expense is split between a current tax expense of $677 million (2022: $706 million), which includes an EPL current tax charge of $525 million (2022: $326 million) and a deferred tax credit of $112 million (2022: $1,748 million expense including $1,469 million one-off non-cash deferred tax charge).

The effective tax rate is 95 per cent (2022: 100 per cent) materially higher than the standard UK tax rate for the period of 75 per cent. This is in part due to costs which are not fully deductible at the UK statutory rates. If these items had not arisen then we would have expected the effective tax rate for the period to be c.85 per cent.

Shareholder distributions

A final dividend with respect to 2022 of 12 cents per ordinary share was proposed on 9 March 2023 and approved by shareholders at the AGM on 10 May 2023. The dividend was paid on 24 May 2023 to all shareholders on the register as at 14 April 2023, totalling $99 million[9]. An interim dividend was announced on 24 August 2023 at 12 cents per share and was paid on 18 October 2023 at a value of $91 million[10].

In addition to these dividend payments, Harbour completed on 15 February 2023 the remaining $43 million[11] of a $100 million share buyback approved by the Board in November 2022. The Board approved a further $200 million share buyback scheme on 9 March 2023, which concluded on 28 September 2023. The purpose of these share buyback programmes was to reduce the Company's share capital and all ordinary shares purchased as part of the programmes were cancelled. During 2023, we repurchased and cancelled 76.8 million of our own shares at a cost of $249 million3 (2022: $361 million), equating to 9 per cent of our issued share capital at 1 January 2023.

The Board is proposing a final dividend with respect to 2023 of 13 cents per ordinary share to be paid in GBP at the spot rate prevailing on the record date. This dividend is subject to shareholder approval at the AGM, to be held on 9 May 2024. If approved, the dividend will be paid on 22 May 2024 to shareholders on the register as of 12 April 2024. A dividend re-investment 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 26 April 2024.

Statement of Financial Position

	2023  $million	2022  $million
Assets
Non-current assets, excluding deferred taxes	8,074	9,033
Deferred tax assets	7	1,406
Current assets	1,482	2,127
Assets held for sale	334	-
Total assets	9,897	12,566
Liabilities and Equity
Borrowings net of transaction fees	509	1,238
Decommissioning provisions	4,021	4,141
Deferred tax liabilities	1,260	397
Lease creditor	673	825
Derivative liabilities	284	3,450
Other liabilities	1,368	1,494
Liabilities directly associated with assets held for sale	242	-
Total liabilities	8,357	11,545
Equity	1,540	1,021
Total liabilities and equity	9,897	12,566
Net debt	(213)	(704)

Assets

The decrease in total assets of $2,669 million is mainly as a result of the move from a net deferred tax asset position of $1,009 million to a net deferred tax liability of $1,253 million primarily driven by the realisation of the hedging position, reduction in property, plant and equipment (PP&E) of $973 million, lower right-of-use assets, which have reduced by $148 million, partially offset by an increase to intangible assets of $292 million. Total assets included assets held for sale in respect of the Vietnam disposal of $334 million.

Liabilities

The reduction in total liabilities of $3,188 million is mainly driven by a reduction in derivative liabilities of $3,166 million following maturity of contracts and lower commodity prices in the year, a reduction in borrowings of $729 million mainly related to the repayment of the reserves-based lending (RBL) facility and the move to a net deferred tax liability position mentioned above. The decommissioning provision decrease of $120 million was due to changes in cost estimates mainly driven by increased discount rates and spend in the year, partially offset by the unwinding of the discount. Total liabilities included liabilities directly associated with assets held for sale in respect of the Vietnam disposal of $242 million.

The net deferred tax position on the balance sheet is a liability of $1,253 million. This is primarily made up of a deferred tax liability in respect of the future profits which will flow from our PP&E of $2,901 million offset by a deferred tax asset in respect of future tax relief on decommissioning spend of $1,574 million. Whilst our future UK profits in the period to 31 March 2028 will be subject to 75 per cent taxation due to the EPL, UK decommissioning spend is not deductible for EPL and so relieved at 40 per cent.

Equity and reserves

Total equity increased mainly due to the gains in comprehensive income related to favourable fair market value movements on cash flow hedges of $3,168 million (2022: $269 million), gains on currency translation of $103 million (2022: losses of $198 million), offset by movements in tax on cash flow hedges of $2,376 million (2022: gains of $1,006 million), share buybacks of $249 million (2022: $361 million) and dividend payments of $190 million (2022: $191 million) made in the year. Retained earnings increased by the profit after tax.

Net debt

As at 31 December 2023, net debt of $213 million (2022: $704 million) consisted of cash balances of $280 million (2022: $500 million), net of the $500 million bond (2022: $500 million) adjusted for unamortised fees of $7 million (2022: $9 million). Following net repayments of the RBL facility of $775 million and settlement in full of the exploration finance facility (EFF) of $11 million, the RBL facility is $nil (2022: $775 million less unamortised fees of $73 million) and the EFF is $nil (2022: $11 million). The remaining $61 million unamortised fees for the RBL have been reclassified to debtors.

The RBL facility was amended and extended in November 2023 which resulted in the debt availability of $1.3 billion. Available liquidity, being undrawn RBL facility plus cash balances of $0.3 billion, was $1.6 billion at the end of the year.

As at 31 December 2023, the leverage ratio¹ was 0.1x (2022: 0.2x) which has reduced primarily as a result of repayments of the RBL facility during the year resulting in nil drawdown at year end.

	2023  $million	2022  $million
Leverage ratio
Net debt1	213	704
EBITDAX1	2,675	4,010
Leverage ratio1	0.1x	0.2x

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

Derivative financial instruments

We carry out hedging activity to manage commodity price risk, to ensure we comply with the requirements of the RBL facility and to ensure there is sufficient funding for future investments. We have entered into a series of fixed-price sales agreements and a financial hedging programme for both oil and gas, consisting of swap and option instruments. Our future production volumes are hedged under the physical and financial arrangements in place at 31 December 2023. These are set out in the following table. Hedges realised to date are in respect of both crude oil and natural gas.

The current hedging programme is shown below:

Hedge position		2024	2025	2026
Oil
Volume hedged (mmboe)		7.32	4.38	-
Average price hedged ($/bbl)		84.37	77.35	-
UK natural gas
Volume hedged (mmboe)		13.08	7.38	1.55
Average priced hedged (p/therm)		67.19	89.68	99.28

At 31 December 2023, our financial hedging programme on commodity derivative instruments showed a pre-tax negative mark-to-market fair value of $18 million (2022: $3,257 million), with no ineffectiveness charge to the income statement.

Statement of cash flows¹

	2023  $million	2022  $million
Cash flow from operating activities after tax	2,144	3,130
Cash flow from investing activities - capital investment	(718)	(634)
Cash flow from investing activities - other	25	5
Operating cash flow after investing activities	1,451	2,501
Cash flow from financing activities2	(409)	(396)
Free cash flow3	1,042	2,105
Cash and cash equivalents	280	500

1 Table excludes financing activities related to debt principal movements.

2 Interest and lease payments only, excludes shareholder distributions.

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

Net cash from operating activities after tax amounted to $2,144 million (2022: $3,130 million) after accounting for positive working capital movements of $199 million, including movements in realised but unsettled hedges of $207 million (2022: $104 million). Capital investment was $718 million (2022: $634 million) which included property, plant and equipment additions of $496 million (2022: $477 million) and exploration and evaluation additions of $202 million (2022: $127 million). Cash outflow from financing activities totalled $409 million (2022: $396 million) split between interest payments of $150 million (2022: $142 million) and lease payments of $259 million (2022: $254 million).

Shareholder distributions consist of dividends paid of $190 million (2022: $191 million) and $249 million (2022: $361 million) related to the repurchase of Harbour's own shares.

The Group made net tax payments of $438 million in the period (2022: $552 million) primarily in relation to the UK Energy Profits Levy. 

Cash and cash equivalent balances were $280 million (2022: $500 million) 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.

	2023  $million	2022  $million
Additions to oil and gas assets	(482)	(532)
Additions to fixtures and fittings, office equipment & IT software	(29)	(42)
Additions to exploration and evaluation assets	(210)	(111)
Total capital investment1	(721)	(685)
Movements in working capital	(22)	28
Capitalised interest	7	1
Capitalised lease payments	18	22
Cash capital investment per the cash flow statement	(718)	(634)

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

During the year, the Group incurred total capital expenditure¹ of $969 million (2022: $908 million), split by capital investment $721 million (2022: $685 million) and decommissioning spend $248 million (2022: $223 million) respectively.

The capital investment in the UK mainly consisted of, for operated assets, development drilling in the J-Area, including at Talbot, the tie in of Tolmount East to Tolmount, the appraisal of the Leverett discovery which is close to the Britannia platform and long lead items for the Callanish and North Seymour infill wells at our GBA and AELE hubs respectively. For partner operated assets, capital investment consisted primarily of the tie in of two subsea wells at Beryl, and drilling at Buzzard, Clair and Schiehallion. In International, exploration wells were drilled at Layaran-1 in Indonesia, the JDE well in Norway and the Kan and Ix-1EXP wells in Mexico.

Principal risks

There are no significant changes to the headline principal risks from those disclosed in the 2023 half-year results.

Post balance sheet events

On 5 March 2024 Harbour signed a new $3.0 billion fully unsecured revolving credit facility (RCF) and $1.5 billion bridge facility which will be available at completion to fund the acquisition of the Wintershall Dea asset portfolio. The RCF has a $1.75 billion letter of credit sublimit, a five-year term from signing and will replace the existing RBL facility.

On 6 March 2024, the UK government announced that Energy Profit Levy (EPL) would be extended for a further 12 months to 31 March 2029 from the former end date of 31 March 2028. Harbour is currently assessing the potential impact of this announcement.

Going concern

The Directors consider the going concern assessment period to be up to 30 June 2025. The Group monitors and manages its capital position and its liquidity risk regularly throughout the year to ensure that it has access to sufficient funds to meet forecast cash requirements. Cash forecasts 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 ongoing capital requirements are financed by the Group's $2.75 billion reserves-based lending (RBL) facility that has a current borrowing base of $1.3 billion after the amendment and extension that was completed in November 2023, and $0.5 billion bond which matures in 2026. The amount drawn down under these facilities at 31 December 2023 was nil and $0.5 billion respectively, which together with cash of $0.3 billion, gave a total available liquidity of $1.6 billion. Further details can be found in note 14 on page 45. The RBL facility has a financial covenant relating to the ratio of consolidated total net debt to consolidated EBITDAX on a historic and forward-looking basis, which is tested semi-annually. The amount available under the facility is redetermined annually based on a valuation of the Group's borrowing base assets when applying certain forward-looking assumptions, as defined in the borrowing agreements.  

The Group's latest approved business plan underpins the base case going concern assessment and is based upon management's best estimate of forward commodity price curves, production in line with approved asset plans, unavoidable committed fees in respect of the Wintershall Dea acquisition and the ongoing capital requirements of the Group that will be financed by free cash flow, the existing RBL and bond financing arrangements.

In December 2023 Harbour announced the Wintershall Dea acquisition transaction, which is anticipated to complete in Q4 2024 and will be accretive to Harbour's free cash flow. Once complete, Harbour is expected to receive investment grade credit ratings and to benefit from a significantly lower cost of financing, including the porting of existing euro denominated Wintershall Dea bonds with a nominal value of approximately $4.9 billion and a weighted average coupon of c.1.8 per cent; the Group would also have access to a new $3.0 billion revolving credit facility and $1.5 billion bridge facility. As part of the going concern assessment, a base case, sensitivities and reverse stress tests have been run on the enlarged group forecasts, which are supported by Harbour's acquisition due diligence work, and show that the probability of a liquidity deficit or covenant breach is remote. 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.

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:

§ Brent crude and UK natural gas prices of 20 per cent, and

§ the Group's unhedged production of 10 per cent

throughout the assessment period.

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 further reductions in 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 covenant is 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 significantly below the sensitivity test performed and hence 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 30 June 2025 and has therefore adopted the going concern basis for preparing the financial statements.

By order of the Board,

Alexander Krane

Director

6 March 2024

Disclaimer 

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. 

Financial Statements

Consolidated income statement

For the year ended 31 December 2023

	Note	2023 $ million	2022 $ million
Revenue	4	3,715	5,390
Other income	4	36	41
Revenue and other income		3,751	5,431
Cost of operations	5	(2,357)	(2,845)
(Impairment)/impairment reversal of property, plant, and equipment	10	(214)	170
Impairment of goodwill		(25)	-
Exploration and evaluation expenses and new ventures	5	(36)	(42)
Exploration costs written-off	9	(57)	(64)
Gain on disposal	5	-	12
General and administrative expenses	5	(149)	(121)
Operating profit	5	913	2,541
Finance income	6	104	279
Finance expenses	6	(420)	(358)
Profit before taxation		597	2,462
Income tax expense	7	(565)	(2,454)
Profit for the year		32	8
Profit for the year attributable to:
Equity owners of the company		32	8

Earnings per share	Note	$ cents	$ cents
Basic	8	4	1
Diluted	8	4	1

Consolidated statement of comprehensive income

For the year ended 31 December 2023

	2023 $ million	2022 $ million
Profit for the year	32	8
Other comprehensive profit
Items that may be reclassified to the income statement:
Fair value gains on cash flow hedges	3,168	269
Tax (expense)/credit on cash flow hedges	(2,376)	1,006
Exchange differences on translation	103	(198)
Other comprehensive profit for the year, net of tax	895	1,077
Total comprehensive profit for the year, net of tax	927	1,085
Total comprehensive profit attributable to:
Equity owners of the company	927	1,085

Consolidated balance sheet

As at 31 December 2023

	Note	2023 $ million	2022 $ million
Assets
Non-current assets
Goodwill		1,302	1,327
Other intangible assets	9	1,172	880
Property, plant and equipment	10	4,717	5,690
Right-of-use assets	11	587	735
Deferred tax assets	7	7	1,406
Other receivables		184	298
Other financial assets	15	112	103
Total non-current assets		8,081	10,439
Current assets
Inventories		200	143
Trade and other receivables		832	1,403
Other financial assets	15	170	81
Cash and cash equivalents		280	500
		1,482	2,127
Assets held for sale	12	334	-
Total current assets		1,816	2,127
Total assets		9,897	12,566
Equity and liabilities
Equity
Share capital		171	171
Other reserves		289	(606)
Retained earnings		1,080	1,456
Total equity		1,540	1,021
Non-current liabilities
Borrowings	14	493	1,216
Provisions	13	3,818	3,934
Deferred tax	7	1,260	397
Trade and other payables		13	19
Lease creditor	11	474	604
Other financial liabilities	15	87	1,279
Total non-current liabilities		6,145	7,449
Current liabilities
Trade and other payables		886	1,252
Borrowings	14	16	22
Lease creditor	11	199	221
Provisions	13	230	231
Current tax liabilities		442	199
Other financial liabilities	15	197	2,171
		1,970	4,096
Liabilities directly associated with the assets held for sale	12	242	-
Total current liabilities		2,212	4,096
Total liabilities		8,357	11,545
Total equity and liabilities		9,897	12,566

The notes 1 to 19 form an integral part of these financial statements.

Consolidated statement of changes in equity

For the year ended 31 December 2023

	Share capital $ million	Share premium1 $ million	Merger reserve1 $ million	Capital redemption reserve $ million	Cash flow hedge reserve2 $ million	Costs of hedging reserve2 $ million	Currency translation reserve $ million	Retained earnings $ million	Total equity $ million
At 1 January 2022	171	1,505	677	8	(2,062)	2	98	75	474
Profit for the year	-	-	-	-	-	-	-	8	8
Other comprehensive income	-	-	-	-	1,286	(11)	(198)	-	1,077
Total comprehensive income	-	-	-	-	1,286	(11)	(198)	8	1,085
Purchase and cancellation of own shares	-	-	-	-	-	-	-	(361)	(361)
Share-based payments	-	-	-	-	-	-	-	36	36
Capital restructuring1	-	(1,505)	(406)	-	-	-	-	1,911	-
Purchase of ESOP Trust shares	-	-	-	-	-	-	-	(22)	(22)
Dividend paid	-	-	-	-	-	-	-	(191)	(191)
At 31 December 2022	171	-	271	8	(776)	(9)	(100)	1,456	1,021
Profit for the year	-	-	-	-	-	-	-	32	32
Other comprehensive income	-	-	-	-	779	13	103	-	895
Total comprehensive income	-	-	-	-	779	13	103	32	927
Purchase and cancellation of own shares	-	-	-	-	-	-	-	(249)	(249)
Share-based payments	-	-	-	-	-	-	-	46	46
Purchase of ESOP Trust shares	-	-	-	-	-	-	-	(15)	(15)
Dividend paid	-	-	-	-	-	-	-	(190)	(190)
At 31 December 2023	171	-	271	8	3	4	3	1,080	1,540

¹ In 2022, share premium and merger reserve balances were recategorised to retained earnings following the capital reduction effective 3 August 2022.

² Disclosed net of deferred tax.

Consolidated statement of cash flows

For the year ended 31 December 2023

	Note	2023 $ million	2022 $ million
Net cash inflows from operating activities	16	2,144	3,130
Investing activities
Expenditure on exploration and evaluation assets		(202)	(127)
Expenditure on property, plant and equipment	10	(496)	(477)
Expenditure on non-oil and gas intangible assets		(20)	(30)
Expenditure on other intangible assets		(81)	-
Receipts for sub-lease income		10	10
Proceeds from/payments relating to disposal of oil and gas properties		3	(6)
Expenditure on business combinations - deferred consideration		-	(19)
Finance income received		93	20
Net cash outflows used in investing activities		(693)	(629)
Financing activities
Repurchase of shares		(249)	(361)
Proceeds from new borrowings - reserves-based lending facility	14	660	-
Proceeds from new borrowings - exploration finance facility	14	-	11
Lease liability payments		(259)	(254)
Repayment of reserves-based lending facility	14	(1,435)	(1,663)
Repayment of exploration finance facility	14	(11)	(38)
Repayment of financing arrangement	14	(21)	(15)
Purchase of ESOP Trust shares		(12)	(21)
Interest paid and bank charges		(150)	(142)
Dividends paid	18	(190)	(191)
Net cash outflows from financing activities		(1,667)	(2,674)
Net decrease in cash and cash equivalents		(216)	(173)
Net foreign exchange difference		(4)	(26)
Cash and cash equivalents at 1 January		500	699
Cash and cash equivalents at 31 December		280	500

Notes to the consolidated financial statements

1.   General information

Harbour Energy plc ('Harbour') 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 financial information for the year ended 31 December 2023 and 2022 contained in this document does not constitute statutory accounts of Harbour Energy plc (the Company), as defined in section 435 of the Companies Act 2006. The financial information for the years ended 31 December 2023 and 2022 have been extracted from the consolidated financial statements of Harbour Energy plc and all its subsidiaries (the Group), which were authorised for issued by the Board of Directors on 6 March 2024 and will be delivered to the Registrar of Companies in due course. The auditor's report on those financial statements was unqualified and did not contain a statement under section 498 of the Companies Act 2006.

The Group's principal activities are the acquisition, exploration, development and production of oil and gas reserves on the UK and Norwegian continental shelves, Indonesia, Vietnam and Mexico.

2.   Basis of preparation and significant accounting policies

2.1  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 downside sensitivities 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 unlikely. Further details are within the Financial Review.

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.

2.2  Accounting policies

The accounting policies adopted in the preparation of the 2023 consolidated financial statements are consistent with those adopted and disclosed in Harbour's 2022 Annual Report and Accounts. A number of amendments to existing standards and interpretations were effective from 1 January 2023 but had no impact on the full-year financial statements. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

2.3  Basis of consolidation

The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as at 31 December 2023. 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 and there are no non-controlling interests.

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.

2.4  Use of judgements and estimates

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. 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 2022 Annual Report and Accounts, apart from change in the judgement associated with tax due to a reduction in judgement required in 2023 with regards to deferred tax associated with the UK Energy Profits Levy (EPL) but an increase in judgements around uncertain tax positions. Disclosure regarding the judgements and estimates made in assessing the impact of climate change and the energy transition are detailed below.

2.5  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 continued strategic ambition is to achieve net zero by 2035 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, potential partial UK offshore electrification and the eventual cessation of production of mature fields. In addition, the company is investing in the development of carbon capture and storage projects in the UK.  Where the Group cannot reduce its Scope 1 and 2 emissions, it will invest in high quality, independently verified, carbon offsets to achieve the goal of net zero.

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 goal, taking into consideration both GHG volumes and intensity. 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 limited electrification and other activities to reduce Scope 1 and 2 GHG emissions, the UK Emissions Trading Scheme cost and carbon offset purchases.

Emissions reduction incentives are part of staff remuneration through the annual bonus program. Additionally, the cost of borrowing is tied to our gross operated CO₂ emissions performance, with GHG metrics being linked to our RBL interest expense, further incentivising our emissions reduction targets.

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-price commodity price outlooks. 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 may bring greater levels of disruption and volatility than these external scenarios expect and do not represent management's current best estimate.

Management's current best estimate for the foreseeable future, which was derived from consideration of a  range of considered economic forecasts, has been used on the same basis to prepare the financial statements and is represented by the Harbour scenario oil price curve. Management continues to review these estimates and assumptions to ensure they reflect the latest economic environment conditions and market information available.

Impairment of property, plant and equipment, and goodwill

The energy transition 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. In the current period, when testing for impairment, the Harbour scenario real long-term commodity price assumptions from 2026 for Brent crude were $70/bbl (2022: $65/bbl) and UK NBP gas 90 pence/therm (2022: 65 pence/therm) combined with the short term forecast period reflecting market forward curves at the year end.

Carbon costs will develop over time and carry considerable uncertainty due to the rate of transition and maturity of regulatory regimes. For the UK price of carbon, Harbour management's real forward price curve assumption in 2024 is £50/tonne ($63/tonne) rising to £140/tonne ($175/tonne) in 2030. The sensitivity was run on the IEA Net Zero carbon price curve. The foreign exchange rate was assumed to be $1.00:£1.25 flat for future periods to convert to nominal prices. Such assumptions are inherently uncertain and may ultimately differ from the actual amounts.

During 2023 there was a total net pre-tax impairment charge of $239 million (2022: $170 million) across goodwill of $25 million and property, plant and equipment $214 million. Further details on the latter amount can be found in and note 10.

Further, sensitivities on the impairment of property, plant and equipment and goodwill have been prepared using various commodity price scenarios to show the possible impact on net book carrying values. As noted, the Harbour scenario is the basis for the preparation of the financial statements. Impairment sensitivities have been prepared at an average -10 per cent and +10 per cent to the Harbour scenario average for crude, gas and carbon and selected published climate change price curves.

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

This analysis covers the transition risks and the graphs below show the crude oil and UK NBP gas price curves for the period to 2050 for the following scenarios:  IEA Net Zero 2050, IEA Stated Policies and IEA 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.

§ Harbour scenario base price curves used for impairment testing

§ IEA Net Zero Emissions by 2050 (NZE) limiting global temperature rise to 1.5^oC

§ IEA Stated Policies (STEPS) current policy commitments by sector and country

§ IEA Announced Pledges (APS) current climate commitments by governments and industries

The crude price curves reflect the published IEA price curves for all periods. For UK NBP gas there are no IEA published price curves therefore management has derived the UK NBP gas price curves by converting from the published IEA European gas price curve. The 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 for 2024-2027, the derived gas price curve matches the Harbour scenario price curve to create a scenario that was considered reasonably plausible.

Pre-development assets such as Zama in Mexico and Andaman in Indonesia 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 results of the sensitivities are as follows and show the impact on the property, plant and equipment balance sheet carrying values when it had resulted in a material decrease in carrying value.

	Commodity	Carrying value $ million	Pre-tax sensitivity in carrying value $ million
			+10% price to Harbour scenario	-10% price to Harbour scenario	IEA Net Zero Emissions by 2050 (NZE)	IEA Stated Policies (STEPS)	IEA Announced Pledges (APS)
Property, plant, and equipment (note 10)	Crude Oil	4,717	-	(86)	(221)	-	-
	UK NBP Gas (derived)		-	(21)	(9)	-	-
	Carbon		-	-	(27)

The +/-10% price curves used in the Harbour scenarios adjust long-term prices from 2027.

Under the -10% price to Harbour scenario for crude there is a pre-tax impairment to property, plant and equipment on two UK fields of $86 million (post-tax $40 million) and for UK NBP gas a pre-tax impairment on a single UK field of $21 million (post-tax $6 million).

For crude, under the IEA NZE 2050 scenario, there is a pre-tax impairment to property, plant and equipment on a single UK field of $221 million (post-tax $104 million) and for UK NBP gas, there is a pre-tax impairment on two UK fields of $9 million (post-tax $3 million). For carbon, under all scenarios carbon price does not drive a material change in carrying value as they are not a sensitive and material assumption in the cash flow forecasts. There is no impairment to property, plant and equipment across the three +10% price to Harbour scenarios nor the IEA STEPS and APS scenarios.

Under the IEA Net Zero Emissions by 2050 scenario for carbon, there is a pre-tax impairment to property, plant and equipment on a single UK field of $27 million (post-tax $13 million).

For goodwill, there are no impairments under any scenario except for the -10% price to Harbour scenario for UK NBP gas which reflects an impairment of $4 million.

Property, plant and equipment - depreciation and expected useful lives

A significant proportion of property, plant and equipment assets are expected to reach cessation of production over the next 10 to 20 years. The energy transition has the potential to reduce the expected useful lives of assets and consequently accelerate the cessation of production dates and increase the rate at which depreciation is charged. There are no significant judgements and/or critical estimation uncertainty related to climate factors.

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 be tied back to existing infrastructure 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.

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. 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 $456 million and $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.

Currently, 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.

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.

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 two regions: namely North Sea and International. The North Sea segment includes the UK and Norwegian continental shelves, and the International segment includes Indonesia, Vietnam and Mexico.

Information on major customers can be found in note 4.

Income statement

		2023 $ million	2022 $ million
Revenue
North Sea		3,478	5,082
International		237	308
Total Group sales revenue		3,715	5,390
Other income
North Sea		36	41
International		-	-
Total Group revenue and other income		3,751	5,431
Group operating profit
North Sea		898	2,388
International		15	153
Group operating profit		913	2,541
Finance income		104	279
Finance expenses		(420)	(358)
Profit before income tax		597	2,462
Income tax expense		(565)	(2,454)
Profit for the year		32	8

Balance sheet

		2023 $ million	2022 $ million
Segment assets
North Sea		8,632	11,346
International		1,265	1,220
Total assets		9,897	12,566
Segment liabilities
North Sea		(7,818)	(10,938)
International		(539)	(607)
Total liabilities		(8,357)	(11,545)

Other information

		2023 $ million	2022 $ million
Capital additions
North Sea		611	576
International		110	109
Total capital additions		721	685
Depreciation, depletion and amortisation
North Sea		1,369	1,471
International		61	75
Total depreciation, depletion and amortisation		1,430	1,546
Exploration and evaluation expenses and new ventures
North Sea		36	34
International		-	8
Total exploration and evaluation expenses and new ventures		36	42
Exploration costs written-off
North Sea		38	71
International1		19	(7)
Total exploration costs written-off		57	64

¹   In 2022, International included a credit to the income statement related to a change to the decommissioning estimate in the Falkland Islands business unit.

4.   Revenue from contracts with customers and other income

		2023 $ million	2022 $ million
Type of goods
Crude oil sales		2,086	2,792
Gas sales		1,415	2,322
Condensate sales		179	238
Total revenue from contracts with customers1		3,680	5,352
Tariff income		30	30
Other revenue		5	8
Revenue from production activities		3,715	5,390
Other income2		36	41
Total revenue and other income		3,751	5,431

¹  Revenues from contracts with customers of $4,591 million (2022: $8,537 million) include crude oil sales of $2,179 million (2022: $3,545 million) and gas sales of $2,233 million (2022: $4,754 million). This was prior to realised hedging losses in the period of $93 million (2022: $753 million) on crude oil and $818 million (2022: $2,432 million) on gas sales.

²  Other income mainly represents partner recoveries related to lease obligations and, in 2023 a receipt related to the Viking CCS Development Agreement that was signed in March.

Approximately 88 per cent (2022: 84 per cent) of the revenues were attributable to sales to energy trading companies of the Shell group.

5.   Operating profit

	Note	2023 $ million	2022 $ million
Cost of operations
Production, insurance and transportation costs		1,171	1,114
Gas purchases		12	36
Royalties		4	5
Depreciation of oil and gas assets	10	1,192	1,319
Depreciation of right-of-use oil and gas assets	11	230	219
Capitalisation of IFRS 16 lease depreciation on oil and gas assets	11	(27)	(30)
Amortisation of oil and gas intangible assets		-	1
Movement in over/underlift balances and hydrocarbon inventories		(225)	181
Total cost of operations		2,357	2,845
Impairment expense/(reversal) of property, plant and equipment	10	108	(88)
Impairment loss/(gain) due to increase in decommissioning provision	10	106	(82)
Impairment of goodwill		25	-
Exploration costs written-off1	9	57	64
Exploration and evaluation expenditure and new ventures2		36	42
Gain loss on disposal3		-	(12)
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets	11	9	11
Depreciation of non-oil and gas assets	10	3	5
Amortisation of non-oil and gas intangible assets	9	23	21
Other administrative costs4		114	84
Total general and administrative expenses		149	121
Auditors' remuneration
Audit fees
Fees payable to the company's auditor for the company's Annual Report		3	3
Audit of the company's subsidiaries pursuant to legislation		1	1
Non audit fees5
Other services pursuant to legislation - interim review		-	-
Other services6		1	1

1 Exploration costs written-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway and also includes costs associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 13).

2 Exploration and evaluation expenditure and new ventures of $36 million (2022: $42 million) includes $29 million (2022: $28 million) of early project costs on new ventures incurred in respect of the Group's interest in CCS and electrification projects in the UK, plus $7 million (2022: $13 million) of ongoing pre-licence costs.

3 The gain on disposal in 2022 of $12 million relates to the release of a provision associated with Premier's sale of its legacy Pakistan assets in 2019 after the expiry of the deadline in the period for tax claims to be submitted.

4 Other administrative costs in 2023 include consultancy costs of $33 million (2022: $9 million).

5 The Company has a policy on the provision of non-audit services by the auditor which is aimed at ensuring their continued independence. This policy is available on the Group's website. The use of the external auditor for services relating to accounting systems, financial statement preparations is not permitted, as are various other services including some advisory services that could give rise to conflicts of interest or other threats to the auditor's objectivity that cannot be reduced to an acceptable level by applying safeguards.

6 Other non-audit services in 2023 primarily relate to transaction related  activities.

6.   Finance income and finance expenses

	Note	2023 $ million	2022 $ million
Finance income
Bank interest		19	10
Other interest and finance gains		6	20
Lease finance income		2	2
Realised gains on interest rate swaps		-	6
Realised gains on foreign exchange forward contracts		9	1
Gains on derivatives1		68	38
Foreign exchange gains2		-	202
Total finance income		104	279
Finance expenses
Interest payable on reserves-based lending		15	71
Interest payable on bond		27	27
Other interest and finance expenses		17	12
Lease interest	11	51	25
Losses on derivatives1		-	48
Finance expense on deferred revenue		4	20
Foreign exchange losses		57	-
Bank and financing fees3		100	91
Unwinding of discount on decommissioning and other provisions	13	156	65
		427	359
Finance costs capitalised during the year4		(7)	(1)
Total finance expense		420	358

¹  Gains and losses on derivatives relate to changes in the fair value of an embedded derivative within one of the Group's gas contracts (2022: $48 million loss on derivatives). Gains on derivatives in 2022 included mark to market gains on unrealised interest rate and foreign exchange derivatives.

²  In 2022, significant unrealised foreign exchange gains arose mainly from the revaluation of open gas hedges denominated in sterling.

³  Bank and financing fees include an amount of $48 million (2022: $55 million) relating to the amortisation of arrangement fees and related costs capitalised against the Group's long-term borrowings (note 14).

⁴  The amount of finance costs capitalised was determined by applying the weighted average rate of finance costs applicable to the borrowings of the Group of 6.0 per cent to the expenditures on the qualifying assets (2022: 4.4 per cent).

7.   Income tax

	2023 $ million	2022 $ million
Current income tax expense:
UK corporation tax	641	672
Overseas tax	14	53
Adjustment in respect of prior years	22	(19)
Total current income tax expense	677	706
Deferred tax (credit)/expense:
UK corporation tax1	(74)	1,772
Overseas tax	(18)	(8)
Adjustment in respect of prior years	(20)	(16)
Total deferred tax (credit)/expense	(112)	1,748
Total income tax expense reported in the income statement	565	2,454
The tax expense/(credit) in the statement of comprehensive income is as follows:
Tax expense/(credit) on cash flow hedges	2,376	(1,006)

[1] 2022 includes a $1,469 million charge in respect of the revaluation of the deferred tax on the balance sheet due to the introduction of the Energy Profits Levy.

Reconciliation of tax expense and the accounting profit before taxation multiplied by the statutory rate of corporation tax and supplementary charge applying to UK oil and gas production operations for the years ended 31 December 2023 and 2022 is, as follows:

	2023 $ million	2022 $ million
Profit before income tax	597	2,462
At the Group's statutory income tax rate of 75.0% (2022: 55.0%)	448	1,354
Effects of:
Expenses/ (income) not deductible/ (taxable) for tax purposes	101	(12)
Interest not deductible for supplementary charge and Energy Profits Levy	60	53
Adjustments in respect of prior years	2	(36)
Remeasurement of deferred tax	13	(72)
Deferred Energy Profits Levy	-	1,469
Impact of different tax rates	(29)	(190)
Expenses not deductible for Energy Profits Levy	52	8
Energy Profits Levy investment allowance	(64)	(81)
Investment allowance	(18)	(39)
Total tax expense reported in the consolidated income statement at the effective tax rate of 95% (2022: 100%)	565	2,454

The effective tax rate for the year was 95 per cent, compared to 100 per cent for 2022.

The tax expense reconciliation has been prepared based on the statutory rate of taxation applying to UK oil and gas production because the majority of Group profit was generated on the UK continental shelf. UK oil and gas production is taxed at a rate of 30 per cent (2022: 30 per cent), a supplementary charge of 10 per cent (2022: 10 per cent), and with effect from 1 January 2023, the Energy Profits Levy (EPL) of 35 per cent (2022: 25 per cent) to give an overall tax rate of 75 per cent (2022: 65 per cent). As the EPL was introduced part way through the previous financial year a blended average rate of 55 per cent was applied.

The future effective tax rate is impacted by the mix of jurisdictions in which the Group operates. The UK statutory tax rate for oil and gas production operations is expected to remain a primary influence on the effective tax rate. The Energy Profits Levy at the 35 per cent rate is currently in place until 31 March 2028.

Deferred tax

The principal components of deferred tax are set out in the following tables:

	2023 $ million	2022 $ million
Deferred tax assets	7	1,406
Deferred tax liabilities	(1,291)	(397)
	(1,284)	1,009
Reclassification of deferred tax liabilities directly associated with assets held for sale (note 12)	31	-
Total deferred tax	(1,253)	1,009

The origination of and reversal of temporary differences are, as shown in the next table, related primarily to movements in the carrying amount and tax base value of expenditure and the timing of when these items are changed and are credited against accounting and taxable profit.

	Accelerated capital allowances $ million	Decomm-issioning $ million	Losses $ million	Fair value of derivatives $ million	Other $ million	Overseas $ million	Total deferred tax asset/ (liability) $ million
As at 1 January 2022	(2,820)	2,013	1,314	1,392	39	(187)	1,751
Deferred tax (expense)/ credit	(658)	(362)	(745)	49	(40)	8	(1,748)
Comprehensive income	-	-	-	1,006	-	-	1,006
Foreign exchange	82	(86)	-	5	(2)	1	-
As at 31 December 2022	(3,396)	1,565	569	2,452	(3)	(178)	1,009
Deferred tax (expense)/ credit	546	(25)	(388)	(61)	22	18	112
Comprehensive expense	-	-	-	(2,376)	1	-	(2,375)
Foreign exchange	(51)	34	-	(9)	1	(5)	(30)
As at 31 December 2023	(2,901)	1,574	181	6	21	(165)	(1,284)

The Group's deferred tax assets as at 31 December 2023 are recognised to the extent that taxable profits are expected to arise against which the tax assets can be utilised. The Group assessed the recoverability of its UK ring fenced losses and allowances using corporate assumptions which are consistent with the Group's impairment assessment. Based on those assumptions, the Group expects to fully utilise its recognised UK tax losses and allowances. The recovery of the Group's UK decommissioning deferred tax asset is additionally supported by the ability to carry back decommissioning tax losses and set these against ring fence taxable profits of prior periods.

The EPL increased to a rate of 35 per cent from 25 per cent with effect from 1 January 2023. The EPL is currently in place until 31 March 2028. Any temporary differences subject to the EPL expected to reverse in this period have consequently been remeasured to the higher rate. Ring fence tax losses cannot be offset against profits subject to EPL nor are deductions given for expenditure incurred on decommissioning. Consequently, the deferred tax assets representing future decommissioning deductions and ring fence tax losses are not impacted by EPL with the effect of EPL primarily being on the deferred tax liability associated with accelerated capital allowances. The closing deferred tax liability for the period of $1,284 million includes $1,014 million of deferred tax liabilities arising from the impact of EPL.

In line with other sensitivity analysis undertaken, we have assessed the impact on the recoverability of deferred tax assets based on an average -10 per cent to the Harbour scenario average crude price curves. The sensitivity analysis indicates that there would no material impact to the recoverability of deferred tax assets.

The Group has unrecognised UK tax losses and allowances as at 31 December 2023 of approximately $181 million (2022: $202 million) in respect of ring fence losses, $138 million (2022: $111 million) in respect of ring fence investment allowance and $803 million (2022: $807 million) in respect of non-ring fence losses.

The Group also has unrecognised tax losses of approximately $168 million (2022: $157 million) in respect of its international operations. These losses include amounts of $13 million which will expire within 10 years and $24 million which will expire within 5 years.

The overseas deferred tax relates mainly to temporary differences associated with fixed asset balances.

No deferred tax liabilities have been provided on unremitted earnings of overseas subsidiaries, because due to the application of withholding reliefs under international double taxation treaties and dividend exemptions under UK and Netherlands legislation no additional taxation is expected to arise on future distribution.

Legislation was introduced in UK Finance Act 2021 to increase the main rate of UK corporation tax for non-ring fence profits from 19 per cent to 25 per cent from 1 April 2023. This change does not have a material impact on the Group as the UK profits are primarily subject to the UK ring fence tax rate.

Global minimum corporation tax rate - Pillar Two requirements

The legislation implementing the Organisation for Economic Co-operation and Development's (OECD) proposals for a global minimum corporation tax rate (Pillar Two) was substantively enacted into UK law on 20 June 2023. The rules have effect from 1 January 2024 and therefore the rules do not impact the Group's results to 31 December 2023.

The Group has applied the mandatory exception to recognising and disclosing information about the deferred tax assets and liabilities related to Pillar Two income taxes in accordance with the amendments to IAS 12 published by the IASB on 23 May 2023.

The Group has performed an assessment of the Group's potential exposure to Pillar Two income taxes for periods from 1 January 2024. The assessment of the potential exposure to Pillar Two income taxes is based on the most recent tax filings, country-by-country reporting and financial statements for the constituent entities in the Group. Based on the assessment, the Pillar Two effective tax rates in most of the jurisdictions in which the Group operates are above 15 per cent and the transitional safe harbour relief is expected to apply. On this basis the Group does not expect a material exposure to Pillar Two income taxes in any jurisdictions.

Uncertain tax positions

During the period an uncertain tax position has been identified in certain UK subsidiaries relating to the timing of the taxation of fair value movements and realised gains and losses on hedges entered into in order to manage commodity price risk. On the strength of independent advice, management considers that there is no expectation of a net additional outflow of funds.  As such no additional liability has been recognised in the consolidated financial statements as at 31 December 2023.  However, a contingent liability exists as the UK Tax Authorities could take an alternative view on whether the fair value movements on the hedged instruments are disregarded for tax purposes.  While not considered a likely outcome, if the UK Tax Authorities were to disagree and successfully challenge the position, a possible liability currently estimated not to exceed $120 million could arise because of the differences in tax rates across the periods in question.

8.   Earnings per share (EPS)

Basic EPS is calculated by dividing the profit after tax attributable to ordinary shareholders of the Group by the weighted average number of ordinary shares in issue during the year.

Diluted EPS is calculated by dividing the profit after tax attributable to ordinary shareholders by the weighted average number of ordinary share in issue during the year plus the weighted average number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares into ordinary shares.

The following table reflects the income and share data used in the basic and diluted EPS calculations:

	2023	2022
Earnings for the year ($ millions)
Earnings for the purpose of basic earnings per share	32	8
Effect of dilutive potential ordinary shares	-	-
Earnings for the purpose of diluted earnings per share	32	8
Number of shares (millions)
Weighted average number of ordinary shares for the purposes of basic earnings per share1	804	900
Dilutive potential ordinary shares2	2	12
Weighted average number of ordinary shares for the purposes of diluted earnings per share	806	912
Earnings per share ($ cents)
Basic	4	1
Diluted	4	1

¹  During the current period 76.8 million ordinary shares were repurchased and cancelled as part of the share buyback programme.

²  Excludes certain share options outstanding at 31 December 2023 as their option price was greater than market price.

9.   Other intangible assets

	Note	Oil and gas  assets $ million	Non-oil and gas assets1 $ million	Carbon allowances3 $ million	Total $ million
Cost
At 1 January 2022		813	119	-	932
Additions during the year		111	31	-	142
Transfers to property, plant and equipment	10	(29)	-	-	(29)
Reduction in decommissioning asset	13	(12)	-	-	(12)
Exploration written-off2		(64)	-	-	(64)
Currency translation adjustment		(2)	(13)	-	(15)
At 31 December 2022		817	137	-	954
Additions during the year		210	20	-	230
Transfers from property, plant and equipment	10	-	7	-	7
Reclassification from trade and other receivables		-	-	86	86
Increase in decommissioning asset	13	4	-	-	4
Exploration written-off2		(57)	-	-	(57)
Currency translation adjustment		42	8	-	50
At 31 December 2023		1,016	172	86	1,274
Amortisation
At 1 January 2022		-	60	-	60
Charge for the year		-	21	-	21
Currency translation adjustment		-	(7)	-	(7)
At 31 December 2022		-	74	-	74
Charge for the year		-	23	-	23
Currency translation adjustment		-	5	-	5
At 31 December 2023		-	102	-	102
Net book value
At 31 December 2022		817	63	-	880
At 31 December 2023		1,016	70	86	1,172

¹ Non-oil and gas assets relate primarily to Group IT software.

² The exploration write-off of $57 million (2022: $64 million) includes $13 million related to the Ix-1EXP well in Mexico, $15 million related to the JDE well in Norway and also includes costs associated with licence relinquishments and uncommercial well evaluations and $4 million related to an increase in decommissioning provisions in the North Sea (note 13) (2022: $6 million credit).

³ On 31 December 2023, the Group reclassified purchases of UK ETS carbon allowances of $61 million and Voluntary Emissions Reductions (VER) credits of $25 million from trade and other receivables to intangible assets, $43 million of which are expected to be released to the income statement in the next 12 months.

10. Property, plant and equipment

	Note	Oil and gas  assets $ million	Fixtures and fittings & office equipment $ million	Total $ million
Cost
At 1 January 2022		12,022	30	12,052
Additions1		532	11	543
Transfers from intangible assets	9	29	-	29
Decrease in decommissioning asset2	13	(778)	-	(778)
Currency translation adjustment		(369)	(3)	(372)
At 31 December 2022		11,436	38	11,474
Additions1		482	9	491
Transfers to intangible assets	9	-	(7)	(7)
Reclassification of asset held for sale	12	(198)	-	(198)
Decrease in decommissioning asset2	13	(22)	-	(22)
Currency translation adjustment		159	2	161
At 31 December 2023		11,857	42	11,899
Accumulated depreciation
At 1 January 2022		4,785	21	4,806
Charge for the year		1,319	5	1,324
Net impairment reversal		(170)	-	(170)
Currency translation adjustment		(174)	(2)	(176)
At 31 December 2022		5,760	24	5,784
Charge for the year		1,192	3	1,195
Impairment charge		214	-	214
Reclassification of asset held for sale	12	(103)	-	(103)
Currency translation adjustment		91	1	92
At 31 December 2023		7,154	28	7,182
Net book value
At 31 December 2022		5,676	14	5,690
At 31 December 2023		4,703	14	4,717

¹ Included within property, plant and equipment additions of $491 million (2022: $543 million) are associated cash flows of $496 million (2022: $477 million) and non-cash flow movements of $5 million (2022: ($66 million)), represented by a $30 million decrease in capital accruals (2022: $43 million increase), $18 million of capitalised lease depreciation (2022: $22 million) and $7 million of capitalised interest (2022: $1 million).

² A decrease in the decommissioning assets of $22 million (2022: $778 million) was made during the year as a result of both new obligations and an update to the decommissioning estimates (note 13).

During the year, the Group recognised a pre-tax impairment charge of $214 million (post-tax $109 million) (2022: net impairment credit of $170 million; post-tax $50 million). This comprised a pre-tax impairment charge representing a write-down of property, plant and equipment assets of $108 million (2022: $163 million), across two CGUs in the UK of $70 million. Of these CGUs, one was driven primarily by a significant reduction in the gas price forward curve, and the other by a revised decommissioning cost profile. In addition there was a Vietnam fair value impairment on the held for sale asset of $38 million plus a pre-tax impairment charge of $106 million (2022: $82 million credit) in respect of revisions to decommissioning estimates on mainly non-producing assets with no remaining net book value (see note 13).

In 2022, a net pre-tax impairment credit of $170 million was recognised as a result of impairments reversals on North Sea assets of $251 million driven by a higher forward curve and long term price assumption for gas, and a pre-tax impairment credit of $82 million in respect of revisions to decommissioning estimates on the Group's non-producing assets with no remaining net book value. This was partially offset by an impairment to property, plant and equipment of $163 million from a single CGU in the UK North Sea, driven primarily by the contracted price realised for crude sales being negatively impacted by the pricing differential between Urals and Brent crude and a revised operating cost profile for the field.

Key assumptions used in calculations

Assumptions used in impairment measurement include estimates of commercial reserves and production volumes, future oil and gas prices, discount rates and the level and timing of expenditures, all of which are inherently uncertain.

Commodity and carbon prices - The Group uses the fair value less cost of disposal method (FVLCD) to calculate the recoverable amount of the cash-generating units (CGU) consistent with a level 3 fair value measurement (see note 15). In determining the recoverable value, appropriate discounted-cash-flow valuation models were used, incorporating market-based assumptions. Management's commodity price curve assumptions are benchmarked against a range of external forward price curves on a regular basis. Individual field price differentials are then applied. The first three years reflect the market forward price curves transitioning to a long-term price from 2027, thereafter inflated at 2.5 per cent per annum. The long-term commodity prices used were $70 per barrel for crude and 90p per therm for gas.

Production volumes and oil and gas reserves - Production volumes are based on life of field production profiles for each asset within the CGU. Proven and probable reserves are estimates of the amount of oil and gas that can be economically extracted from the Group's oil and gas assets. The Group estimates its reserves using standard recognised evaluation techniques, assessed at least annually by management. Proven and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices.

Costs - Operating expenditure, capital investment and decommissioning costs are derived from the Group's business plan. The discount rate reflects management's estimate of the Group's country-based weighted average cost of capital (WACC). Foreign exchange rates are based on management's long-term rate assumptions, with reference to a range of underlying economic indicators.

Sensitivity to changes in assumptions used in calculations

Reductions or increases in the long-term oil and gas prices of 10 per cent are considered to be reasonably possible changes for the purpose of sensitivity analysis. As shown in note 2 of the financial statements the decreases to the long-term oil and gas prices from 1 January 2027 specified above would result in a further pre-tax impairment of $86 million (post-tax $40 million) and $21 million (post-tax $6 million), respectively.  

Considering the discount rates, the Group believes a one per cent increase in the post-tax discount rate is considered to be a reasonable possibility for the purpose of sensitivity analysis. A one per cent increase in the post-tax discount rate would lead to a further pre-tax impairment of $24 million (post-tax $11 million), and a one per cent decrease in the post-tax discount rate would have no impact on the post-tax impairment charge.

11. Leases

This note provides information for leases where the Group is a lessee.

Balance sheet

Right-of-use assets	Land and buildings $ million	Drilling rigs $ million	FPSO $ million	Offshore facilities $ million	Equipment $ million	Total $ million
Cost
At 1 January 2022	100	153	509	-	18	780
Additions during the year1	-	-	-	338	-	338
Cost revisions/remeasurements	3	33	53	(4)	4	89
Disposals	(6)	-	-	-	-	(6)
Currency translation adjustment	(9)	(17)	-	-	(2)	(28)
At 31 December 2022	88	169	562	334	20	1,173
Additions during the year1	25	-	-	-	1	26
Cost revisions/remeasurements	1	48	63	(6)	4	110
Reclassification as asset held for sale	(5)	-	(71)	-	-	(76)
Disposals	(4)	(19)	-	-	-	(23)
Currency translation adjustment	4	10	-	-	1	15
At 31 December 2023	109	208	554	328	26	1,225
Accumulated depreciation
At 1 January 2022	22	98	102	-	7	229
Charge for the year	12	43	107	61	7	230
Disposals	(6)	-	-	-	-	(6)
Currency translation adjustment	(2)	(12)	-	-	(1)	(15)
At 31 December 2022	26	129	209	61	13	438
Charge for the year	9	42	94	89	5	239
Reclassification of asset held for sale	(2)	-	(23)	-	-	(25)
Disposals	(4)	(19)	-	-	-	(23)
Currency translation adjustment	1	7	-	-	1	9
At 31 December 2023	30	159	280	150	19	638
Net book value
At 31 December 2022	62	40	353	273	7	735
At 31 December 2023	79	49	274	178	7	587

¹ Additions of $26 million mainly related to new land and buildings were made to the right-of-use assets during the year (2022: total additions of $338 million related to the Tolmount offshore facilities).

Right-of-use liabilities	Note	2023 $ million	2022 $ million
At 1 January		825	654
Additions		28	338
Re-measurement		110	89
Finance costs charged to income statement	6	51	25
Finance costs charged to decommissioning provision	13	1	1
Reclassification of liabilities as held for sale	12	(95)	-
Lease payments		(262)	(254)
Currency translation adjustment		15	(28)
At 31 December		673	825
Classified as:
Current		199	221
Non-current		474	604
Total lease liabilities		673	825

The significant portion of the Group's lease liabilities represent lease arrangements for an FPSO vessel on the Catcher asset, and offshore facilities on the Tolmount asset.

The lease liabilities and associated right-of-use-assets have been calculated by reference to in-substance fixed lease payments in the underlying agreements incurred throughout the non-cancellable period of the lease along with periods covered by options to extend the lease where the Group is reasonably certain that such options will be exercised. When assessing whether extension options were likely to be exercised, assumptions are consistent with those applied when testing for impairment.

Income statement

Depreciation charge of right-of-use assets	Note	2023 $ million	2022 $ million
Land and buildings - non-oil and gas assets		8	11
Land and buildings - oil and gas assets		1	1
Drilling rigs		42	43
FPSO		94	107
Offshore facilities		89	61
Equipment - non oil and gas assets		1	-
Equipment - oil and gas assets		4	7
		239	230
Capitalisation of IFRS 16 lease depreciation1
Drilling rigs		(25)	(26)
Equipment		(2)	(4)
Total depreciation charge included within the consolidated income statement		212	200
Lease interest	6	51	25

¹  Of the $27 million (2022: $30 million) capitalised IFRS 16 lease depreciation, $18 million (2022: $22 million) has been capitalised within property, plant and equipment and $9 million (2022: $8 million) within provisions (note 13).

The total cash outflow for leases in 2023 was $259 million (2022: $254 million).

12. Assets held for sale

In August 2023, Harbour announced that it had entered into a Sale and Purchase Agreement to sell its business in Vietnam, which holds its 53.125 per cent interest in Chim Sao and Dua producing fields to Big Energy Joint Stock Company for a consideration of $84 million. The transaction, which is subject to government approvals, has an effective date of 1 January 2023. The assets and liabilities of Vietnam have been classified as assets held for sale in the balance sheet as at 31 December 2023 as completion is expected to be achieved within 12 months from entering into the SPA. 

The Group's Vietnam operations are included in the International segment however are not considered a major geographical area or line of business and therefore the disposal has not been classified as discontinued operations.

The major classes of assets and liabilities of the Group as held for sale as at 31 December 2023, are as follows:

		Note	2023 $ million
Assets
Property, plant and equipment			95
Right of use assets		11	51
Other receivables and working capital			188
Assets held for sale			334
Liabilities
Provisions		13	87
Lease creditor		11	95
Trade and other payables			29
Deferred tax		7	31
Liabilities directly associated with assets held for sale			242
Net assets directly associated with disposal group			92
Impairment loss recorded			38

Immediately before the classification of the disposal group as assets held for sale, the recoverable amount was estimated for the disposal group and no impairment loss was identified. The assets in the disposal group are held at the lower of their carrying amount and fair value less costs to sell. As at 31 December 2023, an impairment of $38 million was recognised as the fair value less cost to sell, being the expected consideration adjusted for items agreed under the SPA, was below the carrying amount of the disposal group. Following the impairment charge the net assets directly associated with the disposal group held on the consolidated balance sheet was $92 million.

13. Provisions

	Decommissioning provision $ million	Other provisions $ million	Total $ million
At 1 January 2022	5,354	27	5,381
Additions	24	-	24
Changes in estimates - decrease to oil and gas tangible decommissioning assets	(720)	-	(720)
Changes in estimates - decrease to oil and gas intangible decommissioning assets	(6)	-	(6)
Changes in estimates on oil and gas tangible assets - credit to income statement	(82)	-	(82)
Changes in estimates on oil and gas intangible assets - credit to income statement	(6)	-	(6)
Changes in estimates  - credit to income statement	-	(1)	(1)
Amounts used	(223)	(2)	(225)
Disposal	(9)	-	(9)
Interest on decommissioning lease	(1)	-	(1)
DD&A on decommissioning right-of-use leased asset	(8)	-	(8)
Unwinding of discount	65	-	65
Currency translation adjustment	(247)	-	(247)
At 31 December 2022	4,141	24	4,165
Additions	40	-	40
Changes in estimates - decrease to oil and gas tangible decommissioning assets	(203)	-	(203)
Changes in estimates on oil and gas tangible assets - debit to income statement	141	-	141
Changes in estimates on oil and gas intangible assets - debit to income statement	4	-	4
Changes in estimates - debit to income statement	-	3	3
Amounts used	(248)	-	(248)
Reclassification of liabilities directly associated with assets held for sale	(87)	-	(87)
Interest on decommissioning lease	(1)	-	(1)
DD&A on decommissioning right-of-use leased asset	(9)	-	(9)
Unwinding of discount	156	-	156
Currency translation adjustment	87	-	87
At 31 December 2023	4,021	27	4,048
	Non-current liabilities $ million	Current liabilities $ million	Total $ million
Classified within
At 31 December 2022	3,934	231	4,165
At 31 December 2023	3,818	230	4,048

Decommissioning provision

The Group provides for the estimated future decommissioning costs on its oil and gas assets at the balance sheet date. The payment dates of expected decommissioning costs are uncertain and are based on economic assumptions of the fields concerned. The Group currently expects to incur decommissioning costs within the next 40 years, the majority of which are anticipated to be incurred between the next 10 to 20 years. These estimated future decommissioning costs are inflated at the Group's long term view of inflation of 2.5 per cent per annum (2022: 2.5 per cent per annum) and discounted at a risk-free rate of between 4.3 per cent and 5.2 per cent (2022: 3.5 per cent and 3.7 per cent) reflecting a 6-month (2022: 6-month) rolling average of market rates over the varying lives of the assets to calculate the present value of the decommissioning liabilities. The unwinding of the discount is presented within finance costs.

These provisions have been created based on internal and third-party estimates. Assumptions based on the current economic environment have been made, which management believe are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to consider any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon market prices for the necessary decommissioning work required, which will reflect market conditions at the relevant time. In addition, the timing of decommissioning liabilities will depend upon the dates when the fields become economically unviable, which in itself will depend on future commodity prices and climate change, which are inherently uncertain.

Other provisions

Other provisions relate to termination benefit provision in Indonesia of $27 million (2022: $24 million), where the Group operates a service, severance and compensation pay scheme under a collective labour agreement with the local workforce.

14. Borrowings and facilities

The Group's borrowings are carried at amortised cost:

	2023 $ million	2022 $ million
Reserves-based lending (RBL) facility1	-	702
Bond	493	491
Exploration finance facility	-	11
Other loans	16	34
Total borrowings	509	1,238
Classified within:
Non-current liabilities	493	1,216
Current liabilities	16	22
Total borrowings	509	1,238

¹  The reserves-based lending (RBL) facility was fully repaid in the year, leaving $61 million of unamortised fees and related costs to be amortised over the remaining term of the facility which have been reclassified within current and non-current assets as appropriate

The RBL facility was amended and extended in November 2023, and the key terms of the amended RBL facility are:

§ Term matures 31 December 2029.

§ Facility size of $2.75 billion, with a $1.75 billion letter of credit sub-limit.

§ Debt availability at $1.346 billion effective 24 November 2023.

§ Debt availability to be redetermined on an annual basis.

§ Interest at compounded SOFR plus a margin of 3.2 per cent, rising to a margin of 3.4 per cent from November 2025 and 3.6 per cent from November 2027.

§ A margin adjustment linked to carbon-emission reductions.

§ Straight line amortisation of LC sub-limit from January 2027 to 6 months before maturity. No material cash collateralisation required until 2028.

§ Liquidity and leverage covenant tests.

§ A syndication group of 15 banks.

Certain fees are also payable, including fees on available commitments at 40 per cent of the applicable margin and commission on letters of credit issued at 50 per cent of the applicable margin.

In October 2021, the Group issued a $500 million bond under Rule 144A and with a tenor of five years to maturity. The coupon was set at 5.50 per cent and interest is payable semi-annually.

At the balance sheet date, the outstanding RBL balance excluding incremental arrangement fees and related costs was $nil million (2022: $775 million). As at 31 December 2023, $1,340 million remained available for drawdown under the RBL facility (2022: $1,972 million).

The Group has facilities to issue up to $1,750 million of letters of credit, of which $1,186 million was in issue as at 31 December (2022: $966 million), mainly in respect of future abandonment liabilities.

A further $34 million of arrangement fees and related costs were capitalised during the year following amendments to the RBL facility which became effective from November 2023.

During the year $48 million (2022: $55 million) of arrangement fees and related costs have been amortised and are included within financing costs.

At 31 December 2023, $68 million of arrangement fees and related costs remain capitalised (2022: $82 million), of which $21 million is due to be amortised within the next 12 months (2022: $20 million). $61 million of these arrangement fees relate to the RBL facility, $19 million of which have been reclassified within current assets, and $42 million, which are due to be amortised beyond the next 12 months, have been reclassified to non-current assets.

Bond interest of $6 million (2022: $6 million comprising both bond and RBL interest) had accrued by the balance sheet date and has been classified within accruals.

Since 2019, the Group has been operating within an exploration finance facility (EFF), of NOK 1 billion, in relation to part-financing the exploration activities of Harbour Energy Norge AS. This facility was repaid in full in February 2023.

Other loans represent a commercial financing arrangement with Baker Hughes (formerly BHGE), that covered a three-year work programme for drilling, completion and subsea tie-in of development wells on Harbour's operated assets. The loan will be repaid based on production performance, subject to a cap

The table below details the change in the carrying amount of the Group's borrowings arising from financing cash flows.

	Total $ million
Total borrowings as at 1 January 2022	2,886
Repayment of RBL	(1,663)
Repayment of financing arrangement	(15)
Repayment of EFF loan	(38)
Proceeds from EFF loan	11
Currency translation adjustment on EFF loan	(7)
Financing arrangement interest payable	9
Amortisation of arrangement fees and related costs	55
Total borrowings as at 31 December 2022	1,238
Proceeds from drawdown of borrowing facilities	660
Repayment of RBL	(1,435)
Repayment of financing arrangement	(21)
Repayment of EFF loan	(11)
Arrangement fees and related costs on RBL capitalised	(34)
Financing arrangement interest payable	3
Amortisation of arrangement fees and related costs	48
Reclassification of RBL arrangement fees and related costs to current and non-current assets	61
Total borrowings as at 31 December 2023	509

15. Other financial assets and liabilities

The Group held the following financial instruments at fair value at 31 December 2023. The fair values of all derivative financial instruments are based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy, except for the royalty valuation, which includes estimates based on unobservable inputs and are level 3 in the IFRS 13 hierarchy.

	31 December 2023 $ million		31 December 2022 $ million
Current	Assets	Liabilities	Assets	Liabilities
Measured at fair value through the income statement
Foreign exchange derivatives	6	-	6	-
Interest rate derivatives	-	-	24	-
Fair value of embedded derivative within a gas contract	10	-	-	(57)
	16	-	30	(57)
Measured at fair value through other comprehensive income
Commodity derivatives	154	(197)	51	(2,114)
Total current	170	(197)	81	(2,171)
Non-current
Measured at fair value through the income statement
Interest rate derivatives	-	-	18	-
			18	-
Measured at fair value through other comprehensive income
Commodity derivatives	112	(87)	85	(1,279)
Total non-current	112	(87)	103	(1,279)
Total current and non-current	282	(284)	184	(3,450)

15.1 Fair value measurements

All financial instruments that are initially recognised and subsequently remeasured at fair value have been classified in accordance with the hierarchy described in IFRS 13 Fair Value Measurement. The hierarchy groups fair-value measurements into the following levels, based on the degree to which the fair value is observable.

§ Level 1: fair value measurements are derived from unadjusted quoted prices for identical assets or liabilities.

§ Level 2: fair value measurements include inputs, other than quoted prices included within level 1, which are observable directly or indirectly.

§ Level 3: fair value measurements are derived from valuation techniques that include significant inputs not based on observable data.

	Financial Assets		Financial Liabilities
	Level 2 $ million	Level 3 $ million	Level 2 $ million	Level 3 $ million
At 31 December 2023
Fair value of embedded derivative within gas contract	10	-	-	-
Commodity derivatives	266	-	(284)	-
Foreign exchange derivatives	6	-	-	-
Total fair value	282	-	(284)	-
	Financial Assets		Financial Liabilities
At 31 December 2022	Level 2 $ million	Level 3 $ million	Level 2 $ million	Level 3 $ million
Fair value of embedded derivative within gas contract	-	-	(57)	-
Commodity derivatives	136	-	(3,393)	-
Foreign exchange derivatives	6	-	-	-
Interest rate derivatives	42	-	-	-
Total fair value	184	-	(3,450)	-

There were no transfers between fair value levels in 2022 or 2023.

Fair value movements recognised in the income statement on financial instruments are shown below:

	2023 $ million	2022 $ million
Finance income
Change in fair value of embedded derivative within gas contract	68	-
Foreign exchange derivatives	-	7
Interest rate derivatives	(43)	31
	25	38
	2023 $ million	2022 $ million
Finance expense
Change in fair value of embedded derivative within gas contract	-	48
	-	48

15.2 Fair values of other financial instruments

The following financial instruments are measured at amortised cost and are considered to have fair values different to their book values.

	2023 $ million		2022 $ million
	Book value	Fair value	Book value	Fair value
Bond	(493)	(487)	(491)	(446)

The fair value of the bond is within level 2 of the fair value hierarchy and has been estimated by discounting future cash flows by the relevant market yield curve at the balance sheet date. The fair values of other financial instruments not measured at fair value including cash and short-term deposits, trade receivables, trade payables and floating rate borrowings equate approximately to their carrying amounts.

15.3 Cash flow hedge accounting

The Group uses a combination of fixed price physical sales contracts and cash-settled fixed price commodity swaps and options to manage the price risk associated with its underlying oil and gas revenues. As at 31 December 2023, all of the Group's cash-settled fixed price commodity swap derivatives have been designated as cash flow hedges of highly probable forecast sales of oil and gas.

The following table indicates the volumes, average hedged price and timings associated with the Group's financial commodity derivatives. Volumes hedged through fixed price contracts with customers for physical delivery are excluded.

Position as at 31 December 2023	2024	2025	2026
Oil
Volume hedged (thousand bbls)	7,320	4,380	-
Weighted average hedged price ($/bbl)	84.37	77.35	-
UK natural gas
Volume hedged (million therms)	759	428	90
Weighted average hedged price (p/therm)	67.19	89.68	99.28

As at 31 December 2023, the fair value of net financial commodity derivatives designated as cash flow hedges, all executed under ISDA agreements with no margining requirements, was a net payable of $66 million (2022: $3,516 million) and net unrealised pre-tax losses of $16 million (2022: $3,185 million) were deferred in other comprehensive income in respect of the effective portion of the hedge relationships.

Amounts deferred in other comprehensive income will be released to the income statement as the underlying hedged transactions occur. As at 31 December 2023, net deferred pre-tax losses of $51 million (2022: $2,368 million) are expected to be released to the income statement within one year.

15.4 Interest Rate Benchmark Reform (IBOR)

During the year, the Group transitioned to alternative benchmark rates to cater for the discontinuation of IBOR rates.  Our bond is at a fixed interest rate of 5.5 per cent whilst the RBL (undrawn at 31 December 2023) transitioned from US LIBOR to SOFR (Secured Overnight Financing Rate).   

16. Notes to the statement of cash flows

Net cash flows from operating activities consist of:

	2023 $ million	2022 $ million
Profit before taxation	597	2,462
Adjustments to reconcile profit before tax to net cash flows:
Finance cost, excluding foreign exchange	363	358
Finance income, excluding foreign exchange	(104)	(77)
Depreciation, depletion and amortisation	1,430	1,546
Fair value movement in carbon swaps	-	2
Net impairment of property, plant and equipment	214	(170)
Impairment of goodwill	25	-
Share based payments	20	17
Decommissioning expenditure	(268)	(217)
Exploration costs written-off	57	64
Onerous contract payments	-	(2)
Gain on disposal	-	(12)
Movement in realised cash-flow hedges not yet settled	(207)	(104)
Unrealised foreign exchange loss/(gain)	49	(238)
Working capital adjustments:
(Increase)/decrease in inventories	(52)	65
Decrease/(increase) in trade and other receivables	519	(75)
(Decrease)/increase in trade and other payables	(61)	63
Net tax payments	(438)	(552)
Net cash inflow from operating activities	2,144	3,130

Reconciliation of net cash flow to movement in net borrowings

	2023 $ million	2022 $ million
Proceeds from drawdown of borrowing facilities	(660)	-
Proceeds from EFF loan	-	(11)
Repayment of RBL facility	1,435	1,663
Repayment of EFF loan	11	38
Repayment of financing arrangement	21	15
Financing arrangement interest payable	(3)	(9)
Arrangement fees and related costs capitalised	34	-
Amortisation of arrangement fees and related costs capitalised	(48)	(55)
Currency translation adjustment on EFF loan	-	7
Movement in total borrowings	790	1,648
Movement in cash and cash equivalents	(220)	(199)
Decrease in net borrowings in the year	570	1,449
Opening net borrowings	(738)	(2,187)
Closing net borrowings	(168)	(738)

Analysis of net borrowings

	2023 $ million	2022 $ million
Cash and cash equivalents	280	500
RBL facility	-	(702)
Bond	(493)	(491)
EFF loan	-	(11)
Net debt	(213)	(704)
Financing arrangement	(16)	(34)
Closing net borrowings	(229)	(738)
Non-current assets	42	-
Current assets	19	-
Closing net borrowings after total unamortised fees1	(168)	(738)

¹ $61 million of fees associated with the RBL are recognised in debtors.

The carrying values on the balance sheet are stated net of the unamortised portion of issue costs and bank fees of $68 million of which $61 million relates to the RBL and is recognised in assets and $7 million is netted against the bond (2022: $82 million of which $73 million related to the RBL and $9 million related to the bond both of which were netted off against the borrowings).

17. Related Parties

Transactions between the company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note.

Harbour Energy's Viking CCS entered into an arrangement with West Burton Energy, the independent power generation company based in Nottinghamshire, which is a subsidiary of EIG, Harbour's largest shareholder. The intention is to capture, transport and permanently store CO2 emissions from the West Burton B power station. Harbour Energy and West Burton Energy have begun the necessary engineering design to connect West Burton B to the high-capacity Viking CCS storage sites located beneath the Southern North Sea.

There have not been any financial transactions with West Burton Energy in 2023.  

Compensation of key management personnel of the Group

Remuneration of key management personnel, including Directors of the Group, is shown below.

	2023 $ million	2022 $ million
Salaries and short-term employee benefits	13	15
Payments made in lieu of pension contributions	1	1
Total	14	16

18. Distributions made and proposed

A final dividend of 12 cents per ordinary share in relation to the year ended 31 December 2022 was paid on 24 May 2023 pursuant to shareholder approval received on 10 May 2023.

Pursuant to shareholder approval received on 10 May 2023, an interim dividend of 12 cents per ordinary share in relation to the half year ended 30 June 2023 was paid on 18 October 2023.

	2023 $ million	2022 $ million
Cash dividends on ordinary shares declared and paid:
Final dividend for 2022: 12 cents per share (2021: 11 cents per share)	99	98
Interim dividend for 2023: 12 cents per share (2022: 11 cents per share)	91	93
Total	190	191
Proposed dividends on ordinary shares:
Final dividend for 2023: 13 cents per share (2022: 12 cents per share)	100	100

Proposed dividends on ordinary shares are subject to approval at the annual general meeting and are not recognised as a liability as at 31 December.

19. Post balance sheet events

On 5 March 2024 Harbour signed a new $3.0 billion fully unsecured revolving credit facility (RCF) and $1.5 billion bridge facility which will be available at completion to fund the acquisition of the Wintershall Dea asset portfolio. The RCF has a $.1.75 billion letter of credit sub-limit, a five-year term from signing and will replace the existing RBL facility.

On 6 March 2024, the UK government announced that Energy Profit Levy (EPL) would be extended for a further 12 months to 31 March 2029 from the former end date of 31 March 2028. Harbour is currently assessing the potential impact of this announcement.

Glossary

2C	Best estimate of contingent resources
2P	Proven and probable reserves
AGM	Annual general meeting
APS	Announced Pledges Scenario
bbl	Barrel
boe	Barrel of oil equivalent
CCS	Carbon capture and storage
CGU	Cash generating unit
DD&A	Depreciation, depletion and amortisation
DRIP	Dividend re-investment plan
EBITDAX	Earnings before interest, tax, depreciation, amortisation and exploration
EFF	Exploration financing facility
EPL	Energy Profits Levy (UK)
EPS	Earnings per share
ESOP	Employee stock ownership plan
ETS	Emission trading system
FEED	Front End Engineering & Design
FPSO	Floating production storage offtake vessel
FVLCD	Fair value less cost of disposal
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas emissions
IAS	International Accounting Standards
IASB	International Accounting Standards Board
IBOR	Inter-bank Offered Rates
ISDA	International Swaps and Derivatives Association
IFRSs	International Financial Reporting Standards
kboepd	Thousand of barrels of oil equivalent per day
LC	Letter of credit
LIBOR	London Inter-bank Offered Rates
mbtu	Million British thermal unit
mmbbl	Million barrels of oil
mmboe	Million barrels of oil equivalent
mscf	Thousand standard cubic feet
NBP	Natural gas prices
NOK	Norwegian krone
OECD	Organisation for Economic Co-operation and Development
PP&E	Property, plant and equipment
PSC	Production sharing contract
RBL	Reserves-based lending
RCF	Revolving credit facility
SOFR	Secured Overnight Financing Rate
SPA	Sales and purchase agreement
STEPS	IEA Stated Policies
Therm	Unit of UK natural gas
VER	Voluntary emissions reductions
WACC	Weighted average cost of capital

Non-IFRS measures

Harbour uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles (GAAP). These non-IFRS measures, which are presented within the financial review, are defined below:

§ Capital investment: Depicts how much the Group has spent on purchasing fixed assets in order to further its business goals and objectives. It is a useful indicator of the Group's organic expenditure on oil and gas assets, and exploration and appraisal assets, incurred during a period.

§ DD&A per barrel: Depreciation and amortisation of oil and gas properties for the period divided by working interest production. This is a useful indicator of ongoing rates of depreciation and amortisation of the Group's producing assets.

§ EBITDAX: Earnings before interest, tax, depreciation and amortisation, impairments, remeasurements, onerous contracts and exploration expenditure. This is a useful indicator of underlying business performance.

§ Free cash flow: Operating cash flow less cash flow from investing activities less interest and lease payments and is before shareholder distributions.

§ Leverage ratio: Net debt divided by the last 12 months EBITDAX.

§ Liquidity: The sum of cash and cash equivalents on the balance sheet and the undrawn amounts available to the Group on our principal facilities. This is a key measure of the Group's financial flexibility and ability to fund day-to-day operations.

§ Net debt: Total reserves-based lending facility and bond (net of the carrying value of unamortised fees) less cash and cash equivalents recognised on the consolidated balance sheet. This is an indicator of the Group's indebtedness and contribution to capital structure.

§ Operating cost per barrel: Direct operating costs (excluding over/underlift) for the period, including tariff expense, insurance costs and mark to market movements on emissions hedges, less tariff income, divided by working interest production. This is a useful indicator of ongoing operating costs from the Group's producing assets.

§ Shareholder returns paid: Dividends plus share buybacks completed in the period are included in this metric which shows the overall value returned to stakeholders in the period.

§ Total capital expenditure: Capital investment 'additions' per notes 9 and 10 plus decommissioning expenditure 'amounts used' per note 13.

Group reserves and resources

Oil and gas 2P reserves and 2C resources¹

	UK			International2			Total
	Oil, NGLs	Gas	Total	Oil, NGLs	Gas	Total	Oil, NGLs	Gas	Total
	mmbbls	bcf	mmboe	mmbbls	bcf	mmboe	mmbbls	bcf	mmboe
2P reserves (working interest)
1 January 2023	213	936	390	9	57	20	221	993	410
Revisions and additions3	1	87	17	-	11	2	2	98	19
Production	(31)	(173)	(64)	(1)	(14)	(4)	(33)	(186)	(68)
31 December 2023	183	851	343	7	54	18	190	905	361
2P reserves (entitlement)4
31 December 2023	183	851	343	6	43	14	189	893	357
2C resources (working interest)
1 January 2023	142	361	204	137	657	250	279	1,019	455
Revisions, additions, relinquishments5	3	(27)	(2)	25	238	66	28	210	64
31 December 2023	145	334	202	162	895	316	307	1,229	519

¹ Volumes reflect internal estimates. ERCE as a competent independent person has audited the Group's 2P net entitlement and working interest reserves as at 31 December 2023 and ERCE considers these to be fair and reasonable as per the SPE Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information. ERCE has also audited c. 80 per cent of the Group's 2C contingent resources as at 31 December 2023 and is of the opinion that Harbour's estimates are fair and reasonable. Further, ERCE believes that if its audit had included all of Harbour's 2C resources then it would have been able to express the same opinion. Conversion of gas volumes from bcf to boe is determined using an energy conversion of 5.8 mmbtu per boe. Fuel gas is not included in these estimates.

² International consists of Indonesia, Vietnam and Mexico.

³ UK 2P reserves additions includes over 20 mmboe of additions across Harbour's UK operated J-Area, AELE and GBA hubs, following the approval of several new wells

⁴ Harbour's net entitlement 2P reserves are lower than its working interest 2P reserves for its international assets, reflecting the terms of the Production Sharing Contracts (PSC).

⁵ Increase in 2C resource largely reflects the addition of the Layaran gas discovery in Indonesia and the Kan oil discovery in Mexico.

The Group provides for amortisation of costs relating to evaluated properties based on direct interests on an entitlement basis, which incorporates the terms of the PSCs in Indonesia and Vietnam. On an entitlement basis, reserves were 357 mmboe as at 31 December 2023.

Because of rounding, some totals may not agree exactly with the sum of their component parts.

CO₂ Storage capacity

2C resources (working interest)1	UK (million tonnes)
1 January 2023	300
Additions and disposals2	(78)
31 December 2023	222

¹ Reflects Harbour's internal estimates which have been externally audited by ERCE, a competent independent person. ERCE considers Harbour's internal estimates to be fair and reasonable.  

² Reflects the addition of storage resource associated with Harbour's 30 per cent working interest in the Acorn project offset by the impact of bp joining the Viking project with a 40 per cent interest during 2023. Excludes any potential storage capacity associated with the two Viking licences which were awarded during 2023 and are in the process of being appraised and volumes associated with several further development options available to Acorn.

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[1] See Glossary for the definition of non-IFRS measures used in this section.

[2] Total spend on share buybacks includes transaction fees and foreign exchange differences applied to the sterling denominated shares repurchased.

[3] 2024 and 2025 outlook excludes any effects from the Acquisition

[4] $200 million free cash flow forecast provided in January 2024 reflected $85/bbl and 100p/therm

[5] Hedge price for gas hedge collars reflects the forward curve as at 6 March 2024

[6] Formal legal implementation of amendments to follow

[7] Based on 2023 production numbers.

[8] $200 million free cash flow sensitivity provided in January 2024 reflected $85/bbl and 100p/therm

[9] Difference to the final dividend value declared of $100 million is due to foreign exchange adjustments on sterling denominated shares at the date of payment.

[10] Difference to the interim dividend declared of $100 million is due to foreign exchange adjustments on sterling denominated shares and reduced share count in issue between the record date and the announcement driven by the repurchases of shares.

[11] Total spend on share buybacks includes transaction fees and foreign exchange differences applied to the sterling denominated shares repurchased.

 

END