REG - Harbour Energy PLC - Full year results for the year to 31 December 2025
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RNS Number : 4774V Harbour Energy PLC 05 March 2026
THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION
Harbour Energy plc
("Harbour" or the "Company" or the "Group")
Full year results for the year to 31 December 2025
5 March 2026
Harbour Energy plc today announces its results for the year ended 31 December
2025.
Linda Z Cook, Chief Executive Officer, commented:
"2025 was a year of significant progress for Harbour. We delivered excellent
operational performance while maintaining capital discipline and integrating
new assets. This drove record production and higher free cash flow against a
backdrop of lower commodity prices. In addition, we improved our cost
structure, built momentum at our growth projects in Mexico and Argentina, and
announced three significant transactions. Together these actions position
Harbour's portfolio to deliver higher margin production over the coming years,
leading to material growth in free cash flow.
Today we also announced details of our new distributions policy that links
shareholder returns directly to free cash flow. The policy strikes the right
balance across the commodity price cycle between our commitment to a strong
balance sheet, unlocking the potential of our portfolio and delivering
attractive shareholder returns.
2026 is off to a strong start. Production over the first two months of the
year averaged 509 thousand barrels per day and we completed the LLOG
transaction on 11 February, marking our entry into the US deepwater Gulf.
Looking ahead, our focus remains on safety, operational excellence, advancing
our growth projects, strengthening the balance sheet and completing the
Waldorf and Indonesia transactions."
Excellent operational delivery
§ Record production of 474 kboepd (2024: 258 kboepd), up 84%
§ Unit operating costs reduced by 22% to $12.8/boe (2024: $16.5/boe)
§ Total recordable injury rate (TRIR) of 1.1 per million hours worked (2024:
1.0)
§ New wells and projects online in the UK, Norway, Argentina and Egypt
§ Exploration and appraisal successes in Egypt and Norway
§ 2P reserves and 2C resources of 3.0 bnboe at year end (2024: 3.2 bnboe)
Material strategic progress
§ Appointed operator of the 750 mmboe gross recoverable Zama oil field
(Mexico, Harbour 32%) and a new, more capital efficient, phased FPSO-based
development plan agreed
§ Construction underway at Southern Energy (Argentina), a 6 mtpa LNG project
(Harbour 15%) due to commence operations end 2027
§ Exited Vietnam; announced Indonesia divestments for $215 million with
completion expected in Q2 2026
§ Announced $170 million acquisition of Waldorf (UK) with the potential to
unlock significant financial synergies including UK tax losses with an
expected value of $900 million. Completion expected end Q2 2026
§ Post period end, completed the $3.2 billion LLOG acquisition, securing a
fully operated, oil weighted portfolio in the deepwater US Gulf with a long
reserve life, a compelling growth outlook and significant running room
Financial highlights(( 1 (#_ftn1) ))
§ Realised post-hedge oil and European gas prices of $69/bbl and $13/mscf
(2024: $82/bbl and $11/mscf)
§ Increased revenue and other income of $10.3 billion (2024: $6.2 billion)
and adjusted EBITDAX of $7.2 billion (2024: $4.1 billion)
§ Increased free cash flow of $1.1 billion (2024: $0.1 billion)
§ Increased adjusted profit after tax of $0.6 billion (2024: $0.4 billion),
equating to adjusted earnings per voting ordinary share of 31 cents (2024: 33
cents)
§ Reported loss after tax of $0.2 billion (2024: $0.1 billion), reflecting a
106% effective tax rate and impacted by a $0.3 billion deferred tax charge
associated with changes to the UK fiscal regime and $0.7 billion of pre-tax
impairments and exploration write-offs in our North Africa, Mexico and CCS
portfolios
§ Investment grade credit ratings of Baa2 (negative outlook), BBB- and BBB-
(credit watch negative) by Moody's, Fitch and S&P, respectively
Shareholder distributions
Harbour has adopted an updated distributions policy which links shareholder
returns directly to free cash flow and strengthens our capital allocation
framework across the commodity price cycle. The new policy includes a base
dividend and supports deleveraging alongside disciplined investment in
attractive organic growth opportunities in the near term. This will underpin
future production and free cash flow growth, driving enhanced shareholder
returns over time.
§ Since 2022, Harbour has on average returned c.40% of annual free cash flow
to shareholders
§ Under the new policy, Harbour will target returning 45-75% of free cash
flow each year, including an initial base dividend of 16.10 cents/voting
ordinary share ($300 million(( 2 (#_ftn2) )))
§ While leverage is above 1.0x, Harbour expects to pay out towards the lower
end of the range, prioritising debt reduction. As leverage falls below 1.0x,
Harbour expects to pay out towards the top end of the range
§ In line with the new policy, Harbour has declared a 2025 final dividend of
8.05 cents/voting ordinary share ($150 million(( 3 (#_ftn3) ))). This brings
total distributions for 2025 to $478 million, representing a c.45% free cash
flow payout
2026 guidance and outlook
2026 guidance and outlook is updated to include the impact of the LLOG
acquisition and assumes completion of the Indonesia and Waldorf (UK)
transactions end Q2 2026:
§ For 2026 Harbour now expects:
- Production of 475-500 kboepd. Production to end February averaged
509 kboepd including one month's contribution from LLOG
- Unit operating costs of c.$14.5/boe
- Total capital expenditure of $2.2-2.4 billion, reflecting additional
expenditure relating to the LLOG and Waldorf acquisitions
- Free cash flow of c.$0.6 billion(( 4 (#_ftn4) )), assuming $65/bbl
Brent and $11/mscf European gas prices. A $5/bbl change in Brent or $1/mscf
change in European gas prices for the full year impacts our 2026 free cash
flow by c.$170 million or c.$150 million respectively
§ Beyond 2026:
- Production is expected to be maintained in the range of 475-500 kboepd
through to 2030, supported by total capex of $2.0-2.3 billion per annum with
unit operating costs less than $15/boe
- Annual free cash flow expected to increase to c.$1.0 billion in
2028(( 5 (#_ftn5) )), driven by the LLOG and Waldorf acquisitions
- Further free cash flow margin growth expected around the end of the
decade, driven by continued growth from the LLOG portfolio and as Harbour's
Mexico projects come onstream
- With anticipated additions to reserves in Argentina, Mexico, Norway
and the US Gulf, the 2P reserves replacement ratio for the period year end
2025 to 2028 is projected to be over 100 per cent
- Net debt on completion of LLOG was $7.2 billion with leverage
anticipated to be slightly above Harbour's target of <1.0x at year end
2026, reducing to 1.0x in 2028
Enquiries
Harbour Energy
plc
+44 (0) 203 833 2421
Elizabeth Brooks, SVP Investor Relations
Andy Norman, SVP Communications
Email: CorporateExternalCommunications@harbourenergy.com
(mailto:CorporateExternalCommunications@harbourenergy.com)
Online presentation for analysts and investors
Management will host a live online presentation for analysts and investors at
9.00am (GMT). The link to register, and the presentation, will be available on
www.harbourenergy.com (http://www.harbourenergy.com) . A replay will be
available on Harbour's website shortly after the event.
Forward looking statements
This statement contains certain forward-looking statements that are subject to
the usual risk factors and uncertainties associated with the oil and gas
exploration and production business. Whilst Harbour believes the expectations
reflected herein to be reasonable in light of the information available to
them at this time, the actual outcome may be materially different owing to
factors beyond Harbour's control or within Harbour's control where, for
example, Harbour decides on a change of plan or strategy. Accordingly, no
reliance may be placed on the figures contained in such forward-looking
statements.
The information contained within this announcement is deemed by Harbour to
constitute inside information for the purposes of the UK Market Abuse
Regulation. By the publication of this announcement via a Regulatory
Information Service, this inside information is now considered to be in the
public domain. The person responsible for arranging for the release of this
announcement on behalf of Harbour is Howard Landes, General Counsel
Summary of 2025 performance
Excellent operational execution
In 2025, we delivered production of 474 kboepd (2024: 258 kboepd), at the top
end of guidance and split approximately 40 per cent liquids, 40 per cent
European natural gas and 20 per cent other natural gas. The 84 per cent
increase versus 2024 reflects a full year's contribution from the Wintershall
Dea assets, including 169 kboepd from Norway and 73 kboepd from Argentina, and
excellent operational execution.
Production was supported by new wells onstream including in the UK, Norway,
Argentina and Egypt, the completion of the Fenix project in Argentina and
Maria Phase 2 in Norway, as well as continued high reliability across the
portfolio. In addition, we saw outperformance from our operated hubs in the
UK.
2026 production is expected to increase to between 475-500 kboepd, reflecting
contributions from the LLOG and Waldorf portfolios partially offset by managed
decline in the UK and the divestment of producing assets in Indonesia and
Vietnam.
Strict cost and capital discipline
In 2025 we reduced our unit operating costs by 22 per cent to $12.8/boe (2024:
$16.5/boe). This reflected the addition of the lower cost Wintershall Dea
portfolio and the exit from Harbour's higher cost Vietnam business partially
offset by a weaker US dollar sterling exchange rate. We also captured early
savings as part of the Wintershall Dea integration process and further
improved our UK cost base.
2025 capital expenditure including decommissioning spend totalled $2.4 billion
(2024: $1.8 billion), with the increase reflecting the addition of the
Wintershall Dea assets. The outturn at the lower end of original guidance of
$2.4-2.6 billion was driven by high grading and cost efficiency measures
across several of our business units including reduced activity in the UK, a
pause in drilling in the APE Vaca Muerta gas licence (Argentina), and the
reduction of some expenditures in Mexico and across our portfolio of CCS
projects.
For 2026, Harbour expects operating costs of c.$14.5/boe and total capital
expenditure of $2.2-2.4 billion, reflecting the addition of the LLOG and
Waldorf assets.
Safe and responsible operations
2025 saw a slight increase in Harbour's total recordable injury rate to 1.1
per million hours worked (2024: 1.0) as we expanded our operations into new
jurisdictions. While there was a reduction in the number of Tier 2 process
safety events versus 2024, we recorded one Tier 1 event in Mexico during the
year. All safety events continue to be rigorously investigated with learnings
shared across the Company to drive improved performance.
In 2025 we delivered a step change in our GHG intensity which reduced to 13
kgCO(2)e/boe (2024: 18 kgCO(2)e/boe) on a net equity share basis. This was
driven primarily by the addition of the lower GHG intensity Wintershall Dea
assets alongside the divestment of our Vietnam business and continued
decarbonisation efforts. We remain on track to halve our gross operated
emissions by 2030 relative to our 2018 baseline.
Maximising the value of our producing assets
The majority of Harbour's capital programme is focused on infrastructure-led
opportunities, profitably converting reserves into production and cash flow.
These opportunities are typically low risk, high return investments
concentrated around our existing production hubs.
In Norway, we completed our operated Maria Phase 2 project on schedule and
within budget, marking the first of six Norway subsea developments due
onstream during 2025-2027. Production start-up from our operated Dvalin North
field is on track for mid-2026, with installation of the subsea infrastructure
completed in 2025 and development drilling underway. Subsea installation
campaigns were also completed at Alve North and Idun North, both being
developed as multi-well tie-backs to Skarv, and at Irpa, a three-well tie-back
to Aasta Hansteen. These projects, as well as infill drilling, are expected to
maintain current production levels in Norway.
In the UK, investment in 2025 was targeted at our two largest operated hubs,
J-Area and the Greater Britannia Area (GBA). At J-Area, Jocelyn South came
onstream just three months after discovery in March, production started up
from the RK development well in July and successful well interventions were
carried out late in the year. Together with strong subsurface performance from
Talbot, these activities contributed to the J-Area achieving production rates
not seen for over a decade. The GBA satellite fields Callanish and Brodgar
also continued to outperform, with Brodgar production supported by plant
optimisation and the successful H5 development well.
In Argentina, at our offshore CMA-1 concession, production was supported by
the three-well Fenix project completed in January and a successful Aries
platform well workover. Onshore in the Vaca Muerta unconventional shale play,
ten 3,000 metre lateral gas wells were drilled with nine new wells completed
and connected, supporting production from APE. Drilling resumed in November
after a three month pause to align with lower domestic demand requirements.
Elsewhere, development activities across our three production hubs in Germany
- Mittelplate, Gas Nord and Emlichheim - continued to provide stable
production while in Egypt two Raven West infill wells at West Nile Delta were
brought onstream. We also delivered exploration success in Egypt including at
West Nile Delta, with the Fayoum-5 and El King gas discoveries, and at Disouq
with EZZ-1, which was bought onstream in January 2026, only two months after
discovery.
Progressing our highest return, most competitive projects supporting reserves
and future cash flow
In Norway, Harbour continued to progress its pipeline of potential
developments and infill wells towards final investment decisions (FIDs). These
include the Gjøa subsea satellite projects which are targeting a 2026 FID
while development concept studies are underway at Adriana/Sabina, Storjo and
Cuvette. Additionally, Harbour made a small discovery close to the Skarv
infrastructure in 2025. Post period end, a discovery was made at Omega Sør
(Harbour 24 per cent) near the Snorre field and Harbour was awarded nine
exploration licences in the APA 2025 licensing round, four as operator and all
close to existing infrastructure.
In Mexico, we saw good momentum at the 750 mmboe gross Zama oil field (Harbour
32 per cent) with Harbour being appointed operator and a more capital
efficient, phased FPSO-based development plan being agreed. FEED is planned
for 2026 ahead of FID. We also increased the gross resource estimate of our
operated Kan field (70 per cent Harbour) by 50 per cent to 150 mmboe and are
maturing development options ahead of FEED. As operator of Zama and Kan, we
see the potential for material synergies across the two projects and for
leveraging the offshore technical experience acquired through LLOG.
In Indonesia, Harbour retains its interests in the potential multi-TCF Andaman
Sea gas discoveries, where we are evaluating potential development options,
including an accelerated, phased development starting at Tangkulo.
In Argentina, Harbour and its partners took FID on Southern Energy SA (SESA,
Harbour 15 per cent), a phased, two vessel 6 mtpa LNG project. This marks a
significant milestone, providing access to global markets for our extensive
Argentinian gas resource. 2025 saw all environmental licences, export permits
and RIGI incentives secured for both vessels and all major contracts awarded
with construction now underway. Production start-up from the first vessel is
on track for end 2027, with the second vessel to commence operations end
2028.
Also in Argentina, at the San Roque concession (Harbour 25 per cent), Harbour
and its partners are in the process of applying for an unconventional licence.
This would allow development of the Vaca Muerta black oil shale to commence,
starting with a potential 16 well programme later in 2026. With more than 700
mmboe of 2C resources, mainly in the Vaca Muerta shale play, and the potential
to add materially to this, Argentina represents the largest single component
of Harbour's 2C resources and a significant reserve replacement opportunity
for the Company.
As at year end 2025, Harbour's proven and probable (2P) reserves on a working
interest basis stood at 1.12 billion boe (2024: 1.25 billion boe), with
additions including at CMA-1 in Argentina and J-Area in the UK partially
offsetting the impact of production. In addition, Harbour had 1.84 billion boe
of 2C resources (2024: 1.91 billion boe). Additions to our 2C resources
resulted from the successful appraisal of Kan in Mexico and discoveries in
Egypt offset by transfers to 2P reserves and further high grading of our UK
and Mexico portfolios. Combined, our 2P and 2C volumes at year end 2025,
represented 18 years reserves and resources life(( 6 (#_ftn6) )).
Harbour's 2P reserves replacement averaged c.250 per cent per annum over the
four-year period from year end 2021 to 2025. For 2026, we anticipate at least
150 per cent reserves replacement supported by the expected reserve additions
from the LLOG and Waldorf acquisitions.
Building a competitive CCS business
Harbour has a leading CO(2) storage position in Europe with 880 million tonnes
of net storage resource, offering the potential for a new source of long-term
stable cash flow. In 2025, we continued to mature our most advantaged
projects.
At our operated Viking project in the UK (Harbour 60 per cent), FEED was
completed in March and the development consent order for the onshore pipeline
was approved. We also welcomed the government's intention to provide
development funding for Viking up to FID. Key milestones to FID include
emitter selection and negotiation of the economic licence to be awarded by the
government.
In Denmark, the high return Greensand Future project (Harbour 40 per cent) is
on track to commence commercial operations by early 2027 with an injection
rate of c.400 ktpa. Onshore Denmark, Harbour has a 40 per cent operated
interest in the onshore Greenstore project which is progressing through the
appraisal phase. Seismic acquisition commenced in December, marking a key step
towards advancing the project towards development.
In May, in line with the Havstjerne licence commitment, we delivered a
successful CO(2) storage appraisal well in the Norwegian North Sea safely and
below budget, confirming the existence of a high quality store.
Active portfolio management
We continue to actively manage our portfolio, ensuring our capital and
resources are allocated to our most competitive projects and in line with our
strategy. In July we exited our Vietnam business and, in December, we
announced the sale of the high cost, sub-scale Natuna Sea Block A field along
with the Tuna development project in Indonesia for $215 million, improving the
overall quality of our portfolio and accelerating value. We also agreed to
exit several early-stage projects in Mexico, including Polok and Chinwol, and
CCS licences during the year.
In December, we announced the acquisition of Waldorf in the UK for $170
million. Once completed, this acquisition will help to improve the
competitiveness and resilience of our UK business amid ongoing fiscal and
regulatory challenges by adding c.$900 million in value through UK tax losses.
In addition, upon completion c.$350 million of trapped cash is unlocked, more
than covering the purchase price. Completion, which is anticipated by
mid-year, is subject to final settlement of all creditors' claims against
Waldorf. The transaction is currently being implemented via court approved
Restructuring Plans.
Also in December, we announced the acquisition of LLOG for $3.2 billion.
Through LLOG, Harbour gains a fully operated, oil weighted portfolio and an
exceptional team in one of the world's most prolific oil and gas basins. LLOG
adds high margin, long-life assets with a compelling growth profile,
underpinned by a deep inventory of high return drilling opportunities. The
acquisition completed post period end in February 2026.
Collectively, these transactions demonstrate Harbour's disciplined approach to
capital allocation, recycling proceeds into cash flow accretive growth
opportunities while enhancing the overall quality of our portfolio.
Significant cash flow generation and strong financial position
Harbour generated free cash flow of $1.1 billion in 2025, a significant
increase versus 2024 and c.$0.5 billion above the outlook provided at the
start of the year after normalising for commodity prices. This was driven by
strong operational execution, rigorous capital discipline and the greater
scale and resilience of our portfolio.
Net debt (including funds held in escrow and before unamortised fees) reduced
to $4.4 billion at year end 2025 (2024: $4.7 billion). This reflects a weaker
USD, which increased the value of our euro-denominated debt by c.$0.6 billion,
partly offset by $0.4 billion of net hybrid issuances. Post period end, on
11 February, we completed the LLOG acquisition, funded through a combination
of $0.5 billion of equity and $2.7 billion of cash, including a $1 billion
bridge facility and $1 billion three year term loan. As a result, net debt
increased to $7.2 billion. Consistent with our approach on past
acquisitions, we will prioritise debt reduction until our leverage returns to
target levels.
At year-end 2025, we had a strong hedge position with a mark to market gain of
$0.5 billion. For 2026, c.50 per cent of our economic exposure to European gas
prices and c.40 per cent of our economic exposure to Brent is currently hedged
at $11/mscf and $71/bbl respectively.
Competitive and meaningful shareholder distributions
Following the recent announced transactions, Harbour has updated its
distributions policy to a payout ratio approach that links shareholder returns
directly to free cash flow and leverage. This change strengthens our capital
allocation framework and enhances our resilience to commodity price downturns.
It also aligns our policy with our peers.
Since 2022, Harbour has on average returned c.40 per cent of free cash flow to
shareholders each year. Under the new policy, we will target returning 45-75
per cent of annual free cash flow, including an initial base dividend of 16.10
cents/voting ordinary share ($300 million(( 7 (#_ftn7) ))) providing a
minimum payout to shareholders, with potential for additional returns. When
leverage is above Harbour's target of less than 1.0x, Harbour expects
shareholder distributions to be towards the low end of the payout range,
prioritising debt reduction and balance sheet strength. As leverage falls
below 1.0x, Harbour expects to increase the payout towards the top end of the
range which, together with growing free cash flow, is expected to support
increasing shareholder returns over time.
In line with the new policy, Harbour has declared a final 2025 dividend of
8.05 cents/voting ordinary share. Combined with the 2025 interim dividend and
$100 million share buyback announced in August 2025, distributions for 2025
total $478 million, representing a c.45 per cent free cash flow payout.
Our new policy enables us to distribute a base dividend, prioritise near-term
deleveraging and invest in highly attractive, high margin growth
opportunities. These investments support future production and increasing free
cash flow, driving enhanced shareholder returns over the coming years.
2026 Outlook
We had a strong start to the year. Production over the first two months
averaged 509 kboepd including a month's contribution from the LLOG portfolio.
Production is expected to average 475-500 kboepd during 2026, a level which
can be sustained through the end of the decade given our deep inventory of
organic investment opportunities. Unit operating costs for 2026 are guided at
c.$14.5/boe and total capital expenditure is now expected to be $2.2-2.4
billion, including growth investment in the LLOG assets.
At $65/bbl Brent and $11/mscf European gas prices, 2026 free cash flow is
estimated at c.$0.6 billion(( 8 (#_ftn8) )). Looking ahead we expect free
cash to increase to c.$1 billion in 2028, as higher margin new volumes replace
higher cost, higher tax UK barrels. We anticipate another significant step up
in free cash flow around the end of the decade driven by continued growth from
the LLOG portfolio and as our Mexico growth projects come onstream.
Our focus for 2026 is on safety and operational excellence, advancing our
growth projects, strengthening the balance sheet and completing the Waldorf
and Indonesia transactions as we continue to build a more resilient, cash
generative business. We are excited about the opportunities ahead and
realising the full potential of our company for our shareholders.
Financial Review
Summary of financial results
Units 2025 2024
Production and post-hedging realised prices
Production kboepd 474 258
Crude oil $/boe 69 82
European gas $/mscf 13 11
Other gas $/mscf 4 4
Income statement
Revenue and other income $ million 10,261 6,226
EBITDAX(1) $ million 7,118 4,027
Adjusted EBITDAX(1) $ million 7,196 4,146
Profit before taxation $ million 2,801 1,219
Loss after taxation $ million (182) (93)
Adjusted profit after taxation(1) $ million 603 370
Effective tax rate Per cent 106 108
Adjusted effective tax rate(1) Per cent 82 79
Operating costs per barrel(1) $/boe 12.8 16.5
Basic loss per ordinary voting share cents/share (15) (10)
Adjusted basic earnings per voting ordinary share(1) cents/share 31 33
Other financial key figures
Total capital expenditure(1) $ million 2,370 1,828
Operating cash flow $ million 3,386 1,615
Free cash flow(1) $ million 1,066 (118)
Shareholder returns paid(1) $ million 545 199
Net debt(1) $ million 4,305 4,424
Leverage ratio(1) times 0.6 1.1
1 Alternative performance measure - see Glossary for the definition.
Reconciliations between adjusted performance measures and reported measures
are provided within the Glossary.
Income statement
2025 2024
$ million $ million
Revenue and other income 10,261 6,226
Cost of operations (5,564) (3,613)
EBITDAX(1) 7,118 4,027
Adjusted EBITDAX(1) 7,196 4,146
Operating profit 3,490 1,648
Profit before tax 2,801 1,219
Taxation (2,983) (1,312)
Loss after tax (182) (93)
Adjusted profit after tax(1) 603 370
2025 2024
Cents/share Cents/share
Basic loss per ordinary voting share (15) (10)
Adjusted basic earnings per voting ordinary share(1) 31 33
1 Alternative performance measure - see Glossary for the definition.
Reconciliations between adjusted performance measures and reported measures
are provided within the Glossary.
Revenue and other income
Total revenue and other income increased to $10,261 million (2024: $6,226
million).
2025 2024
$ million $ million
Revenue and other operating income 10,261 6,226
Crude oil 3,487 2,878
Gas 6,033 2,936
Condensate 511 283
Tariff income and other revenue 60 61
Other operating income 170 68
Revenue earned from hydrocarbon production activities increased to $10,031
million (2024: $6,097 million) after net realised hedging gains of $101
million (2024: $18 million, losses). This increase was mainly driven by higher
production volumes and higher post-hedging European natural gas prices,
partially offset by lower post-hedging crude oil prices.
Crude oil sales increased to $3,487 million (2024: $2,878 million) after
realised hedging gains of $116 million (2024: $32 million). This was driven by
higher production volumes partially offset by lower post-hedging crude oil
prices of $69/bbl (2024: $82/bbl).
Gas revenue was $6,033 million (2024: $2,936 million), split between European
gas revenue of $5,337 million (2024: $2,644 million) including realised
hedging losses of $15 million (2024: $50 million) and other gas revenue of
$696 million (2024: $292 million). The realised post-hedging price for our
European and other gas was $13/mscf (2024: $11/mscf) and $4/mscf (2024:
$4/mscf), respectively.
Condensate revenue was $511 million (2024: $283 million) and tariff income and
other revenue $60 million (2024: $61 million). Other income amounted to $170
million (2024: $68 million) .
Cost of operations
Cost of operations increased to $5,564 million (2024: $3,613 million) driven
primarily by the impact of a full year of the enlarged portfolio. Cost of
operations includes operating costs of $2,317 million (2024: $1,612 million)
and depreciation, depletion and amortisation expense of $2,907 million (2024:
$1,704 million) as discussed below along with over/underlift movements and
other items totalling $340 million (2024: $297 million).
2025 2024
$ million $ million
Cost of operations
Field operating costs 2,317 1,612
Depreciation, depletion and amortisation 2,907 1,704
Other 340 297
Operating costs 5,564 3,613
Total operating costs for operating costs per barrel(1) 2,217 1,555
Operating costs per barrel ($ per barrel)(1) 12.8 16.5
1 Alternative performance measure - see Glossary for the definition.
Reconciliations between adjusted performance measures and reported measures
are provided within the Glossary.
Total operating costs increased to $2,217 million (2024: $1,555 million)
driven by the impact of a full year of the acquired portfolio. However, on a
unit of production basis, costs have materially reduced at $12.8/boe (2024:
$16.5/boe), reflecting the lower cost base of the enlarged portfolio.
Depreciation, depletion and amortisation unit expense, which reflects the
current period capitalised costs of producing assets divided by produced
volumes, decreased to $16.8/boe (2024: $18.5/boe).
General and administrative expenses
General and administrative expenses amounted to $536 million (2024: $352
million). The increase was driven by the enlarged group, including expansion
of our corporate centre, and one-off M&A, restructuring and
reorganisation-related transaction costs of $78 million (2024: $119 million)
associated with various initiatives and M&A activities across the group.
2024 solely related to costs associated with the Wintershall Dea acquisition.
Impairments and exploration costs
The Group has recognised a net pre-tax impairment charge on property, plant
and equipment of $365 million (2024: $352 million). Of this, $41 million
(2024: $174 million) was in respect of revisions to decommissioning estimates
on mainly non-producing assets with no remaining book value. There was was
also an impairment of $35 million (2024: $15 million) associated with the
disposal of our Vietnam assets. The remainder largely relates to impairments
in the Mexico and North Africa driven by reserves reductions and field
performance.
During the year, the Group expensed $306 million (2024: $241 million) of
exploration and appraisal activities. This covers exploration write-off
expense of $200 million (2024: $173 million) including costs associated with
projects in Norway ($22 million, 2024: UK $79 million), licence
relinquishments in the UK ($40 million) and Mexico ($107 million, 2024:
Norway, $64 million), and $84 million (2024: $40 million) costs primarily
associated with carbon capture and storage activities.
EBITDAX(1)
EBITDAX(1) was $7,118 million (2024: $4,027 million), with the increase driven
by the enlarged group. Adjusted EBITDAX(1) was $7,196 million (2024: $4,146
million), an increase of $3,050 million.
Net financing costs
Finance income amounted to $461 million (2024: $173 million). The increase
compared to 2024 is primarily due to realised gains on foreign exchange
forward contracts of $191 million and changes in the fair value of foreign
exchange derivatives of $109 million.
Finance expenses amounted to $1,150 million (2024: $602 million). This
included:
▪ interest expense incurred of $176 million (2024: $78 million)
related to debt facilities and bonds;
▪ bank and financing fees of $123 million (2024: $139 million);
▪ unwinding of the discount on decommissioning provisions of $293
million (2024: $221 million);
▪ lease interest of $40 million (2024: $53 million); and
▪ unrealised foreign exchange losses of $485 million (2024: $118
million, gain) which predominantly arose on the Group's tax liabilities and
intercompany balances due to the weakening of the US dollar.
Earnings and taxation
Loss after tax amounted to $182 million (2024: $93 million loss). This
resulted in a loss per ordinary voting share of 15 cents (2024: 10 cents,
loss) after taking into account the weighted average number of ordinary voting
shares in issue of 1,426 million (2024: 990 million). Adjusted profit after
tax was $603 million (2024: $370 million) which resulted in earnings per share
of 31 cents (2024: 33 cents).
After taking into consideration $81 million (2024: $15 million) attributable
to subordinated notes investors, loss after tax attributable to equity owners
of the company amounted to $263 million (2024: $108 million loss attributable
to equity owners of the company). Adjusted profit after tax amounted to $603
million (2024: $370 million), an increase of $233 million.
Harbour's tax expense increased to $2,983 million in 2025 (2024: $1,312
million), primarily driven by higher pre-tax profits resulting from the
additional earnings contributed by the acquisition and the extension of the UK
Energy Profits Levy (EPL). The tax expense comprises a current tax expense of
$3,505 million (2024: $1,415 million, expense) and a deferred tax credit of
$522 million (2024: $103 million, credit).
The effective tax rate of 106 per cent (2024: 108 per cent) is materially
higher than the statutory tax rate of 78 per cent (2024: 78 per cent). This is
primarily due to a $311 million deferred tax charge arising from legal
enactment of the extension of the EPL in the UK by two years, from 31 March
2028 to 31 March 2030, as well as non-deductible foreign exchange losses and
weighting of earnings across the various jurisdictions. The adjusted effective
tax rate is 82 per cent (2024: 79 per cent).
Shareholder distributions
A final dividend with respect to 2024 of 13.19 cents per ordinary share was
proposed on 6 March 2025 and approved by shareholders at the AGM on 8 May
2025. The dividend was paid on 21 May 2025 to all shareholders on the register
as at 11 April 2025, totalling $228 million. An interim dividend was announced
on 7 August 2025 at 13.19 cents per share and was paid on 24 September 2025 at
a value of $227 million.
The Board is proposing a final dividend with respect to 2025 of 8.05 cents per
voting ordinary share to be paid in pound sterling at the spot rate prevailing
on the record date. This dividend is subject to shareholder approval at the
AGM, to be held on 7 May 2026. If approved, the dividend will be paid on 20
May 2026 to shareholders as of 10 April 2026. The ex-dividend date is 9 April
2026. A dividend reinvestment plan (DRIP) is available to shareholders who
would prefer to invest their dividends in the shares of the company. The last
date to elect for the DRIP in respect of this dividend is 28 April 2026.
A DRIP is provided by Equiniti Financial Services Limited. The DRIP enables
the company's shareholders to elect to have their cash dividend payments used
to purchase the company's shares. More information can be found
at www.shareview.co.uk/info/drip (http://www.shareview.co.uk/info/drip) .
Statement of financial position
2024
2025 As restated
$ million $ million
Assets
Goodwill 5,062 5,062
Non-current assets, excluding goodwill and deferred taxes 19,797 21,168
Deferred tax assets 121 130
Current assets 3,723 3,640
Assets held for sale 390 277
Total assets 29,093 30,277
Liabilities and equity
Borrowings net of transaction fees 5,151 5,229
Provisions 7,413 7,521
Deferred tax liabilities 6,491 6,177
Lease liabilities 634 792
Other financial liabilities 40 877
Other liabilities 2,944 3,197
Liabilities directly associated with assets held for sale 214 233
Total liabilities 22,887 24,026
Equity 6,206 6,251
Total liabilities and equity 29,093 30,277
Net debt 4,305 4,424
Assets
The decrease in total assets of $1,184 million to $29,093 million (2024:
$30,277 million, as restated) is mainly as a result of a reduction in
property, plant and equipment of $1,368 million, driven by impairment charges
of $365 million as well as an increase in depreciation $2,773 million (2024:
$1,522 million) relative to additions in the period $1,523 million (2024:
$1,059 million). Total assets include assets held for sale in respect of the
Indonesia disposal of $390 million (2024: Vietnam $277 million).
Liabilities
The decrease in total liabilities of $1,139 million to $22,887 million (2024:
$24,026 million) is primarily driven by the reduction in the fair value of the
Group's other financial liabilities, reducing to $40 million from $877
million, with the net financial instruments moving to a net asset position.
Total liabilities included liabilities directly associated with assets held
for sale in respect of the Indonesia disposal of $214 million.
The net deferred tax position on the statement of financial position is a
liability of $6,370 million (2024: $6,047 million, as restated). This
primarily consists of deferred tax liabilities in respect of the future
profits which will flow from our accelerated capital allowances of $9,012
million and fair value losses on derivatives $2,739 million, partially offset
by deferred tax assets in respect of future tax relief on decommissioning
spend of $331 million and tax losses of $194 million.
Equity and reserves
Total equity decreased by $45 million to $6,206 million (2024: $6,251
million). The decrease was driven by shareholder distributions of $545 million
(2024: $199 million), offset by the new issuance of subordinated notes in the
period of $970 million less the repayment of $558 million of the existing
notes. Movements in equity also included favourable post-tax fair value
movements on cash flow hedges of $429 million (2024: unfavourable of $166
million), offset by losses on currency translation of $182 million (2024: $130
million, gains) all recognised in other comprehensive income, in addition to
the loss for the year.
Net debt
As at 31 December 2025, net debt was $4,305 million (2024: $4,424 million).
This consisted of borrowings amounting to $5,366 million (2024: $5,513
million) less unamortised fees of $215 million (2024: $284 million) less cash
balances of $846 million (2024: $805 million). During the year, a new $900
million senior bond maturing in 2035 was placed, and partly used to pay the
existing $500 million senior bond. The €1,000 million bond due in 2025 was
also paid during the year. In addition, Harbour had surety bonds of $726
million (£538 million) at year end which provide cover for decommissioning
securities.
As at 31 December 2025, the Group has the ability to fund its near-term debt
maturities out to 2028 and, following the latest acquisitions, its investment
grade rating was reaffirmed by Moody's (Baa2) and unchanged by Fitch (BBB-).
Available liquidity, comprising the undrawn portion of the RCF facility of
$2.3 billion (the $3.0 billion facility had not been drawn down and $0.7
billion letters of credit for decommissioning had been drawn) plus cash
balances of $0.8 billion (2024: $0.8 billion), was $3.1 billion (2024: $2.7
billion) at the end of the year.
As at 31 December 2025, the leverage ratio(1) was 0.6x (2024: 1.1x) which has
decreased primarily as a result of the significant increase in EBITDAX due to
a full year of contribution from the acquisition in 2025 versus four months of
EBITDAX contribution in 2024. Net debt is marginally lower at $4.3 billion
(2024: $4.4 billion).
The balance sheet is in a strong position supported by the RCF facility and
investment grade credit ratings.
2025 2024
$ million $ million
Leverage ratio(1)
Net debt 4,305 4,424
EBITDAX 7,118 4,027
Leverage ratio(1) 0.6 x 1.1 x
1 Alternative performance measure - see Glossary for the definition.
Reconciliations between adjusted performance measures and reported measures
are provided within the Glossary.
Derivative financial instruments
We carry out hedging activity to manage commodity price risk. We have entered
into both a series of fixed-price sales agreements and a financial hedging
programme for both oil and gas, consisting of swap and option instruments.
Hedges realised to date are in respect of both crude oil and natural gas.
The hedging programme as at 31 December 2025 is shown below:
Hedge position 2026 2027 2028
Oil
Total oil volume hedged (thousand bbls) 16,258 7,574 -
- of which swaps 14,159 1,643 -
- of which collars 2,099 5,931 -
Weighted average fixed price ($/bbl) 72.57 68.08 -
Weighted average collar floor and cap ($/bbl) 60.00 - 75.24 60.00 - 76.99 -
Natural gas
Gas volume hedged (thousand boe) 26,483 12,602 1,804
- of which swaps/fixed price forward sales 19,830 5,506 510
- of which zero cost collars 6,653 7,096 1,294
Weighted average fixed price ($/mscf) 11.67 10.92 10.87
Weighted average collar floor and cap ($/mscf) 9.38 - 17.75 8.15 - 14.63 7.95 - 16.00
As at 31 December 2025, our financial hedging programme on commodity
derivative instruments showed a pre-tax positive mark-to-market fair value of
$493 million (2024: $475 million, negative). Most of the commodity derivatives
were designated as cash flow hedges, therefore, changes in fair value were
reported in other comprehensive income.
For foreign exchange derivative instruments, the pre-tax positive
mark-to-market fair value was $104 million (2024: $198 million, negative). Of
this value, $83 million (2024: $173 million) related to the cross-currency
interest rate swaps designated as cash flow hedges relating to the euro bonds
of €2.6 billion (2024: €2.4 billion) which were hedged at a forward rate
of between 1.1017 and 1.1680 (2024: 1.1015 and 1.1209).The remaining $21
million related to FX forward contracts designated as fair value through
income statement.
Statement of cash flows(1)
2025 2024
$ million $ million
Cash flow from operating activities before tax payments 6,862 3,114
Tax payments (3,476) (1,499)
Cash flow from operating activities after tax payments 3,386 1,615
Cash flow from investing activities - capital investment (1,912) (1,322)
Cash flow from investing activities - other(2) 132 89
Operating cash flow after investing activities 1,606 382
Cash flow from financing activities(3) (540) (500)
Free cash flow(4) 1,066 (118)
Cash and cash equivalents 846 805
(1) Table excludes financing activities related to debt and subordinated notes
principal movements.
(2) Excludes net expenditure on business combinations of $34 million (2024:
$1,044 million).
(3) Interest, lease interest and capital payments only, excludes shareholder
distributions.
(4) Alternative performance measure - see Glossary for the definition.
Reconciliations between adjusted performance measures and reported measures
are provided within the Glossary.
Net operating cash flow before tax was $6,862 million (2024: $3,114 million)
reflecting twelve months of the enlarged group. The timing and magnitude of
tax payments impacted net cash from operating activities after tax which
amounted to $3,386 million (2024: $1,615 million). Tax payments during the
year were $3,476 million compared to $1,499 million in 2024 due to the
enlarged portfolio.
Cash flow working capital movements were positive $60 million (2024: negative
$494 million) as a result of the collection of overdue receivables in Egypt
and Mexico acquired as part of the Wintershall Dea transaction.
Capital investment was $1,912 million (2024: $1,322 million) which included
property, plant and equipment additions of $1,435 million (2024: $884
million), exploration and evaluation additions of $363 million (2024: $359
million) and other intangible additions of $114 million (2024: $79 million).
Cash outflow from financing activities totalled $540 million (2024: $500
million) split between interest payments of $246 million (2024: $181 million)
and lease payments of $294 million (2024: $319 million).
Free cash flow was $1,066 million inflow (2024: $118 million outflow).
Shareholder distributions totalled $545 million (2024: $199 million) and
consist of dividends paid of $455 million (2024: $199 million) and the
repurchase of Harbour's own shares of $90 million (2024: $nil).
Cash and cash equivalent balances were $846 million (2024: $805 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.
2025 2024
$ million $ million
Additions to oil and gas assets (1,511) (1,037)
Additions to fixtures and fittings, office equipment and IT software (63) (73)
Additions to exploration and evaluation assets (327) (398)
Additions to other intangible assets (45) (36)
Total capital investment(1) (1,946) (1,544)
Movements in working capital (47) 140
Capitalised interest 36 18
Capitalised lease depreciation 45 64
Cash capital investment per the cash flow statement (1,912) (1,322)
(1) Alternative performance measure - see Glossary for the definition.
Reconciliations between adjusted performance measures and reported measures
are provided within the Glossary.
During the period, the Group incurred total capital expenditure of $2,370
million (2024: $1,828 million), split by capital investment $1,946 million
(2024: $1,544 million), decommissioning spend $374 million (2024: $284
million), and energy transition expenditure $50 million (2024: $nil)
respectively.
The majority of the capital investment was concentrated around our existing
production hubs, predominantly in Norway and the UK. Refer to the Operational
review for more detail.
Principal risks
The directors have identified a number of changes to the principle risks
facing the company following the completion of the Wintershall Dea
acquisition. This includes elevated risk levels in relation to the lower
commodity price environment, physical asset security, cyber security and a
somewhat lower risk in relation to the energy transition. Notably, the
principal risk recognised in the 2024 Annual Report as 'Integration of
acquired businesses' has been retired following the successful completion of
the acquisition.
Events after the reporting period
On 11 February 2026 Harbour announced it had completed the acquisition of LLOG
Exploration Company LLC for $3.2 billion, marking the Company's strategic
entry into the US Gulf of America. Harbour financed the Acquisition through
$2.7 billion of cash and the issuance of 174,855,744 new Harbour voting
ordinary shares (the Consideration Shares) to LLOG Holdings LLC (the Seller)
with an agreed value of $0.5 billion. The cash was funded by a $1.0 billion
bridge facility, a $1.0 billion 3-year term loan and $0.7 billion from
existing sources of liquidity.
At the time when the financial statements were authorised for issue, the group
had not yet completed the accounting for the acquisition of LLOG Exploration
Company LLC. The proximity of the completion of the acquisition to the
authorisation of the financial statements has meant the fair values of the
assets and liabilities have not been finalised. It is also not yet possible to
provide detailed information about each class acquired receivables and any
contingent liabilities of the acquired entities.
In 2024, the German non-governmental organisation Deutsche Umwelthilfe (NGO)
filed a lawsuit against the German mining authority (LBEG) challenging the
operating permit of Harbour Energy Germany GmbH (HEGG) for HEGG's Mittelplate
field. HEGG is a joined party in this lawsuit. On 26 February 2026, a court of
first instance (Schleswig-Holsteinisches Verwaltungsgericht) decided that the
operating permit is to be considered invalid during the duration of the main
court proceeding. HEGG filed an appeal on 27 February 2026 with the Appellate
Court (Schleswig-Holsteinisches Oberverwaltungsgericht). This Court confirmed
the receipt of the appeal and stated in writing that its Senate, which will
decide on the appeal, assumes that the operations of the drilling and
production island Mittelplate will continue until a decision has been
determined. Based on this first response by the Appellate Court, and in close
alignment with the mining authority, HEGG is focused on continuing safe
operations.
Going concern
The directors considered the going concern assessment period to be up to
31 December 2027. The Group monitors and manages its capital position and its
liquidity risk regularly to ensure that it has access to sufficient funds to
meet forecast cash requirements. Cash forecasts for management are regularly
produced and sensitivities considered based on, but not limited to, the
Group's latest life of field production and expenditure forecasts,
management's best estimate of future commodity prices based on recent forward
curves, adjusted for the Group's hedging programme, and the Group's borrowing
facilities.
The Group's ongoing capital requirements are financed by its $3.0 billion
revolving credit facility (RCF), bonds $5.3 billion (before unamortised fees),
senior term loan $1.0 billion, bridge loan $1.0 billion, subordinated notes of
$2.2 billion, and surety bonds of $726 million (£538 million) which provide
cover for decommissioning securities. The term and bridge loans were entered
into in February 2026 to finance the completion of the LLOG acquisition
announced in December 2025.
The RCF is subject to financial covenants that require the ratio of
consolidated total net debt, including letters of credit, to last twelve
months (LTM) EBITDAX to be less than 3.5x, and LTM EBITDA divided by interest
expense to exceed 3.5x. Under the Group's base case, the RCF is forecast to
have an undrawn balance of $3.0 billion through 2026 and 2027. When combined
with drawn letters of credit and unrestricted cash the headroom is forecasted
to be $2.7 billion 2027 which provides a robust liquidity position.
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 and the
ongoing capital requirements of the Group that will be financed by free cash
flow, the existing RCF and debt financing arrangements described above.
In addition, Harbour announced the Waldorf transaction in December 2025 which
is expected to complete in the second quarter of 2026 which is planned to be
financed from existing debt facilities. As part of the going concern
assessment, separate 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
throughout the entire assessment period in:
▪ Brent crude, UK natural gas and European TTF gas prices of 20 per
cent; and
▪ the Group's unhedged production of 10 per cent.
Management considers this represents a severe but plausible downside scenario
appropriate for assessing going concern and viability.
In this downside scenario when applied to the base case forecast, the Group is
forecast to have sufficient liquidity headroom throughout the going concern
assessment period and to remain in compliance with its financial covenants.
Reverse stress tests have been prepared reflecting reductions in each of
commodity price and production parameters, prior to any mitigation strategies,
to determine at what levels each would need to reach such that either the
lending covenants are breached or liquidity headroom runs out. The results of
these reverse stress tests demonstrated the likelihood that a sustained
significant fall in commodity prices or a significant fall in production over
the assessment period that would be required to cause a risk of funds
shortfall or a covenant breach is remote.
Taking the above analysis into account and considering the findings of the
work performed to support the statement on the long-term viability of the
company and the Group, the Board was satisfied that, for the going concern
assessment period, the Group is able to maintain adequate liquidity and comply
with its lending covenants up to 31 December 2027 and has therefore adopted
the going concern basis for preparing the financial statements.
By order of the Board,
Alexander Krane
Chief Financial Officer
4 March 2026
Financial statements
Consolidated income statement
For the year ended 31 December 2025
2025 2024
Note $ million $ million
Revenue 4 10,091 6,158
Other operating income 4 170 68
Revenue and operating other income 10,261 6,226
Cost of operations 5 (5,564) (3,613)
Impairment of property, plant and equipment 5,12 (365) (352)
Impairment of right-of-use assets 13 - (20)
Exploration and evaluation expenses and new ventures 5 (106) (68)
Exploration costs written-off 5 (200) (173)
General and administrative expenses 5 (536) (352)
Operating profit 3,490 1,648
Finance income 7 461 173
Finance expenses 7 (1,150) (602)
Profit before taxation 2,801 1,219
Income tax expense 8 (2,983) (1,312)
Loss for the year after taxation (182) (93)
Loss for the year attributable to:
Equity owners of the company (263) (108)
Subordinated notes investors 81 15
(182) (93)
Loss per share Note $ cents $ cents
Basic
Ordinary shares voting 9 (15) (10)
Ordinary shares non-voting 9 (17) (11)
Diluted
Ordinary shares voting 9 (16) (10)
Ordinary shares non-voting 9 (17) (11)
Consolidated statement of comprehensive income
For the year ended 31 December 2025
2025 2024
$ million $ million
Loss for the year (182) (93)
Other comprehensive income
Items that will not be subsequently reclassified to income statement:
Actuarial gains/(losses) 36 (6)
Tax (expense)/credit on actuarial gains/(losses) (11) 4
Net other comprehensive income/(loss) that will not be subsequently 25 (2)
reclassified to income statement
Items that may be subsequently reclassified to income statement:
Fair value gains/(losses) on cash flow hedges 1,181 (545)
Tax (charge)/credit on cash flow hedges (752) 379
Exchange differences on translation (182) 130
Net other comprehensive income/(loss) may be subsequently reclassified to 247 (36)
income statement
Other comprehensive income/(loss) for the year, net of tax 272 (38)
Total comprehensive income/(loss) for the year 90 (131)
Total comprehensive income/(loss) attributable to:
Equity owners of the company 9 (146)
Subordinated notes investors 81 15
90 (131)
Consolidated balance sheet
For the year ended 31 December 2025
2024
2025 As restated
Note $ million $ million
Assets
Non-current assets
Goodwill 10 5,062 5,062
Other intangible assets 11 5,749 5,714
Property, plant and equipment 12 13,210 14,578
Right-of-use assets 13 496 656
Equity accounted investments 7 -
Deferred tax assets 8 121 130
Other receivables 16 126 176
Other financial assets 23 209 44
Total non-current assets 24,980 26,360
Current assets
Inventories 15 398 368
Trade and other receivables 16 1,994 2,322
Other financial assets 23 485 145
Cash and cash equivalents 17 846 805
3,723 3,640
Assets held for sale 18 390 277
Total current assets 4,113 3,917
Total assets 29,093 30,277
Equity and liabilities
Equity
Share capital 26 171 171
Merger reserve 26 3,728 3,728
Other reserves 229 (18)
Retained earnings 53 807
Equity attributable to equity holders of the company 4,181 4,688
Equity attributable to subordinated notes investors 27 2,025 1,563
Total equity 6,206 6,251
Non-current liabilities
Borrowings 22 4,915 4,215
Provisions 21 6,967 7,024
Deferred tax 8 6,491 6,177
Trade and other payables 20 68 30
Lease liabilities 13 466 551
Other financial liabilities 23 19 415
Total non-current liabilities 18,926 18,412
Current liabilities
Trade and other payables 20 1,424 1,755
Borrowings 22 236 1,014
Lease liabilities 13 168 241
Provisions 21 446 497
Current tax liabilities 1,452 1,412
Other financial liabilities 23 21 462
3,747 5,381
Liabilities directly associated with the assets held for sale 18 214 233
Total current liabilities 3,961 5,614
Total liabilities 22,887 24,026
Total equity and liabilities 29,093 30,277
The following notes form part of these financial statements.
The financial statements were approved by the board of directors and
authorised for issue on 4 March 2026 and signed on its behalf by:
Alexander Krane
Chief Financial Officer
Consolidated statement of changes in equity
For the year ended 31 December 2025
Share capital Merger reserve(1) Other reserves (note 24) Retained earnings Equity attributable to owners of the company Equity attributable to subordinated notes investors Total equity
$ million $ million $ million $ million $ million $ million $ million
At 1 January 2024 171 271 18 1,093 1,553 - 1,553
Loss the year - - - (108) (108) 15 (93)
Other comprehensive income - - (36) (2) (38) - (38)
Total comprehensive income - - (36) (110) (146) 15 (131)
Issue of new shares - 3,457 - - 3,457 - 3,457
Share-based payments - - - 48 48 - 48
Purchase of ESOP trust shares - - - (25) (25) - (25)
Acquired through business combination - - - - - 1,548 1,548
Dividend paid - - - (199) (199) - (199)
At 31 December 2024 171 3,728 (18) 807 4,688 1,563 6,251
(Loss)/profit for the year - - - (263) (263) 81 (182)
Other comprehensive income - - 247 25 272 - 272
Total comprehensive income/(loss) - - 247 (238) 9 81 90
Share-based payments - - - 44 44 - 44
Purchase of ESOP trust shares - - - (15) (15) - (15)
Purchase and cancellation of own shares - - - (90) (90) - (90)
Dividends paid - - - (455) (455) - (455)
Distributions to subordinated notes investors - - - - - (58) (58)
Issuance of subordinated notes - - - - - 970 970
Repayment of subordinated notes - - - - - (558) (558)
Fair value adjustment to subordinated notes - - - - - 27 27
At 31 December 2025 171 3,728 229 53 4,181 2,025 6,206
(1) The increase in the merger reserve in 2024 represents the difference
between the fair value and nominal value of the shares issued as consideration
for the acquisition of the Wintershall Dea business.
( )
Consolidated statement of cash flows
For the year ended 31 December 2025
2025 2024
Note $ million $ million
Net cash inflow from operating activities 30 3,386 1,615
Investing activities
Expenditure on exploration and evaluation assets (363) (359)
Expenditure on property, plant and equipment 12 (1,435) (884)
Expenditure on non-oil and gas intangible assets (69) (42)
Expenditure on other intangible assets (45) (37)
Acquisition of subsidiaries, net of cash acquired 14 16 (1,044)
Acquisition deposit 16 (100) -
Disposal deposit 18 50 -
Finance income received 106 76
Other receipts 26 13
Net cash outflow from investing activities (1,814) (2,277)
Financing activities
Repurchase of shares (90) -
Proceeds from bond issuance net of transaction costs 30 894 1,720
Proceeds from new borrowings - revolving credit facility 30 440 2,225
Proceeds from subordinated notes net of transaction costs 27 970 -
Proceeds from new borrowings - reserves based lending facility 30 - 178
Proceeds from bridge facility 30 - 1,500
Payments of principal portion of lease liabilities (257) (265)
Interest paid on lease liabilities (37) (54)
Repayment of bonds 30 (1,391) -
Repayment of subordinated notes 27 (558) -
Repayment of revolving credit facility 30 (690) (1,975)
Repayment of reserves based lending facility 30 - (178)
Repayment of bridge facility 30 - (1,500)
Repayment of financing arrangement 30 - (17)
Purchase of ESOP trust shares (15) (25)
Interest paid and bank charges (246) (181)
Distributions paid to subordinated notes investors 30 (58) -
Dividends paid to shareholders 32 (455) (199)
Net cash (outflow)/inflow from financing activities (1,493) 1,229
Net increase in cash and cash equivalents 79 567
Net foreign exchange difference (11) (37)
Reclassification of cash as asset held for sale (27) (11)
Cash and cash equivalents at 1 January 805 286
Cash and cash equivalents at 31 December 846 805
Notes to the consolidated financial statements
1 Corporate information
Harbour Energy plc is a limited liability company incorporated in Scotland and
listed on the London Stock Exchange. The address of the registered office is
4(th) Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United
Kingdom.
The consolidated financial information for the year ended 31 December 2025
and 2024 contained in this document does not constitute statutory accounts
of Harbour Energy plc (Harbour or the company), as defined in section 435 of
the Companies Act 2006. The financial information for the years ended
31 December 2025 and 2024 have been extracted from the consolidated financial
statements of Harbour Energy plc and all its subsidiaries (the Group) which
were authorised for issue by the board of directors on 4 March 2026 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.
On 3 September 2024, the Group completed the acquisition of substantially all
of Wintershall Dea's upstream oil and gas assets, including those in Norway,
Germany, Denmark, Argentina, Mexico, Egypt, Libya and Algeria as well as
Wintershall Dea's CCS licences in Europe. Under IFRS 3 Business Combinations,
the Group is the legal and accounting acquirer as it obtained control over the
Wintershall Dea portfolio through the business combination: as it was the
entity that issued equity and paid cash to effect the business combination; at
completion the existing Harbour Energy plc shareholders held a majority of
voting ordinary shares; and from completion, day-to-day management of the
enlarged group has been led by existing Harbour Energy plc personnel, with no
change to the executive directorship.
The Group designated 1 September 2024 as the acquisition date (beginning of
month) rather than the actual acquisition date of 3 September 2024 (during
the month) as the events between the designated acquisition date and the
actual acquisition date do not result in material changes in the amounts
recognised.
The acquired Wintershall Dea portfolio results are fully consolidated in the
financial statements from 1 September 2024, and all results prior to this date
represent those of the legacy Harbour group only.
The Group's principal activities are the acquisition, exploration, development
and production of oil and gas reserves in Norway, the UK, Germany, Mexico,
Argentina, North Africa and Southeast Asia.
2 Material accounting policies
Basis of preparation
The consolidated financial statements have been prepared on a going concern
basis in accordance with UK-adopted International Accounting Standards (IAS)
in conformity with the requirements of the Companies Act 2006. The analysis
used by the directors in adopting the going concern basis considers the
various plans and commitments of the Group as well as various sensitivity and
reverse stress test analyses. The results from the severe but plausible
downside sensitivities and reverse stress tests with regard to production and
commodity price assumptions, which in management's view reflect two of the
principal risks, indicate that material changes within the going concern
period that would impact the going concern basis of preparation are remote.
In 2024, the Vietnam Business Unit was classified as an asset held for sale.
This sale was completed in July 2025. In 2025, the Indonesia disposal
transaction announced in December 2025 was classified as asset held for sale
(see note 18).
The presentation currency of the Group financial information is US dollars and
all values in the Group financial information are presented in millions ($
million) and all values are rounded to the nearest 1 million, except where
otherwise stated.
The financial statements have been prepared on the historical cost basis,
except for certain financial assets and liabilities, including derivative
financial instruments, which have been measured at fair value.
The accounting policies which follow set out those policies which apply in
preparing the financial statements for the year ended 31 December 2025. All
accounting policies are consistent with those adopted and disclosed in
Harbour's 2024 Annual Report & Accounts.
Basis of consolidation
The consolidated financial statements comprise the financial statements of the
company and its subsidiaries as at 31 December 2025. Subsidiaries are those
entities over which the Group has control. Control is achieved where the Group
has the power over the subsidiary, has rights, or is exposed to variable
returns from the subsidiary and has the ability to use its power to affect its
returns. All subsidiaries are 100 per cent owned by the Group, except for five
entities holding interests in operations in North Africa and CCS projects
which are accounted for as joint operations.
Profit or loss and each component of other comprehensive income (OCI) are
attributed to the equity holders of the company and to the subordinated notes
investors.
If the Group loses control over a subsidiary, it derecognises the related
assets (including goodwill), liabilities, non-controlling interest and other
components of equity, while any resultant gain or loss is recognised in profit
or loss. Any investment retained is recognised at fair value.
The results of subsidiaries acquired or disposed of during the year are
included in the income statement from the completion date of acquisition or up
to the completion date of disposal, as appropriate. Where necessary,
adjustments are made to the financial statements of subsidiaries acquired to
bring the accounting policies used into line with those used by other members
of the Group.
All intra-group transactions and balances have been eliminated on
consolidation.
Prior year adjustment arising from finalising acquisition fair values
On 3 September 2024, the Group closed the transaction to acquire substantially
all of Wintershall Dea's upstream assets from BASF and LetterOne, including
those in Norway, Germany, Denmark, Argentina, Mexico, Egypt, Libya and Algeria
as well as Wintershall Dea's carbon capture and storage (CCS) licences in
Europe. A purchase price allocation (PPA) had been performed and provisional
fair values of the identifiable assets and liabilities of Wintershall Dea, and
resulting goodwill, were disclosed in Harbour's 2024 Annual Report &
Accounts. These were finalised during 2025 and resulted in a change in the
fair values of the assets and liabilities and associated goodwill, the
reasoning for which is described in note 14. Each of the affected financial
statement line items have been restated and the impact is summarised in the
following table.
Balance sheet at 31 December 2024
As previously reported Adjustments As restated
$ million $ million $ million
Non-current assets
Goodwill 5,147 (85) 5,062
Property, plant and equipment 14,543 35 14,578
Current assets
Trade and other receivables 2,316 6 2,322
Non-current liabilities
Deferred tax 6,221 (44) 6,177
Significant accounting judgements and estimates
The preparation of the Group's financial statements in conformity with
UK-adopted IAS requires management to make judgements, estimates and
assumptions at the date of the financial statements. Estimates and assumptions
are continuously evaluated and are based on management experience and other
factors, including expectations of future events that are believed to be
reasonable under the circumstances. Uncertainty about these assumptions and
estimates could result in outcomes that require a material adjustment to the
carrying amount of the assets or liabilities affected in future periods.
In preparing these financial statements, management has made judgements and
estimates that affect the application of accounting policies and the reported
amounts of assets and liabilities, income and expenses including those that
have the potential to materially impact the balance sheet over the next 12
months. Actual results may differ from these estimates.
The significant judgements made by management in applying the Group's
accounting policies, and the key sources of estimation uncertainty, were the
same as those described in Harbour's 2024 Annual Report & Accounts, with
the removal of the defined benefit obligations on the basis of materiality.
Judgements
Significant accounting judgements considered by the Group are:
▪ The carrying value of intangible exploration and evaluation
assets, in relation to whether commercial determination of an exploration
prospect had been reached. The costs are subject to regular technical,
commercial and management review on at least an annual basis to confirm the
continued intent to develop, or otherwise extract value from, the discovery.
Where this is no longer the case, the costs are immediately expensed. For the
carrying value of intangible exploration and evaluation assets see note 11;
▪ The carrying value of property, plant and equipment regarding
assessing assets for indicators of impairment (see note 12);
▪ Decommissioning costs in relation to the timing of when
decommissioning would occur (see note 21); and
▪ Tax including assessment of risks around tax uncertainties and the
recognition of deferred tax assets (see note 8 below).
Key sources of estimation uncertainty
Details of the Group's critical accounting estimates are set out in these
financial statements and are:
▪ Purchase price allocation that involved a number of judgemental
estimates in determining the fair value of assets and liabilities acquired
from Wintershall Dea in September 2024. See note 14 for further information;
▪ The carrying value of property, plant and equipment and goodwill,
where the key assumptions relate to oil and gas prices expected to be realised
and the estimation of 2P reserves, 2C resources and production profiles. See
notes 10 and 12 for further information;
▪ Decommissioning costs where the key assumptions relate to the
discount and inflation rates applied, applicable rig rates and expected timing
of cessation of production (COP) on each field. See note 21 for further
information;
▪ The provision for, or disclosure of, areas of uncertainty for tax
purposes where the key assumptions are driven by technical analysis
corroborated by external advice; and
▪ Recognition of deferred tax assets and liabilities, where key
assumptions relate to oil and gas prices expected to be realised, and
production profiles. See note 8 for further information.
Disclosure regarding the judgements and estimates made in assessing the impact
of climate change and the energy transition are described below and references
to notes in the financial statements are provided.
The results from downside sensitivities prepared with regard to production and
commodity price assumptions, which in management's view reflect the principal
risks, indicate that material changes that would impact the carrying amounts
of assets and liabilities within the next financial year are unlikely.
Impact of climate change on the financial statements and related disclosures
Judgements and estimates made in assessing the impact of climate change and
the energy transition
Harbour monitors global climate change and energy transition developments and
plans. Management recognises there is a general high level of uncertainty
about the speed and scale of impacts which, together with limited historical
information, provides challenges in the preparation of forecasts and plans
with a range of possible future scenarios, which may have the potential to
materially impact the balance sheet.
The Group's strategic aspiration is to be net zero by 2050 with an interim
target of a 50 per cent reduction in gross operated Scope 1 and 2 emissions by
2030 against the 2018 baseline. This will be achieved through several
opportunities, including operational efficiency improvements, targeted
decarbonisation projects and the eventual cessation of production of mature
fields. In addition, the company is investing in the development of CCS
projects in the UK and Europe.
All new economic investment decisions include the cost of carbon, and
opportunities are assessed on their climate-impact potential and alignment
with Harbour Energy's net zero aspiration taking into consideration both GHG
volumes and intensity. The acquisition in 2024 has helped to advance our
energy transition objective by strategically shifting our portfolio towards
natural gas. Over time this move is expected to notably reduce our greenhouse
gas intensity on a net equity basis. The corporate modelling that supports the
preparation of the financial statements (such as asset and goodwill impairment
assessment, going concern and viability, deferred tax asset recoverability)
includes project costs related to CCS, certain decarbonisation projects once
sanctioned, other activities to reduce gross operated Scope 1 and 2 GHG
emissions, the UK and EU Emissions Trading Scheme costs and carbon offset
purchases. Emissions reduction incentives are part of staff remuneration
through the annual bonus programme.
Climate change and the energy transition have the potential to significantly
impact the accounting estimates adopted by management and therefore the
valuation of assets and liabilities reported on the balance sheet. On an
ongoing basis, management continues to assess the potential impacts on the
significant judgements and estimates used in the preparation of the financial
statements. Estimates adopted in the financial statements reflect management's
best estimate of future market conditions where, in particular, commodity
prices can be volatile. Commodity and carbon price curve assumptions are
described below noting that there is consideration given to other assumptions,
not exhaustively, such as foreign exchange and discount rates. Notwithstanding
the challenges around climate change and the energy transition, it is
management's view that the financial statements are consistent with the
disclosures in the Strategic report, Governance and Additional information
section of the Annual Report and Accounts.
This note provides insight into how Harbour has considered the impact on
valuations of key line items in the financial statements and how they could
change based on the climate change scenarios and sensitivities considered. The
scenarios presented show what the possible impact could be on the financial
statements considering both high and low commodity and carbon price outlooks
plus discount rates range. Importantly, these climate change scenarios do not
form the basis of the preparation of the financial statements but rather
indicate how the key assumptions that underpin the financial statements would
be impacted by the climate change scenarios. They are also designed to
challenge management's perspective on the future business environment. It is
recognised that the reality of the nature of progress of energy transition
will bring greater levels of disruption and volatility than these external
scenarios expect and do not represent management's current best estimate.
The financial statements have been prepared using management's current best
estimate for the foreseeable future, based on a range of economic forecasts
and represented by the Harbour scenario oil price curve. Management regularly
reviews these estimates and assumptions to ensure they align with the latest
economic conditions and market information.
Property, plant and equipment, and goodwill
Transitioning to lower carbon energy as the energy transition progresses has
the potential to significantly impact future commodity and carbon prices which
would, in turn, affect the future operating and capital costs, estimates of
cessation of production, useful lives, and consequently the recoverable amount
of property, plant and equipment and goodwill.
The non-current assets of the Group, particularly goodwill and oil and gas
assets within property, plant and equipment, are considered to be the most
sensitive to the energy transition.
Depreciation, estimated useful life and risk of stranded assets
The energy transition and the rate of its progression may impact the remaining
lifespan of assets. Typically, the Group's oil and gas assets are depreciated
using a unit of production method, which is based on the ratio of production
in the year to the commercial proven and probable reserves of the field,
considering future capital development expenditures.
As at 31 December 2025, the Group's production plans for existing assets
indicated that 44 per cent, 17 per cent and nil per cent of the commercial
proven and probable reserves would remain by 2030, 2035, and 2050,
respectively. Using the unit of production depreciation method, the carrying
amounts for the oil and gas assets are depreciated in line with the depletion
of reserves. An evaluation of the oil and gas assets as at 31 December 2025
indicated that the oil and gas assets would experience significant additional
depreciation by 2030 and complete depreciation by 2050, based on the planned
depletion of reserves.
This indicates that a substantial portion of proven and probable reserves are
anticipated to be produced by 2035, resulting in lower risk of stranded assets
being carried in the consolidated balance sheet. The Group's portfolio
management approach aims to mitigate the risk of stranded assets in the event
of a faster-than-expected structural decline in demand for oil and gas due to
tighter environmental regulations, changes in market demands and global energy
demand.
Impairment of property, plant and equipment, and goodwill
The important assumptions for impairment testing of goodwill and oil and gas
assets applied to the life of fields production and cost profiles include
commodity and carbon prices and discount rates. These key assumptions are
carefully assessed by management, both in isolation and in aggregate, to
ensure there is a fair and balanced view attained with minimal aggregate bias.
These assumptions are inherently uncertain and may ultimately diverge from the
actual amounts.
For the current year's impairment testing, the first three years reflect
benchmarked consensus and market forward price curves transitioning to a
long-term price from 2028. The Harbour scenario utilised real long-term
commodity price assumptions from 2028 for Brent crude at $74 per barrel (2024:
$78 per barrel), UK NBP gas at 89 pence per therm (2024: 80 pence per therm),
and a European gas price at $11.6 per mmbtu.
Carbon costs are expected to evolve over time and are subject to significant
uncertainty due to the rate of transition and the maturity of regulatory
frameworks. For the carbon price, Harbour management's real forward price
curve assumption in 2026 was $78 per tonne (2024: $72 per tonne), projected to
increase to $164 per tonne (2024: $182 per tonne) by 2030. Sensitivity
analysis was conducted using the IEA Net Zero carbon price curve, with a flat
assumed foreign exchange rate of pound sterling to US dollar rate of
£1:$1.30.
Sensitivity to changes in commodity price assumptions
Sensitivity analyses on the impairment of oil and gas assets and goodwill have
been conducted using different commodity price scenarios to demonstrate the
potential impact on their net book carrying values. It should be noted that
the financial statements are based on the Harbour scenario. Impairment
sensitivities have been developed using average -10 per cent deviation from
the Harbour scenario long-term crude and gas prices as well as selected
published climate change price curves.
The sensitivity scenarios described below incorporate changes to the commodity
price assumptions and assume that all other factors remain unchanged from the
Harbour scenario used for the basis of preparation of the financial
statements. Importantly, these sensitivities are stated before any management
mitigation actions to manage downside risks if the scenarios were to occur.
The Sustainability review within the Annual Report and Accounts discusses both
transition and physical risk climate change scenarios. This analysis covers
the transition risks and the graphs opposite show the crude oil, UK NBP gas
price curves and European TTF gas price for the period to 2050 for the
following IEA scenarios: Net Zero Emissions by 2050, Stated Policies and
Current Policies
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): pathway to limiting global
temperature rise to 1.5ºC
▪ IEA Stated Policies Scenario (STEPS): pathway based on existing
policy commitments and measures and those currently under development by
sector and country
▪ IEA Current Policies Scenario (CPS): pathway based exclusively on
existing, enacted energy and climate policies, assuming no new measures or
policy intentions are implemented
The crude price curves reflect the published IEA price curves for all periods.
For UK NBP there are no IEA published price curves therefore management has
derived the gas price curves by converting from the published IEA European gas
price curve. This was achieved by converting from USD per mmbtu to USD per
mscf and applying other known correlation coefficients between the European
and UK gas markets. In addition, for the period 2026-2028, the derived gas
price curve matches the Harbour scenario price curve to create a scenario that
was considered reasonably plausible.
Pre-development assets are recorded in other intangible assets ahead of
demonstration of commerciality and recognition of 2P reserves and hence are
not included below, however they are subject to the same management rigour
with the corporate models. The majority of such assets are in developing
countries with a growing future demand for energy which may reduce the climate
change impact from these pre-development assets.
The impact of the sensitivities on the carrying value of oil and gas assets
and goodwill in the consolidated balance sheet are shown in the table below:
31 December 2025
Pre-tax sensitivity (increase)/decrease in carrying value
$ million
Carrying value -10% price to Harbour scenario IEA Net Zero Emissions by 2050 (NZE) IEA Stated Policies (STEPS) IEA Current Policies
(CPS)
Commodity $ million
Goodwill (note 10) Crude oil 5,062 171 583 68 53
Gas 396 1,506 882 121
Oil and gas assets (note 12) Crude oil 13,114 362 1,028 - -
Gas 116 178 85 50
31 December 2024
Pre-tax sensitivity (increase)/decrease in carrying value
$ million
Carrying value -10% price to Harbour scenario IEA Net Zero Emissions by 2050 (NZE) IEA Stated Policies (STEPS) IEA Announced Pledges (APS)
Commodity $ million
Goodwill (note 10) Crude oil 5,062 45 928 - 38
Gas 37 1,431 997 1,114
Oil and gas assets (note 12) Crude oil 14,493 323 2,528 - 415
Gas 2 131 89 35
The -10 per cent price curves used in the Harbour scenarios adjust long-term
prices from 2026.
Under the -10 per cent price to Harbour scenario for crude, there is a pre-tax
impairment to oil and gas assets of $362 million and on goodwill an impairment
of $171 million. For gas, there is a pre-tax impairment of $116 million and on
goodwill an impairment of $396 million.
For crude, under the IEA NZE 2050 scenario, there is a pre-tax impairment to
oil and gas assets of $1,028 million and on goodwill an impairment of $583
million. For gas, there is a pre-tax impairment to oil and gas assets of $178
million and on goodwill an impairment of $1,506 million.
For crude, under the IEA STEPS, there is a pre-tax impairment to oil and gas
assets of $nil and on goodwill an impairment of $68 million. For gas, there is
a pre-tax impairment to oil and gas assets of $85 million and on goodwill an
impairment of $882 million.
For crude, under the IEA CPS, there is a pre-tax impairment to oil and gas
assets of $nil and on goodwill an impairment of $53 million. For gas there is
a pre-tax impairment to oil and gas assets of $50 million and on goodwill an
impairment of $121 million.
Sensitivity to changes in carbon price assumptions
The sensitivity scenarios described below incorporate changes to the carbon
price assumptions and assume that all other factors remain unchanged from the
Harbour scenario used for the basis of preparation of the financial
statements. This sensitivity is stated before any management mitigation
actions to manage downside risks if the scenarios were to occur.
The risk of stranded assets may increase in a higher carbon price scenario.
Sensitivity analyses of the carrying value of Harbour's oil and gas assets and
goodwill to carbon prices have been conducted based on the IEA NZE 2050
scenario. This aims to demonstrate the resilience of the assets' carrying
values to higher long-term carbon prices than those reflected in the
consolidated balance sheet.
This analysis covers the transition risks, and the graph below shows the
carbon price per tonne for the period to 2050 for the IEA NZE 2050 scenario.
The scenario price curves are dependent on factors covering supply, demand,
economic and geopolitical events and therefore are inherently uncertain and
subject to significant volatility. As a result, they are unlikely to
accurately predict future outcomes.
▪ Harbour scenario: base price curves used for impairment testing
▪ IEA Net Zero Emissions by 2050 (NZE): pathway to limiting global
temperature rise to 1.5°C
Applying the IEA NZE 2050 carbon price scenario for the entirety of the useful
economic life of the assets resulted in a pre-tax impairment of $52 million
(2024: $9 million) to oil and gas assets with no impairment to goodwill under
this scenario.
Sensitivity to changes in discount rate assumptions
The discount rate applied for impairment testing of the fair value less cost
of disposal is based on a nominal post-tax weighted average cost of capital
(WACC) after considering both cost of debt and equity. In 2025, the Group's
post-tax discount rate ranging from 9.0 per cent to 14.5 per cent (2024: 8.8
per cent to 14.5 per cent) is derived after considering relevant peer group's
post-tax WACC and incorporating segment-specific risk.
Considering the discount rates, the Group deems a 1 per cent rise in the
discount rate to be a reasonable potentiality for conducting sensitivity
analysis, assuming that all other factors utilised in calculating the
recoverable value for the carrying amount of goodwill and oil and gas assets
remain unaltered.
A 1 per cent increase in the discount rate would result in an additional
impairment of $77 million (2024: $113 million) to the oil and gas assets and
on goodwill $32 million (2024: $10 million).
Intangible assets - exploration and evaluation assets
The energy transition has the potential to affect the future development or
viability of exploration and evaluation prospects. A significant portion of
the Group's exploration and evaluation assets relate to prospects that could
either be tied back to existing infrastructure or are in developing countries
with a growing future demand for energy which may reduce the climate change
impact from these pre-development assets and hence require less capital
investment as these assets are less exposed to the impacts of the energy
transition compared to large frontier developments. At each balance sheet
date, all exploration and evaluation prospects are reviewed against the
Group's financial framework to ensure that the continuation of activities is
planned and expected. There are no significant judgements and/or critical
estimation uncertainty related to climate factors.
See Judgements: Exploration and evaluation expenditure for further
information.
Deferred tax assets
The potential impact of climate change and energy transition on balance sheet
items is uncertain and may lead to significant changes in the estimations of
parameters such as the useful life of assets and timing of cessation of
production together with their related deferred tax balances.
Deferred tax assets are recognised to the extent that their recovery is
considerable probable. In general, it is expected that sufficient forecasted
taxable profits will be available for the recovery of deferred tax assets
recognised at 31 December 2025 and expected to be recovered within the period
of production for each asset and after taking into account deferred tax
liabilities.
See note 8 Income tax for information on deferred tax balances.
Onerous contracts
Contracts may become onerous due to potential loss of revenue or heightened
costs stemming from changes in climate change and energy transition
regulations.
Management does not foresee any of its existing supply contracts becoming
onerous based on the current production level and estimated useful lives of
its assets.
Decommissioning cost and provisions
The energy transition may accelerate the decommissioning of assets which would
result in an increase in the carrying value of associated decommissioning
provisions. Whilst the Group currently expects to incur decommissioning costs
over the next 40 years, we anticipate the majority of costs will be incurred
between the next 10 to 20 years which will reduce the exposure to the impact
of the energy transition.
In the current year, the undiscounted provision for decommissioning and
restoration was $10.5 billion (2024: $10.5 billion), recognised on a
discounted basis in the consolidated balance sheet.
The discount and inflation rates applied have taken into consideration the
applicable rig rates and expected timing of cessation of production on each
field. Therefore, the timing of decommissioning expenditures has not been
materially brought forward and management do not consider that any reasonable
change in the timing of decommissioning expenditure will have a material
impact on the decommissioning provisions based on the production plans of
existing assets.
Decommissioning cost estimates are based on the current regulatory and
external environment. These cost estimates and recoverability of associated
deferred tax may change in the future, including as a result of the energy
transition. On the basis that all other assumptions in the calculation remain
the same, a 10 per cent increase in the cost estimates, and a 1 per cent
absolute reduction in the applied discount rates used to assess the final
decommissioning obligation, would result in increases to the decommissioning
provision of approximately $740 million (2024: $852 million) and $312 million
(2024: $286 million), respectively. This change would be principally offset by
a change to the value of the associated asset unless the asset is fully
depreciated, in which case the change in estimate is recognised directly
within the income statement.
See Key sources of estimation uncertainty: Decommissioning costs for further
information.
Portfolio changes
Harbour expensed $142 million of costs in relation to CO2 emissions during
2025 (2024: $75 million) with the majority in relation to the UK Emissions
Trading Scheme quotas net of allocated free quotas. Quotas in relation to
future periods are recognised in intangible assets.
Harbour has investments in a number of CCS projects which are regarded as key
to assisting in the energy transition. Projects are recognised in intangible
assets once the projects are regarded as technically feasible and commercially
viable; prior to this, costs are expensed to the income statement. In 2025
Harbour spent $116 million on CCS activities, capitalising $32 million and
expensing $84 million.
Global oil and gas demand considerations
The transition to sustainable energy to mitigate climate change carries the
potential to adversely impact commodity prices due to a global decrease in the
demand for oil and gas, potentially leading to reduced revenue. Furthermore,
investment in clean energy via the adoption of clean energy technologies could
elevate production costs, thereby diminishing future profit margins.
Based on prevailing policies and regulatory frameworks, it is anticipated that
the growth in global oil demand will decrease, but the demand for oil and gas
is projected to continue as a crucial component of the energy mix for the
foreseeable future. Natural gas is widely known as a key transition fuel. In
the 2025 IEA World Energy Outlook report the demand for natural gas has been
revised upwards in all scenarios compared to the previous year, reflecting
stronger anticipated demand for gas to meet growth in electricity demand.
During the year, the Group produced 474 kboepd (2024: 258 kboepd), accounting
for less than 0.4 per cent of global production. Consequently, the Group does
not expect the ability to sell the volume of oil equivalent produced to be
directly impacted by shifts in global oil and gas demand. Management remains
committed to investing in a diversified oil and gas company.
Cost of carbon allowances
Harbour is part of the European and UK Emissions Trading Schemes (EU and UK
ETS) and purchases carbon allowances to meet its regulatory obligations under
the schemes. Harbour is entitled to receive a share of free allowances
according to UK and EU ETS regulations. Allowances owned in excess of
liabilities to date that are available to be used in future periods are
recorded in other intangible assets and measured at cost. The costs for
purchasing allowances are recorded in costs of operations matching emissions
for the period. Accruals that are required for allowances to be purchased are
measured at market price.
Joint arrangements
A joint arrangement is one in which two or more parties have joint control.
Joint control is the contractually agreed sharing of control of an
arrangement, which exists only when decisions about the relevant activities
require the unanimous consent of the parties sharing control.
Exploration and production operations are usually conducted through joint
arrangements with other parties. The Group reviews all joint arrangements and
classifies them as either joint operations or joint ventures depending on the
rights and obligations of each party to the arrangement and whether the
arrangement is structured through a separate vehicle. The Group's interest in
joint operations, such as exploration and production arrangements, are
accounted for by recognising its:
▪ Assets, including its share of any assets held jointly
▪ Liabilities, including its share of any liabilities incurred
jointly
▪ Revenue from the sale of its share of the output arising from the
joint operation
▪ Share of the revenue from the sale of the output by the joint
operation
▪ Expenses, including its share of any expenses incurred jointly
A joint venture, which normally involves the establishment of a separate legal
entity, is a contractual arrangement whereby the parties that have joint
control of the arrangement have the rights to the arrangement's net assets.
The results, assets and liabilities of a joint venture are incorporated in the
consolidated financial statements using the equity method of accounting. Note
34 describes the Group's interests in joint arrangements as at 31 December
2025.
Where the Group transacts with its joint operations, unrealised profits and
losses are eliminated to the extent of the Group's interest in the joint
operation.
Foreign currency translation
Each entity in the Group determines its own functional currency, being the
currency of the primary economic environment in which the entity operates, and
items included in the financial statements of each entity are measured using
that functional currency.
The consolidated financial statements are presented in US dollars, which is
also the parent company's functional currency.
Transactions recorded in foreign currencies are initially recorded in the
entity's functional currency by applying an average rate of exchange. Monetary
assets and liabilities denominated in foreign currencies are retranslated at
the functional currency rate of exchange ruling at the reporting date. All
differences are taken to the income statement.
Non-monetary assets and liabilities denominated in foreign currencies are
measured at historic cost based on exchange rates at the date of the initial
transaction and subsequently not retranslated.
On consolidation, the assets and liabilities of the Group's operations are
translated at exchange rates prevailing on the balance sheet date. Income and
expense items are translated at the average monthly exchange rates for the
year. Equity is held at historic cost and is not retranslated. The resulting
exchange differences are recognised as other comprehensive income and are
transferred to the Group's currency translation reserve.
When an overseas operation is disposed of, such translation differences
relating to it are recognised as income or expense.
Goodwill arising on the acquisition of a foreign operation and any fair value
adjustments to the carrying amounts of assets and liabilities arising on the
acquisition are treated as assets and liabilities of the foreign operation and
translated at the closing rate.
Goodwill
In the event of a business combination or acquisition of an interest in a
joint operation in which the activity constitutes a business, as defined in
IFRS 3 Business Combinations, the acquisition method of accounting is applied.
Goodwill represents the difference between the aggregate of the fair value of
purchase consideration transferred at the acquisition date and the fair value
of the identifiable assets, liabilities and contingent liabilities acquired,
less any non-controlling interest. If however, the fair value of the purchase
consideration transferred is lower than the fair value of the identifiable
assets and liabilities acquired, less non-controlling interest, the difference
is recognised in the income statement as negative goodwill. The Group's
goodwill is related to the requirement to recognise deferred tax for the
difference between the assigned fair values and the related tax base
(technical goodwill). The fair value of the Group's licences are based on
post-tax cash flows or benchmarked multiples. In accordance with IAS 12
paragraphs 15 and 24, a provision is made for deferred tax corresponding to
the difference between the acquisition cost and the transferred tax
depreciation basis. The offsetting entry to this deferred tax is goodwill.
Hence, goodwill arises as a technical effect of deferred tax. Goodwill is
initially measured at cost. Following initial recognition, goodwill is
measured at cost less any accumulated impairment. Goodwill acquired in a
business combination is, from the acquisition date, allocated to each of the
Group's operating segments. This is subsequently tested for impairment at the
Group's operating segment level based on the aggregation of any headroom
arising from asset impairment tests. Goodwill is treated as an asset of the
relevant entity to which it relates, and accordingly non-US dollar goodwill is
translated into US dollars at the closing rate of exchange at each reporting
date.
Goodwill, as disclosed in note 10, is not amortised but is reviewed for
impairment at least annually by assessing the recoverable amount of the
operating segments to which the goodwill relates. Where the carrying amount of
the operating segment and related goodwill is higher than the recoverable
amount of the operating segment, an impairment loss is recognised in the
income statement. The recoverable amounts of the operating segments have been
determined on a fair value less costs to sell basis. Impairments are expected
to arise as the deferred tax that gave rise to the goodwill initially
naturally unwinds in the normal course of business. Impairment losses relating
to goodwill cannot be reversed in future periods.
Pre-licence costs
Pre-licence costs are expensed in the period in which they are incurred.
Licence and property acquisition costs
Licence and property acquisition costs paid in connection with a right to
explore in an existing exploration area are capitalised as exploration and
evaluation costs within intangible assets.
Licence and property acquisition costs are reviewed at each reporting date to
confirm that there is no indication that the carrying amount exceeds the
recoverable amount. If no future activity is planned or the related licence
has been relinquished or has expired, the carrying value of the property
acquisition costs is written off through the income statement. Upon
recognition of proved reserves and internal approval for development, the
relevant expenditure is transferred to oil and gas properties within
development and production assets.
Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated
with the exploration are capitalised as exploration and evaluation (E&E)
intangible non-current assets until the exploration is complete and the
results have been evaluated. If no potential commercial resources are
discovered, the exploration asset is written off.
All such capitalised costs are subject to technical, commercial and management
review, as well as review for indicators of impairment at least annually. This
is to confirm the continued intent to develop or otherwise extract value from
the discovery. When this is no longer the case, the costs are written off
through the income statement.
When proved reserves of oil or natural gas are identified and development is
sanctioned by management, the relevant capitalised expenditure is first
assessed for impairment and, if required, any impairment loss is recognised,
then the remaining balance is transferred to oil and gas properties within
development and production assets. No amortisation is charged during the
exploration and evaluation phase.
Farm-outs - in the exploration and evaluation phase
The Group does not record any expenditure made by the farmee on its account.
It also does not recognise any gain or loss on its exploration and evaluation
farm-out arrangements but re-designates any costs previously capitalised in
relation to the whole interest as relating to the partial interest retained.
Any cash consideration received directly from the farmee is credited against
costs previously capitalised in relation to the whole interest with any excess
accounted for by the farmor as a gain on disposal.
Property, plant and equipment - oil and gas assets
Oil and gas development and production assets are accumulated generally on a
field-by-field or cash-generating unit basis where infrastructure is shared.
This represents expenditure on the construction, installation or completion of
infrastructure facilities such as platforms, pipelines and the drilling of
development wells, including E&E expenditures incurred in finding
commercial reserves transferred from intangible E&E assets, as outlined in
the intangible asset policy above, which is capitalised as oil and gas
properties within development and production assets.
The initial cost of an asset comprises its purchase price or construction
cost, any costs directly attributable to bringing the asset into operation,
the initial estimate of the decommissioning obligation and, for qualifying
assets, where relevant, borrowing costs. The purchase price or construction
cost is the aggregate amount paid and the fair value of any other
consideration given to acquire the asset.
An item of development and production expenditure and any significant part
initially recognised is derecognised upon disposal or when no future economic
benefits are expected. Any gain or loss arising on derecognition of the asset
(calculated as the difference between the net disposal proceeds and the
carrying amount of the asset) is included in the income statement.
Expenditure on major maintenance includes refits, inspections or repairs
comprising the cost of replacement assets or parts of assets, inspection costs
and overhaul costs. Where an asset, or part of an asset, that was separately
depreciated and is now written off is replaced and it is probable that future
economic benefits associated with the item will flow to the Group, the
expenditure is capitalised. All other day-to-day repairs and maintenance costs
are expensed as incurred.
Depreciation, depletion and amortisation (DD&A) of oil and gas assets
All costs relating to a development are accumulated and not depreciated until
the commencement of production. Depreciation is provided generally on a
field-by-field or cash-generating unit basis where infrastructure is shared,
using the unit of production method by reference to the ratio of production in
the year and the related commercial proven and probable reserves of the field,
considering future development expenditures necessary to bring those reserves
into production.
When there is a change in the estimated total recoverable proven and probable
reserves of a field, that change is accounted for in the depreciation charge
over the revised remaining proven and probable reserves.
Acquisitions, asset purchases and disposals
Acquisitions of oil and gas properties are accounted for using the acquisition
method when the assets acquired and liabilities assumed constitute a business.
Transactions involving the purchase of an individual field interest, or a
group of field interests, which do not constitute a business, are treated as
asset purchases irrespective of whether the specific transactions involve the
transfer of the field interests directly or the transfer of an incorporated
entity. Accordingly, no goodwill and no deferred tax gross up arises, and the
consideration is allocated to the assets and liabilities purchased on an
appropriate basis.
Proceeds on disposal are applied to the carrying amount of the specific
intangible asset or oil and gas property disposed of and any surplus is
recorded as a gain on disposal in the income statement.
Decommissioning
A provision for decommissioning is recognised in full when the related
facilities are installed. The amount recognised is the present value of the
estimated future expenditure. A corresponding amount equivalent to the
provision is also recognised as part of the cost of the related oil and gas
property. This is subsequently depreciated as part of the capital costs of the
production facilities. Any change in the present value of the estimated
expenditure is dealt with from the start of the financial year as an
adjustment to the opening provision and the oil and gas property. The
unwinding of the discount is included as a finance cost.
Non-oil and gas assets
Property, plant and equipment - fixtures and fittings and office equipment
Fixtures and fittings and office equipment are stated at cost less accumulated
depreciation and impairment. Depreciation is provided for on a straight-line
basis at rates sufficient to write off the cost of the assets less any
residual value over their estimated useful economic lives. The depreciation
periods for the principal categories of assets are as follows:
▪
Buildings
6 to 50 years
▪ Fixtures and
fittings
10 to 23 years
▪ Office furniture and
equipment 1 to 13
years
Intangible assets
Intangible assets principally comprise IT software/licences and carbon
allowances. IT software/licences are carried at cost less any accumulated
amortisation. These assets are amortised on a straight-line basis over their
useful economic lives of between three and ten years. Carbon allowances are
carried at cost and subject to impairment testing.
Impairment of non-current assets (excluding goodwill)
In accordance with IAS 36 Impairment of Assets, impairment tests are carried
out on items of property, plant and equipment and intangible assets where
there is an indicator of impairment, or an indicator identified that a prior
year impairment may have reversed or decreased. Such indications may be based
on events or changes in the market environment, or on internal sources of
information.
Impairment and reversal indicators
Property, plant and equipment and intangible assets with finite useful lives
are only tested for impairment when there is an indication that they may be
impaired. This is generally the result of significant changes to the
environment in which the assets are operated or when asset performance is
significantly lower than expected.
The main impairment indicators used by the Group are described below:
▪ External sources of information:
− Significant changes in the economic, technological, political or
market environment in which the entity operates or to which an asset is
dedicated
− Fall in demand
− Changes in commodity prices and exchange rates
▪ Internal sources of information:
− Evidence of obsolescence or physical damage
− Significantly lower than expected production or cost performance
− Reduction in reserves and resources, including as a result of
unsuccessful results of drilling operations
− Pending expiry of licence or other rights
− In respect of capitalised exploration and evaluation costs, lack
of planned future activity on the prospect or licence
− For reversals, plausible downside sensitivity scenarios are run to
test the robustness of the asset carrying values typically against changes in
production and commodity prices
Measurement of recoverable amount
The cash-generating unit (CGU) applied for impairment test purposes is
generally the field, except that a number of field interests may be grouped as
a single CGU where the cash inflows of each field are interdependent. The
carrying value of each CGU is compared against the expected recoverable amount
of the asset, which is primarily determined based on the fair value less cost
of disposal (FVLCD) method, where the fair value is determined from the
estimated present value of the future net cash flows expected to be derived
from production of commercial reserves. Standard valuation techniques are used
based on the discount rates that reflect the specific characteristics of the
operating entities concerned; discount rates are determined on a post-tax
basis and applied to post-tax cash flows.
Any impairment loss is recorded in the income statement under 'Impairment of
property, plant and equipment'. Impairment losses recorded in relation to
property, plant and equipment may be subsequently reversed if the recoverable
amount of the assets subsequently increases above carrying value. The
increased carrying amount of an item of property, plant or equipment
attributable to a reversal of an impairment loss may not exceed the carrying
amount that would have been determined (net of depreciation/amortisation) had
no impairment loss been recognised in prior periods.
Non-current assets held for sale
The Group classifies non-current assets and disposal groups as assets held for
sale if their carrying amounts will be recovered principally through a sale
transaction rather than through continuing use. Non-current assets and
disposal groups classified as held for sale are measured at the lower of their
carrying amount and fair value less costs to sell. Costs to sell are the
incremental costs directly attributable to the disposal group, excluding
finance costs and income tax expense. The criteria for held for sale
classification is regarded as met only when the sale is highly probable, and
the asset or disposal group is available for immediate sale in its present
condition. Management must be committed to the plan to sell the asset and the
sale expected to be completed within one year from the date of the
classification. Actions required to complete the sale should indicate that it
is unlikely that significant changes to the sale will be made or that the
decision to sell will be withdrawn. Property, plant and equipment and
intangible assets are not depreciated or amortised once classified as assets
held for sale. Assets and liabilities classified as held for sale are
presented separately as current line items in the balance sheet.
Financial assets
The Group uses two criteria to determine the classification of financial
assets: the Group's business model and contractual cash flow characteristics
of the financial assets. Where appropriate the Group identifies three
categories of financial assets: amortised cost, fair value through profit or
loss (FVTPL), and fair value through other comprehensive income (FVOCI).
Financial assets held at amortised cost
Financial assets held at amortised cost are initially measured at fair value
plus transaction costs and subsequently measured using the effective interest
rate (EIR) method and are subject to impairment. The EIR amortisation is
presented within finance income in the income statement.
Cash and cash equivalents
Cash and cash equivalents comprise cash at bank and other short-term highly
liquid investments that are held for the purpose of meeting short-term cash
commitments, readily convertible to a known amount of cash and are subject to
an insignificant risk of changes in value.
Impairment of financial assets
The Group recognises an allowance for expected credit losses (ECLs) for all
debt instruments not held at FVTPL. ECLs are based on the difference between
the contractual cash flows due in accordance with the contract and all the
cash flows that the Group expects to receive, discounted at an approximation
of the original effective interest rate.
ECLs are recognised in two stages:
▪ 12-month ECL: for credit exposures for which there has not been a
significant increase in credit risk since initial recognition, ECLs are
provided for credit losses that result from default events (payment,
prospective or covenant) that are possible within the next 12 months
▪ Lifetime ECL: for those credit exposures for which there has been
a significant increase in credit risk since initial recognition, a loss
allowance is required for credit losses expected over the remaining life of
the exposure, irrespective of the timing of the default
For trade receivables and contract assets, the Group applies a simplified
approach in calculating ECLs as allowed under IFRS 9 Financial Instruments.
Therefore, the Group does not track changes in credit risk, but instead
recognises a loss allowance based on lifetime ECLs at each reporting date. The
Group has established a provision matrix that is based on its historical
credit loss experience, adjusted for forward-looking factors specific to the
debtors and the economic environment.
Credit impaired financial assets
At each reporting date, the Group assesses whether financial assets carried at
amortised cost and debt financial assets carried at FVOCI are credit impaired.
A financial asset is 'credit impaired' when one or more events that have a
detrimental impact on the estimated future cash flows of the financial asset
have occurred.
Evidence that a financial asset is credit impaired includes the following
observable data:
▪ Significant financial difficulty of the borrower or issuer
▪ A breach of contract such as default or past due event
▪ The restructuring of a loan or advance by the Group on terms that
the Group would otherwise not consider
▪ Becoming probable that the borrower will enter bankruptcy or other
financial reorganisation
▪ The disappearance of an active market for a security because of
financial difficulties
Financial liabilities
Financial liabilities are classified, at initial recognition, as financial
liabilities at fair value through profit or loss, loans and borrowings,
payables, or as derivatives designated as hedging instruments in an effective
hedge, as appropriate. All financial liabilities are recognised initially at
fair value and, in the case of loans, borrowings and payables, net of directly
attributable transaction costs which are capitalised and amortised over the
term of the borrowings. Where borrowings have been fully repaid but the
borrowing facility remains, directly attributable transaction costs that
remain unamortised are presented within current and/or non-current assets.
Borrowings and loans
Interest-bearing bank loans and overdrafts are recorded at the proceeds
received, net of direct issue costs. Finance charges, including premiums
payable on settlement or redemption and direct issue costs, are accounted for
on an accruals basis in the income statement using the effective interest
method and are added to the carrying amount of the instrument to the extent
that they are not settled in the year in which they arise.
Subordinated notes
The Group holds subordinated resettable fixed rate notes (subordinated notes).
Based on their characteristics (mainly no mandatory repayment and no
obligation to pay a coupon except under certain circumstances specified in the
documentation of the subordinated notes) and in compliance with IAS 32
Financial Instruments: Presentation, the subordinated notes are wholly
classified as equity. On completing the Wintershall Dea acquisition in 2024,
the issued subordinated notes were recognised at fair value, based on market
rates as of the acquisition date. Accrued interest payable to the subordinated
notes investors increases equity, whereas the distribution of interest
payments reduces equity.
Derecognition
A financial liability is derecognised when the obligation under the liability
is discharged, cancelled or expires. When an existing financial liability is
replaced by another from the same lender on substantially different terms, or
the terms of an existing liability are substantially modified, such an
exchange or modification is treated as the derecognition of the original
liability and the recognition of a new liability. The difference in the
respective carrying amounts is recognised in the income statement.
Derivative financial instruments and hedge accounting
The Group uses derivative financial instruments such as forward currency
contracts, interest rate swaps, commodity option contracts and commodity swap
arrangements, to hedge its foreign currency risks, interest rate risks and
commodity price risks, respectively. Derivative financial instruments are
initially recognised and subsequently remeasured at fair value.
A derivative with a positive fair value is recognised as a financial asset
whereas a derivative with a negative fair value is recognised as a financial
liability. Derivatives are not offset in the financial statements unless the
Group has both a legally enforceable right and intention to offset. A
derivative is presented as a non-current asset or a non-current liability if
the remaining maturity of the instrument is more than 12 months and it is not
due to be realised or settled within 12 months. Other derivatives maturing in
less than 12 months and expected to be realised or settled in less than 12
months are presented as current assets or current liabilities.
For the purpose of hedge accounting, hedges are classified as:
▪ Fair value hedges when hedging exposure to changes in the fair
value of a recognised asset or liability
▪ Cash flow hedges when hedging exposure to variability in cash
flows that is attributable to either a particular risk associated with a
recognised asset or liability or a highly probable forecast transaction.
Hedge relationships are formally designated and documented at inception,
together with the risk management objective and strategy for undertaking the
hedge. The documentation includes identification of the hedging instrument,
the hedged item or transaction, the nature of the risk being hedged, the
existence at inception of an economic relationship and subsequent measurement
of the hedging instrument's effectiveness in offsetting the exposure to
changes in the hedged item's fair value or cash flows attributable to the
hedged risk, the hedge ratio and sources of hedge ineffectiveness. Hedges
meeting the criteria for hedge accounting are accounted for as follows:
Fair value hedges
The change in fair value of a hedging derivative is recognised in the income
statement. The change in the fair value of the hedged item attributable to the
risk being hedged is recorded as part of the carrying value of the hedged item
and is also recognised in the income statement, where it offsets. The Group
applies fair value hedge accounting when hedging interest rate risk on fixed
rate finance debt.
Fair value hedge accounting is discontinued only when the hedging relationship
or a part thereof ceases to meet the qualifying criteria. This includes when
the risk management objective changes or when the hedging instrument is
terminated or exercised. The accumulated adjustment to the carrying amount of
a hedged item at such time is then amortised prospectively to the income
statement as finance interest expense over the hedged item's remaining period
to maturity.
Cash flow hedges
The effective portion of the gains and losses arising from the remeasurement
of derivative financial instruments designated as cash flow hedges are
deferred within other comprehensive income and subsequently transferred to the
income statement in the period the hedged transaction is recognised in the
income statement. When a hedging instrument is sold or expires, any cumulative
gain or loss previously recognised in other comprehensive income remains
deferred until the hedged item affects profit or loss or is no longer expected
to occur. Any gain or loss relating to the ineffective portion of a cash flow
hedge is immediately recognised in the income statement. Hedge ineffectiveness
could arise if volumes of the hedging instruments are greater than the hedged
item of production, or where the creditworthiness of the counterparty is
significant and may dominate the transaction and lead to losses.
Cash flow hedge accounting is discontinued only when the hedging relationship
or a part thereof ceases to meet the qualifying criteria. This includes when
the designated hedged forecast transaction or part thereof is no longer
considered to be highly probable to occur, or when the hedging instrument is
sold, terminated or exercised without replacement or rollover. When cash flow
hedge accounting is discontinued amounts previously recognised within other
comprehensive income remain in equity until the forecast transaction occurs
and are reclassified to profit or loss. If the forecast transaction is no
longer expected to occur, amounts previously recognised within other
comprehensive income will be immediately reclassified to profit or loss.
Fair values
Fair value is defined as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market
participants at the measurement date. It is determined by reference to quoted
market prices adjusted for estimated transaction costs that would be incurred
in an actual transaction, or by the use of established estimation techniques
such as option pricing models and estimated discounted values of cash flows.
For financial instruments not traded in an active market, the fair value is
determined using appropriate valuation techniques.
Under IFRS 9 Financial Instruments, embedded derivatives are not separated
from a host financial asset, and are classified based on their contractual
terms and the Group's business model.
Equity
Share capital
Share capital includes the total net proceeds, both nominal and share premium,
on the issue of ordinary (voting and non-voting) and preference shares of the
company.
Merger reserve
On 31 March 2021, Harbour Energy plc (formerly Premier Oil plc) acquired
Chrysaor Holdings Limited as part of a reverse acquisition. Under the terms of
the merger, Premier legally acquired Chrysaor through the issuance of
consideration shares whilst Chrysaor was the acquirer for accounting purposes,
primarily as a result of its ability to appoint the Board of the enlarged
group. The merger reserve primarily represented Premier's opening balance on
the legal reserve plus the fair value of the assets and liabilities acquired
by Chrysaor. This was subsequently reduced following a capital restructuring
in 2022.
On 3 September 2024, the company's acquisition of the Wintershall Dea assets
met the conditions to recognise the difference between the fair value and
nominal value of the shares issued as consideration as merger reserve.
Capital redemption reserve
The capital redemption reserve represents the nominal value of shares
transferred following the company's purchase of them.
Cash flow hedge reserve
The cash flow hedge and cost of hedging reserves represent gains and losses on
derivatives classified as effective cash flow hedges. Upon the designation of
option instruments as hedging instruments, the intrinsic and time value
components are separated, with only the intrinsic component being designated
as the hedging instrument and the time value component is deferred in other
comprehensive income as a 'cost of hedging'.
Currency translation reserve
This reserve comprises exchange differences arising on consolidation of the
Group's operations with a functional currency other than the US dollar.
Share-based payments
The Group's main share incentive plans allow employees to acquire shares in
the parent company, subject to certain criteria, and are classified as
equity-settled in accordance with IFRS 2 Share-Based Payments.. The fair value
of the equity-settled awards has been determined at the date of grant of the
award allowing for the effect of any market-based conditions. The fair value
determined at the grant date of the equity-settled share-based payments is
expensed on a straight-line basis over the vesting period with a corresponding
increase directly in equity, based on the Group's estimate of shares that will
eventually vest and adjusted for the effect of non-market-based vesting
conditions.
Employee benefit trust
Shares held in the Employee Share Ownership Plan (ESOP) to meet the future
requirements of the employee share-based payment plans are not included in
assets but are reflected at cost as a deduction from retained earnings. No
gain or loss is recognised in the income statement on the purchase, issue or
cancellation of equity shares.
Recharge arrangements
The Group operates an intercompany recharge mechanism whereby subsidiaries
reimburse the parent company for share-based payments granted under IFRS 2.
These recharges are directly linked to the share-based payment transactions.
Subsidiaries adjust the initial capital contribution when reimbursing the
parent company, while the parent company adjusts its investment in the
subsidiaries, resulting in nil net impact on the parent company's carrying
value of investments. All reciprocal entries are eliminated on consolidation.
Inventories
Consumables and subsea supplies are stated at the lower of cost and net
realisable value. The cost of materials is the purchase cost, determined on
weighted average cost basis. Hydrocarbons, including underlift and overlift
positions, are measured at net realisable value using an observable year-end
oil or gas market price, and are included in other debtors or creditors,
respectively.
Leases
Leases are recognised as a right-of-use asset and a corresponding liability at
the date at which the leased asset is available for use by the Group.
Right-of-use assets are measured at cost, less any accumulated depreciation
and impairment losses, and adjusted for any remeasurement of lease
liabilities. The cost of right-of-use assets includes the amount of lease
liabilities recognised, initial direct costs incurred, and lease payments made
at or before the commencement date less any lease incentives received.
Right-of-use assets are depreciated on a straight-line basis over the shorter
of the lease term and the estimated useful lives of the assets which are no
more than ten years.
The Group recognises right-of-use assets and lease liabilities on a gross
basis and the recovery of lease costs from joint operations' partners is
recorded as other income.
Liabilities arising from a lease are initially measured on a present value
basis reflecting the net present value of the fixed lease payments and amounts
expected to be payable by the Group assuming leases run to full term. The
Group has applied judgement to determine the lease term for some lease
contracts in which it is a lessee that include renewal options. The assessment
of whether the Group is reasonably certain to exercise such options impacts
the lease term, which significantly impacts the amount of lease liabilities
and right-of-use assets recognised.
The lease payments are discounted at the lease commencement date using the
Group's incremental borrowing rates of between 0.9 per cent and 28.5 per cent,
being the rate that the Group would have to pay to borrow the funds necessary
to obtain an asset of similar value in a similar economic environment with
similar terms and conditions.
To determine the incremental borrowing rate, the Group where possible:
▪ Uses recent third-party financing received by the individual
lessee as a starting point, adjusted to reflect changes in financing
conditions since third-party financing was received
▪ Makes adjustments specific to the lease, for example term,
country, currency and security
The Group is exposed to potential future increases in variable lease payments
based on an index or rate, which are not included in the lease liability until
they take effect. When adjustments to lease payments based on an index or rate
take effect, the lease liability is reassessed and adjusted against the
right-of-use asset.
Lease payments are allocated between principal and finance cost. The finance
cost is charged to the income statement over the lease period so as to produce
a constant periodic rate of interest on the remaining balance of the liability
for each period.
Payments associated with short-term leases and leases of low value assets are
recognised on a straight-line basis as an expense in the income statement.
Short-term leases are leases with a lease term of 12 months or less.
For lease arrangements where all partners of a joint operation are considered
to share the primary responsibility for lease payments under a lease contract,
the Group recognises its share of the respective right-of-use asset and lease
liability. This situation is most common where the parties of a joint
operation co-sign the lease contract.
The Group recognises a gross lease liability for leases entered into on behalf
of a joint operation where it has primary responsibility for making the lease
payments. In such instances, if the arrangement between the Group and the
joint operation represents a finance sublease, the Group recognises a net
investment in sublease for amounts recoverable from non-operators whilst
derecognising the respective portion of the gross right-of-use asset. The
gross lease liability is retained on the balance sheet.
The net investment in sublease is classified as either trade and other
receivables or long-term receivables on the balance sheet according to whether
or not the amounts will be recovered within 12 months of the balance sheet
date. Finance income is recognised in respect of net investment in subleases.
Provisions for liabilities
A provision is recognised when the Group has a legal or constructive
obligation as a result of a past event, it is probable that an outflow of
resources embodying economic benefits will be required to settle the
obligation and a reliable estimate can be made of the amount of the
obligation.
The expense relating to any provision is presented in the income statement net
of any reimbursement. If the effect of the time value of money is material,
provisions are discounted using a current pre-tax rate that reflects, where
appropriate, the risk specific to the liability. Where discounting is used,
the increase in the provision due to the passage of time is recognised as part
of finance costs in the income statement.
The estimated cost of dismantling and restoring the production and related
facilities at the end of the economic life of each field is recognised in full
when the related facilities are installed. The amount provided is the present
value of the estimated future restoration cost. A non-current asset is also
recognised. Any changes to estimated costs or discount rates are dealt with
prospectively.
The Group recognises a provision for the estimated CO2 emissions costs when
actual emissions exceed the emission rights granted and still held. When
actual emissions exceed the amount of emission rights granted, a provision is
recognised for the exceeding emission rights based on the purchase price of
allowances concluded in forward contracts or market quotations at the
reporting date.
Group retirement benefits
The Group's various pension plans consist of both defined benefit and defined
contribution plans. Payments to defined contribution retirement benefit plans
are charged as an expense as they fall due. Payments made to state-managed
retirement benefit schemes are dealt with as payments to defined contribution
plans where the Group's obligations under the schemes are equivalent to those
arising in a defined contribution retirement benefit plan.
The Group operates a defined benefit pension scheme, which requires
contributions to be made to a separately administered fund. The cost of
providing benefits is determined using the projected unit credit method, with
actuarial valuations being carried out at each balance sheet date. Actuarial
gains and losses are recognised immediately in the statement of comprehensive
income.
The retirement benefit obligation recognised in the balance sheet represents
the present value of the defined benefit obligation as reduced by the fair
value of plan assets. Any asset resulting from this calculation is limited to
the present value of available refunds and reductions in future contributions
to the plan.
The Group participates in a legally independent multi-employer plan which is
financed by employer and employee contributions as well as the return on plan
assets. Since sufficient information is not available for this multi-employer
plan, the Group accounts for the plan as if it was a defined contribution
plan.
In the case of contribution-based defined benefit pension plans, the Group
makes contribution payments to special-purpose funds as well as to life
insurances. These contribution payments are recorded as expenses. Furthermore,
for some of the Group's contribution-based defined benefit pension plans,
benefit obligations are recognised at the fair value of these funds, so far as
the assets exceed the guaranteed minimum benefit amount.
If the assets do not exceed the guaranteed minimum benefit amount, benefit
obligations for these contribution-based benefit plans are recognised in the
guaranteed minimum benefit amount.
The defined benefit plans are administered by a separate fund that is legally
separated from the Group. The trustees of the pension fund are required by law
to act in the interest of the fund and of all relevant stakeholders in the
plans.
Trade payables
Initial recognition of trade payables is at fair value. Subsequently they are
stated at amortised cost.
Taxes
Current tax
Current tax assets and liabilities for the current and prior periods are
measured at the amount expected to be recovered from or paid to the taxation
authorities. The tax rates and laws used to compute the amount are those that
are enacted or substantively enacted at the reporting date in the countries
where the Group operates and generates taxable income.
Current income tax related to items recognised directly in other comprehensive
income or equity is recognised in other comprehensive income or directly in
equity, not in the income statement.
Management periodically evaluates positions taken in the tax returns with
respect to situations in which tax regulations are subject to interpretation
and establishes provisions where appropriate.
Deferred tax
Deferred taxation is recognised in respect of all temporary differences
arising between the tax bases of the assets and liabilities and their carrying
amounts in the financial statements with the following exceptions:
▪ When the deferred tax liability arises from the initial
recognition of goodwill or an asset or liability in a transaction that is not
a business combination and, at the time of the transaction, affects neither
the accounting profit nor taxable profit or loss and does not give rise to
equal taxable and deductible temporary differences
▪ In respect of taxable temporary differences associated with
investments in subsidiaries, associates and interests in joint arrangements,
when the timing of the reversal of the temporary differences can be controlled
and it is probable that the temporary difference will not reverse in the
foreseeable future
Deferred tax assets are recognised for all deductible temporary differences,
the carry forward of unused tax credits and any unused tax losses. Deferred
income tax assets are recognised only to the extent that it is probable that
the taxable profit will be available against which the deductible temporary
difference, carried forward tax credits or tax losses can be utilised.
Deferred income tax assets and liabilities are measured on an undiscounted
basis at the tax rates that are expected to apply when the related asset is
realised or liability is settled, based on tax rates and laws enacted or
substantively enacted at the reporting date. The carrying amount of the
deferred income tax asset is reviewed at each balance sheet date and reduced
to the extent that it is no longer probable that sufficient taxable profits
will be available to allow all or part of the asset to be recovered. The Group
reassesses any unrecognised deferred tax assets each year taking into account
changes in oil and gas prices, the Group's proven and probable reserves and
resources profile and forecast capital and operating expenditures.
Deferred income tax assets and liabilities are offset only if a legally
enforceable right exists to offset current assets against current tax
liabilities, the deferred income tax relates to the same tax authority and
that same tax authority permits the Group to make a single net payment.
Deferred tax is charged or credited in the income statement, except when it
relates to items charged or credited in other comprehensive income, in which
case the deferred tax is also dealt with in other comprehensive income.
Where deferred tax assets are recognised for temporary differences arising
between the tax base of the Group's share incentive plans and their carrying
value, to the extent that the future tax deduction exceeds the related
cumulative IFRS 2 expense, the excess movement on the associated deferred tax
balance is dealt with directly in equity. To the extent that the future tax
deduction is less than or equal to the cumulative IFRS 2 expense, the movement
on the associated deferred tax balance is charged or credited in the income
statement.
Revenue from contracts with customers
Revenue from contracts with customers is recognised when the Group satisfies a
performance obligation by transferring a good or service to a customer. A good
or service is transferred when the customer obtains control of that good or
service. Revenue associated with the sale of crude oil, natural gas and
natural gas liquids (NGLs) is measured based on the consideration specified in
contracts with customers with reference to quoted market prices in active
markets, adjusted according to specific terms and conditions as applicable
according to the sales contracts. The transfer of control of oil, natural gas,
natural gas liquids and other items sold by the Group occurs when title passes
at the point the customer takes physical delivery. The Group principally
satisfies its performance obligations at a point in time and the amounts of
revenue recognised relating to performance obligations satisfied over time are
not significant.
The Group engages in sleeve and optimisation gas trading activities as part of
its broader commodity risk management and commercial strategy. Contracts are
evaluated based on their intent and usage. Where contracts are entered into
and held for the purpose of generating profit from short-term market movements
or dealer margins, they are classified as held for trading and recognised as
derivatives. Gains and losses from these derivative contracts related to
revenue and costs associated with other contracts that are classified as held
primarily for the purpose of being traded are reported on a net basis as other
operating income in the consolidated income statement.
Over/underlift
Differences between the production sold and the Group's share of production
result in an overlift or an underlift. Underlift positions are measured at net
realisable value using an observable year-end oil or gas market price.
Overlift positions are measured using the sales price that generated the
overlift. Underlift and overlift positions are included in receivables or
payables respectively. Movements during the accounting period are recognised
within cost of sales.
Interest income
Interest income is recognised on an accruals basis, by reference to the
principal outstanding and at the effective interest rate applicable.
Borrowing costs
Borrowing costs directly attributable to the acquisition, construction or
production of an asset that necessarily takes a substantial period of time to
get ready for its intended use or sale (a qualifying asset) are capitalised as
part of the cost of the respective assets. Where the funds used to finance a
project form part of general borrowings, the amount capitalised is calculated
using a weighted average of rates applicable to relevant general borrowings of
the Group during the period. All other borrowing costs are recognised in the
income statement in the period in which they are incurred.
New accounting standards and interpretations
Management anticipates that all relevant pronouncements will be adopted for
the first period beginning on or after the effective date of the
pronouncement. New standards, amendments and interpretations not adopted in
the current year have not been disclosed as they are not expected to have a
material impact on the consolidated financial statements.
Amendments issued and effective in the current year
The Group applied for the first-time certain standards and amendments, which
are effective for annual periods beginning on or after 1 January 2025 (unless
otherwise stated).
Lack of exchangeability - Amendments to IAS 21
For annual reporting periods beginning on or after 1 January 2025, Lack of
Exchangeability - Amendments to IAS 21 The Effects of Changes in Foreign
Exchange Rates specifies how an entity should assess whether a currency is
exchangeable and how it should determine a spot exchange rate when
exchangeability is lacking. The amendments also require disclosure of
information that enables users of its financial statements to understand how
the currency not being exchangeable into the other currency affects, or is
expected to affect, the entity's financial performance, financial position and
cash flows.
The amendments had no impact on the consolidated financial statements.
Standards issued but not yet effective
The Group has not early adopted any other standard, interpretation or
amendment that has been issued but is not yet effective.
IFRS 18 Presentation and Disclosure in Financial Statements
In April 2024, the IASB issued IFRS 18, which replaces IAS 1 Presentation of
Financial Statements. IFRS 18 introduces new requirements for presentation
within the statement of profit or loss, including specified totals and
subtotals. Furthermore, entities are required to classify all income and
expenses within the statement of profit or loss into one of five categories:
operating, investing, financing, income taxes and discontinued operations,
whereof the first three are new.
The standard requires disclosure of newly defined management-defined
performance measures, subtotals of income and expenses, and it also includes
new requirements for aggregation and disaggregation of financial information
based on the identified 'roles' of the primary financial statements and the
associated notes.
In addition, narrow-scope amendments have been made to IAS 7 Statement of Cash
Flows, which include changing the starting point for determining cash flows
from operations under the indirect method, from 'profit or loss' to 'operating
profit or loss' and removing the optionality around classification of cash
flows from dividends and interest. In addition, there are consequential
amendments to several other standards.
IFRS 18, and the amendments to the other standards, are effective for
reporting periods beginning on or after 1 January 2027, but earlier
application is permitted and must be disclosed. IFRS 18 will apply
retrospectively.
The Group is currently working to identify all impacts the amendments will
have on the primary financial statements and notes to the financial
statements. The initial expected material impacts on Group's financial
statements are as follows:
▪ Foreign exchange difference will be classified in the category
where the related income and expense form the item giving rising to the
foreign exchange difference.
▪ New disclosure will be added: (a) management-defined performance
measures; and (b) a reconciliation for each line item in the statement of
profit or loss between the restated amounts presented applying IFRS 18 and the
amounts previously presented applying IAS 1.
Additional standards issued but not yet effective
Other standards and amendments that are not yet effective and have not been
adopted early by the Group include:
▪ Amendments to the Classification and Measurement of Financial
Instruments (Amendments to IFRS 9 and 7). The Amendments are effective for
annual periods starting on or after 1 January 2026;
▪ Contracts Referencing Nature-dependent Electricity (Amendments to
IFRS 9 and IFRS 7). The amendments will take effect for annual reporting
periods starting on or after 1 January 2026;
▪ Annual Improvements to IFRS Accounting Standards-Volume 11. The
amendments will be effective for reporting periods beginning on or after 1
January 2026; and
▪ IFRS 19 Subsidiaries without Public Accountability: Disclosures.
IFRS 19 will become effective for reporting periods beginning on or after
1 January 2027
These standards and amendments are not expected to have a significant impact
on the financial statements in the period of initial application and therefore
no disclosures have been made.
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 consisted of
one class of business being the acquisition, exploration, development and
production of oil and gas reserves and related activities. The operating
segments are divided geographically and managed across nine business units:
namely Norway, UK, Germany, Mexico, Argentina, North Africa, Southeast Asia,
CCS and Corporate. The CCS segment includes Denmark.
Information on major customers can be found in note 4.
Year ended 31 December 2025 ($ million) Norway UK Germany Mexico Argentina North Africa Southeast Asia CCS Corporate Total segments Adjustments and eliminations Consolidated
Revenue and other income
External customers
- Crude oil sales 997 113 422 146 66 46 50 13 1,634 3,487 - 3,487
- Gas sales (27) 124 11 9 431 160 96 - 5,229 6,033 - 6,033
- Condensate sales 275 73 2 - 19 44 - - 98 511 - 511
- Other revenue 15 44 1 - - - - - - 60 - 60
Other operating income - 23 1 3 58 65 - - 20 170 - 170
Inter-segment 3,070 3,493 243 - - - - - - 6,806 (6,806) -
Total revenue and other income 4,330 3,870 680 158 574 315 146 13 6,981 17,067 (6,806) 10,261
Cost of operations (2,880) (2,354) (674) (91) (383) (177) (83) (28) (5,700) (12,370) 6,806 (5,564)
Impairment of property, plant and equipment - (11) (49) (77) - (178) (35) (16) 1 (365) - (365)
Exploration and evaluation expenses and new ventures (8) (9) (1) (19) - - - (69) - (106) - (106)
Exploration costs written-off (37) (53) - (107) - (3) - - - (200) - (200)
General and administrative expenses (61) (50) (75) (26) (29) (14) (7) - (274) (536) - (536)
Segment operating profit 1,344 1,393 (119) (162) 162 (57) 21 (100) 1,008 3,490 - 3,490
Finance income 461
Finance expenses (1,150)
Income tax expense (2,983)
Loss for the year (182)
Total capital additions 903 487 100 102 107 112 82 33 20 1,946 - 1,946
Total depreciation, depletion and amortisation 971 1,296 257 36 198 133 35 - 33 2,959 - 2,959
As at 31 December 2025
Total other non-current assets 9,033 5,772 3,002 1,823 4,070 436 316 29 169 24,650 - 24,650
Total assets 9,285 6,168 3,123 2,157 4,315 715 716 34 2,580 29,093 - 29,093
Total liabilities (6,667) (6,216) (2,017) (438) (1,136) (152) (277) (132) (5,852) (22,887) - (22,887)
Year ended 31 December 2024 ($ million) Norway UK Germany Mexico Argentina North Africa Southeast Asia CCS Corporate Total segments Adjustments and eliminations Consolidated
Revenue and other income
External customers
- Crude oil sales 343 1,755 158 55 23 10 141 - 393 2,878 - 2,878
- Gas sales 86 1,143 9 3 111 63 115 - 1,406 2,936 - 2,936
- Condensate sales 87 156 1 - 6 21 - - 12 283 - 283
- Other revenue 3 39 - - - 19 - - - 61 - 61
Other operating income - 33 4 2 7 6 1 - 15 68 - 68
Inter-segment 946 791 74 - - - - - 68 1,879 (1,879) -
Total revenue and 1,465 3,917 246 60 147 119 257 - 1,894 8,105 (1,879) 6,226
other income
Cost of operations (520) (2,699) (243) (37) (120) (58) (172) (6) (1,631) (5,486) 1,873 (3,613)
Reversal/(impairment) of property, plant and equipment 14 (323) (26) - - - (15) (5) 3 (352) - (352)
Impairment of right-of-use asset - (20) - - - - - - - (20) - (20)
Exploration and evaluation expenses and new ventures (22) (4) - - - - - (40) (2) (68) - (68)
Exploration costs written-off (76) (81) - - - (2) (14) - - (173) - (173)
General and administrative expenses (24) (76) (19) (6) (9) (7) (7) (1) (203) (352) - (352)
Segment operating profit 837 714 (42) 17 18 52 49 (52) 61 1,654 (6) 1,648
Finance income 173
Finance expenses (602)
Income tax expense (1,312)
Loss for the year (93)
Total capital additions 374 698 59 110 61 46 93 33 70 1,544 - 1,544
Total depreciation, depletion and amortisation 293 1,115 146 10 58 16 78 - 29 1,745 - 1,745
As at 31 December 2024 as restated
Total other non-current assets 9,055 6,840 2,817 1,951 4,164 581 523 26 229 26,186 - 26,186
Total assets 9,434 7,306 2,992 2,420 4,488 917 919 18 1,783 30,277 - 30,277
Total liabilities (6,622) (6,936) (1,921) (482) (1,292) (165) (454) (108) (6,046) (24,026) - (24,026)
4 Revenue from contracts with customers and other operating
income
2025 2024
Year ended 31 December $ million $ million
Type of goods
Crude oil sales 3,487 2,878
Gas sales 6,033 2,936
Condensate sales 511 283
Total revenue from contracts with customers(1) 10,031 6,097
Tariff income 48 32
Other revenue 12 29
Revenue from production activities 10,091 6,158
Other operating income(2) 170 68
Total revenue and other operating income 10,261 6,226
(1) Revenues from contracts with customers of $9,930 million (2024: $6,115
million) include crude oil sales of $3,371 million (2024: $2,846 million) and
gas sales of $6,048 million (2024: $2,986 million). This was prior to realised
hedging gains in the year of $116 million (2024: $32 million) on crude oil and
realised hedging losses in the year of $15 million (2024: $50 million) on gas
sales.
(2) Other operating income principally represents receipts of acquired
credit-impaired assets, government subsidies in Argentina and fair value
accounting of commodity derivatives.
For 2025, three customers (2024: one customer) individually contributed more
than 10 per cent of the Group's revenue. They were energy trading companies of
Citigroup (24 per cent), Eni S.p.A. (11 per cent) and energy trading companies
of the Shell group (10 per cent) (2024: energy trading companies of the Shell
group, 54 per cent).
5 Operating profit
2025 2024
Year ended 31 December Note $ million $ million
Cost of operations
Production, insurance and transportation costs 2,317 1,612
Commodity purchases 238 28
Royalties 140 47
(Reversal)/impairment of receivables (2) 21
Depreciation of oil and gas assets 12 2,758 1,516
Depreciation of right-of-use oil and gas assets 13 216 269
Capitalisation of IFRS 16 lease depreciation on oil and gas assets 13 (67) (81)
Movement in over/underlift balances and hydrocarbon inventories (36) 201
Total cost of operations 5,564 3,613
Impairment expense of oil and gas property, plant and equipment 12 289 178
Net impairment loss due to increase in decommissioning provisions on oil and 12 41 174
gas tangible assets
Impairment of assets previously held as assets held for sale 18 35 -
Impairment of right-of-use asset 13 - 20
Exploration costs written-off(1) 11 200 173
Exploration and evaluation expenditure and new ventures(1) 106 68
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets 13 17 16
Depreciation of non-oil and gas assets 12 15 6
Amortisation of non-oil and gas intangible assets 11 20 19
Acquisition, restructuring and reorganisation-related transaction costs(2) 78 119
Other administrative costs 406 192
Total general and administrative expenses(2,5) 536 352
Auditors' remuneration
Audit fees
Fees payable to the company's auditor for the company's Annual Report 5 6
Audit of the company's subsidiaries pursuant to legislation 2 1
Non-audit fees(3)
Other services pursuant to legislation - interim review - -
Other services(4) 1 2
(1) During the year, the Group expensed $306 million (2024: $241 million)
of exploration and appraisal activities. This covers exploration write-off
expense of $200 million (2024: $173 million) including write-off of costs
associated with projects in our Norway Business Unit ($22 million), licence
relinquishments in UK ($40 million) and Mexico ($107 million), and $84 million
(2024: $40 million) costs associated with ongoing projects within the Group's
CCS Business Unit, including $50 million (2024: $nil) associated with energy
transition expenditure.
(2) Total general and administrative expenses in 2025 include consultancy
and business development costs of $78 million (2024: $119 million) associated
with various initiatives and M&A activities across the Group primarily for
the LLOG and Waldorf transactions. In 2024 these costs mainly related to the
acquisition of the Wintershall Dea asset portfolio which completed in
September 2024.
(3) The company has a policy on the provision of non-audit services by the
auditors which is aimed at ensuring their continued independence. This policy
is available on the Group's website. The use of the external auditors for
services relating to accounting systems or financial statement preparations is
not permitted, as are various other services that could give rise to conflicts
of interest or other threats to the auditors' objectivity that cannot be
reduced to an acceptable level by applying safeguards.
(4) Other non-audit services in 2025 primarily relate to bond issuance
related activities..
(5) Expenses related to both short-term and low value lease arrangements are
considered to be immaterial for reporting purposes.
6 Staff costs
2025 2024
Year ended 31 December $ million $ million
Wages and salaries and other staff costs 495 428
Social security costs 69 46
Pension costs 49 35
Total staff costs 613 509
The average number of employees employed by the Group worldwide was:
2025 2024
Number Number
Offshore based 571 545
Onshore and administration 2,341 1,614
Total staff 2,912 2,159
During the period September to December 2024, following the acquisition of the
Wintershall Dea portfolio, the Group employed an average of 3,019 employees.
Staff costs above are recharged to joint venture partners where applicable, or
are capitalised to the extent that they are directly attributable to capital
or decommissioning projects. The above costs include share-based payments as
disclosed in note 28.
The Group operates defined contribution and benefit pension schemes for which
further details are provided in note 29.
7 Finance income and finance expenses
2025 2024
Year ended 31 December Note $ million $ million
Finance income
Bank interest 92 37
Other interest and finance gains 24 16
Realised gains on foreign exchange forward contracts 191 -
Unrealised gains on derivatives(1) 109 -
Gain on financial instruments for contingent consideration 39 -
Lease finance income 1 1
Dividend income 5 1
Foreign exchange gains - 118
Total finance income 461 173
Finance expenses
Interest payable on bonds 173 59
Interest payable on other facilities 3 19
Unrealised losses on derivatives(1) - 43
Realised losses on foreign exchange forward contracts - 71
Realised losses on interest derivatives 5 -
Finance expense on deferred revenue - 5
Lease interest 13 40 53
Bank and financing fees(2) 123 139
Other interest and finance expenses 64 10
Unwinding of discount on decommissioning and other provisions 21 293 221
Foreign exchange losses 485 -
1,186 620
Finance costs capitalised during the year(3) (36) (18)
Total finance expense 1,150 602
(1) Gains on derivatives include mark to market gains on foreign currency
and interest rate derivatives of $37 million (2024: $30 million loss),
derivative ineffectiveness gains of $43 million (2024: $8 million losses) and
$29 million gains related to changes in the fair value of an embedded
derivative within one of the Group's gas contracts (2024: $5 million loss).
(2) Bank and financing fees include an amount of $81 million (2024: $102
million) relating to the amortisation of arrangement fees and related costs
capitalised against the Group's long-term borrowings (note 22). This relates
to the amortisation of capitalised fees in respect of the Group's bonds of
$5,151 million.
(3) 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 4.3 per cent to the expenditures on the qualifying assets (2024: 4.5
per cent).
8 Income tax
The major components of income tax expense are:
2025 2024
Year ended 31 December $ million $ million
Current income tax expense
Charge for the year 3,510 1,413
Adjustments in respect of prior years (5) 2
Total current income tax expense 3,505 1,415
Deferred tax credit
Origination and reversal of temporary differences in current year (781) (168)
Impact of changes in tax laws and rates(1) 265 77
Adjustments in respect of prior years (6) (12)
Total deferred tax credit (522) (103)
Total tax expense reported in the income statement 2,983 1,312
The tax expense/(credit) in the statement of comprehensive income is as
follows:
Tax expense/(credit) on cash flow hedges 752 (379)
Tax expense/(credit) on actuarial gains and losses 11 (4)
Total tax expense/(credit) reported in the statement of comprehensive income 763 (383)
(1) The amount for 2025 comprises a $311 million charge in respect of the
extension of the Energy Profits Levy in the UK by two years to 31 March 2030
and a $46 million credit in respect of the reduction in the German Federal
Corporate Income Tax rate by 1 per cent per annum starting from 2028 through
to 2032. The amount for 2024 comprises the impact of the increase in Energy
Profits Levy from 35 per cent to 38 per cent from 1 November 2024.
Reconciliation of tax expense and the accounting profit before taxation at the
Group's statutory tax rate is as follows:
2025 2024
Year ended 31 December $ million $ million
Profit before income tax 2,801 1,219
At the Group's statutory tax rate of 78 per cent (2024: 78 per cent) 2,185 951
Effects of:
Expenses not deductible for tax purposes 153 68
Adjustments in respect of prior years (11) (10)
Remeasurement of deferred tax 25 70
Deferred Energy Profits Levy extension 311 77
Impact of different tax rates 272 282
Allowances and other tax uplifts (86) (113)
Future dividends from investments in subsidiaries, branches and associates - (11)
Impact of exchange rate differences 134 (2)
Total tax expense reported in the consolidated income statement at the 2,983 1,312
effective tax rate of 106 per cent (2024: 108 per cent)
The tax expense reconciliation has been prepared based on the statutory tax
rate of 78 per cent applicable to oil and gas production in the UK and Norway,
the two most significant jurisdictions of operation for the Group. Management
believes that using this rate provides the most meaningful comparison between
the expected tax expense, based on accounting profit, and the actual tax
expense recognised.
The effective tax rate for the year is 106 per cent, compared to 108 per cent
for 2024.
The effective tax rate of 106 per cent is significantly higher than the
statutory rate of 78 per cent for the Group. This is primarily due to a $311
million deferred tax charge arising from the extension of the Energy Profits
Levy (EPL) in the UK by two years, from 31 March 2028 to 31 March 2030, as
well as non-deductible foreign exchange losses and the weighting of earnings
and expenditure across the various jurisdictions with different statutory tax
rates.
The future effective tax rate is influenced by the profit mix across the
jurisdictions in which the Group operates. The UK and Norway are expected to
remain the principal jurisdictions where profits will be earned, so their
statutory tax rates for oil and gas production operations are anticipated to
continue as the primary factors influencing the Group's future tax expense.
The extension of the EPL by the UK Government from 31 March 2028 to 31 March
2030 was substantively enacted on 3 March 2025 and the associated $311 million
increase in deferred tax liabilities has been recognised in this period's
financial statements.
In the Autumn Budget on 26 November 2025, the UK Government confirmed its
intention to introduce a new Oil and Gas Price Mechanism (OGPM) from 1 April
2030 as a permanent replacement to the Energy Profits Levy. Based on the
details announced in the Budget, the OGPM will apply a 35 per cent tax on
revenues when commodity prices exceed specified price thresholds of $90 per
barrel for oil and 90 pence per therm for gas, to be adjusted annually in line
with CPI inflation.
On 11 July 2025, the German Federal Council passed legislation mandating
annual 1 per cent reductions in the Federal Corporate Income Tax rate starting
from 2028 through to 2032. Including Trade Tax, Germany's headline tax rate
will reduce from approximately 32 per cent to 27 per cent. This has resulted
in a reduction in the Group's deferred tax liability of $46 million which has
been recognised in this period's financial statements.
Deferred tax
The principal components of deferred tax are set out in the following tables:
2025 2024
As restated
As at 31 December $ million $ million
Deferred tax assets 121 130
Deferred tax liabilities (6,491) (6,177)
Total deferred tax (6,370) (6,047)
The presentation above takes into account the offsetting of deferred tax
assets and deferred tax liabilities within the same tax jurisdiction (where
this is permitted). The overall deferred tax balance in a jurisdiction
determines if the deferred tax related to that jurisdiction is disclosed
within deferred tax assets or deferred tax liabilities.
The origination of and reversal of temporary differences are, as shown in the
next table, related primarily to movements in the carrying amounts and tax
base values of expenditure and the timing of when these items are charged
and/or credited against accounting and taxable profit.
Accelerated capital allowances Decom-missioning Losses Fair value of derivatives Other(1) Overseas Total
$ million $ million $ million $ million $ million $ million $ million
As at 1 January 2024 (2,901) 1,574 181 6 21 (171) (1,290)
Deferred tax (expense)/credit (44) 257 (114) (38) 42 - 103
Other comprehensive income - - - 380 4 - 384
Other reserves(2) - - - - (1) - (1)
Additions from business combinations (6,509) 971 201 (14) (2) - (5,353)
Reclassification to assets 19 - - - - - 19
held for sale(3)
Reclassifications(4,5) (221) 7 28 - 15 171 -
Foreign exchange 75 (18) (8) 2 (4) - 47
As at 31 December 2024 (9,581) 2,791 288 336 75 - (6,091)
Additions from business combinations 44 - - - - - 44
as restated
As at 31 December 2024 as restated (9,537) 2,791 288 336 75 - (6,047)
Deferred tax credit/(expense) 667 (111) (100) 52 14 - 522
Other comprehensive income - - - (752) (11) - (763)
Disposal/reclassification to assets held for sale(6) 14 (3) - - - - 11
Reclassifications 1 - - 34 (35) - -
Foreign exchange (157) 62 6 (1) (3) - (93)
As at 31 December 2025 (9,012) 2,739 194 (331) 40 - (6,370)
(1) includes deferred tax movements related to investment allowances,
share-based payments, pensions, financial instruments, leases, provisions,
inventory and working capital.
(2) In 2024, movement in other reserves relates to the element of deferred
tax on UK share-based payments taken to profit and loss reserves.
(3) The presentation of the reclassification of deferred tax liabilities
directly associated with assets held for sale has changed compared to the
prior year. The deferred tax liability of $19 million relating to the Group's
Vietnam business which was classified as held for sale at 31 December 2024 was
previously included within the closing balance in respect of accelerated
capital allowances.
(4) In 2024, items previously classified as overseas balances in 2023 were
reclassified into specific deferred tax categories.
(5) Balances related to UK investment allowances ($12 million) have been
reclassified from accelerated capital allowances to other.
(6) Of the total amount disposed of or reclassified to assets held for sale
in 2025, a $22 million deferred tax liability related to the reclassification
of the operated Indonesia business to held for sale and a $11 million deferred
tax asset related to the disposal of the Vietnam business.
The Group's deferred tax assets 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 tax 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 tax losses and allowances. The recovery of the Group's
decommissioning deferred tax assets is additionally supported in the UK by the
ability to carry back decommissioning tax losses against prior period ring
fence profits, and in Norway by fiscal rules that provide cash refunds of the
tax value of decommissioning tax losses.
In the UK, ring fence tax losses cannot be offset against profits subject to
EPL nor are deductions allowed for decommissioning related expenditure.
Consequently, any deferred tax assets representing future decommissioning
deductions or ring fence tax losses are unaffected by the EPL. The primary
impact of the EPL is on the deferred tax liability associated with accelerated
capital allowances. The closing net deferred tax liability for the period is
$6,370 million (2024 as restated: $6,047 million), of which $1,006 million
(2024: $877 million) relates to deferred tax liabilities arising from the
impact of the EPL.
Consistent with other sensitivity analyses undertaken, we have assessed the
impact on the recoverability of deferred tax assets based on a decrease of 10
per cent to the Harbour scenario average crude price curves. While there would
generally be no material impacts, tax losses in Mexico are particularly
sensitive to the timing of profits as they expire within a 10-year period once
generated. Under this scenario, the deferred tax assets currently recognised
for Mexican tax losses would decrease by around $39 million.
Unrecognised tax losses and allowances
Deferred tax assets are recognised for tax loss carry forwards, tax allowances
and other deductible temporary differences to the extent that it is probable
the associated tax benefits will be realised through offsetting future taxable
profits or by carrying losses back to prior periods' profits. At the end of
the accounting period, the Group had not recognised deferred tax assets for
tax losses, allowances and other deductible temporary differences amounting to
approximately $3,539 million (2024: $2,743 million). These other deductible
temporary differences include unclaimed tax depreciation and investment
allowances, unrealised losses on non-commodity derivatives and decommissioning
related provisions.
2025 2024
As at 31 December $ million $ million
Tax losses by expiry date
Expiring within 5 years 649 477
Expiring within 6-10 years 478 240
No expiration 1,953 1,621
3,080 2,338
Other deductible temporary differences and allowances
Decom-missioning 154 73
Fair value of financial instruments 30 109
Investment allowances 202 185
Unclaimed tax depreciation 73 38
Total unrecognised tax losses and allowances 3,539 2,743
No deferred tax liabilities were recognised for temporary differences
associated with investments in subsidiaries, branches and associates of
approximately $130 million (2024: $293 million) because the Group is in a
position to control the timing of the reversal of the temporary differences
and it is probable that such differences will not reverse in the foreseeable
future.
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
became effective from 1 January 2024.
The Group has applied the mandatory exception in IAS 12 to recognising and
disclosing information about deferred tax assets and liabilities related to
Pillar Two income taxes.
The Group has performed an assessment of its potential exposure to Pillar Two
income taxes for periods from 1 January 2024. The assessment of the potential
exposure 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 has not recorded a liability for Pillar Two income taxes for the year
ended 31 December 2025 in respect of any jurisdiction.
Uncertain tax positions
The Group considers an uncertain tax position to exist when it believes that
the amount of profit subject to tax in the future may exceed the amount
initially reflected in the Group's tax returns. The Group applies IFRIC 23
Uncertainty over Income Tax Treatments in relation to uncertain tax positions.
When management judges that an outflow of funds is probable and a reliable
estimate of the dispute can be made, a provision is recognised for the best
estimate of the most likely liability.
In estimating any such liability, the Group adopts a risk-based approach,
considering the specific circumstances of each dispute. This is based on
management's interpretation of tax law and, where appropriate, is supported by
independent specialist advice. These estimates are inherently judgemental and
can change significantly over time as disputes progress and new facts emerge.
Provisions are reviewed continuously. However, the resolution of tax issues
may take a long time to conclude, and there is a possibility that the amounts
ultimately paid could differ from the amounts initially provided.
In prior periods, the Group disclosed a contingent liability in respect of an
uncertain tax position arising within certain UK subsidiaries. The matter
related to the timing of taxation of fair value movements and realised gains
and losses on derivative instruments entered into to hedge commodity price
risk. Based on independent external tax advice, management concluded that an
outflow of economic benefits was not probable. Accordingly, no liability was
recognised in the Group's consolidated financial statements in previous
reporting periods. The contingent liability, estimated at up to $130 million
as at 31 December 2024, was previously disclosed due to the possibility that
HM Revenue & Customs (HMRC) might apply a different tax treatment to these
hedging transactions. The potential exposure arose primarily from differences
in applicable tax rates over the relevant periods. During 2025, HMRC completed
a review of this matter and confirmed that the Group's filed tax position
requires no adjustments. Consequently, the uncertainty has been resolved and
no financial impact results from this resolution, as no liability was
recognised in prior periods.
9 Loss per share (EPS)
Basic EPS is calculated by dividing the profit/loss after tax attributable to
ordinary shareholders of the Group by the weighted average number of ordinary
shares in issue during the year.
Diluted EPS is calculated by dividing the profit/loss after tax attributable
to ordinary shareholders by the weighted average number of ordinary share in
issue during the year plus the weighted average number of ordinary shares that
would be issued on conversion of all the dilutive potential ordinary shares
into ordinary shares.
The following table reflects the income and share data used in the basic and
diluted EPS calculations:
Year ended 31 December 2025 2024
Loss per share ($ million)
Earnings for the purpose of basic earnings per share (263) (108)
Effect of dilutive potential ordinary shares - -
Loss for the purpose of diluted earnings per share (263) (108)
Number of ordinary shares (millions)
Weighted average number of ordinary shares (voting) for the purpose of basic 1,426 990
earnings per share
Weighted average number of ordinary shares (non-voting) for the purpose of 284 93
basic earnings per share
Weighted average number of ordinary shares (voting) for the purpose of diluted 1,426 990
earnings per share
Weighted average number of ordinary shares (non-voting) for the purpose of 251 93
diluted earnings per share
Loss per share ($ cents)
Basic:
Ordinary shares voting (15) (10)
Ordinary shares non-voting (17) (11)
Diluted:
Ordinary shares voting (16) (10)
Ordinary shares non-voting (17) (11)
10 Goodwill
Goodwill represents the difference between the aggregate of the fair value of
purchase consideration transferred at the acquisition date and the fair value
of the identifiable assets.
2024
2025 As restated
Carrying value Note $ million $ million
At 1 January 5,062 1,302
Additions from business combinations 14 - 3,760
At 31 December 5,062 5,062
Goodwill is allocated as follows to the operating segments:
2024
2025 As restated
Carrying value $ million $ million
Norway 2,648 2,648
UK 1,277 1,277
Germany 321 321
Mexico 199 199
Argentina 593 593
Southeast Asia 24 24
At 31 December 5,062 5,062
The goodwill balance consists of balances arising from the acquisition of
Wintershall Dea's upstream oil and gas assets on 3 September 2024, the
completion of the all-share merger between Premier Oil plc and Chrysaor
Holdings Limited in March 2021, Chrysaor Holdings Limited's acquisition of the
ConocoPhillips UK business, and the UK North Sea assets from Shell, which
completed on 30 September 2019 and 1 November 2017, respectively.
Impairment testing of goodwill
In accordance with IAS 36 Impairment of Assets, goodwill is reviewed for
impairment at the year-end, or more frequently if there are indications that
goodwill might be impaired.
The goodwill recognised in business combinations is allocated to operating
segments for the purpose of impairment testing. The carrying value of goodwill
is tested at the operating segment level against the aggregated headroom
arising from the impairment testing of corresponding segment assets. The
carrying value of the assets is the sum of tangible assets, intangible assets
and goodwill as of the assessment date. In the asset impairment test
performed, and where applicable, the carrying value is adjusted by deferred
tax which protects goodwill from an immediate impairment. When the deferred
tax liabilities from the acquisitions naturally unwind and decrease, as a
result of depreciation through production, more goodwill is exposed to
impairment. This may lead to future impairment charges even though other
assumptions remain stable.
For the purpose of its goodwill impairment assessments, the Group uses the
fair value less cost of disposal method (FVLCD) to calculate the recoverable
amount of the operating segments consistent with a Level 3 fair value
measurement (see note 23). In determining the recoverable value, appropriate
discounted-cash-flow valuation models are used, incorporating market-based
assumptions. Management's commodity assumptions are discussed in note 2.
At the year-end, the Group tested all allocated business unit goodwill for
impairment in accordance with the accounting policy and no goodwill impairment
was recognised (2024: $nil). Goodwill will ultimately be impaired to the
income statement as the relevant operating segment businesses mature.
Determining recoverable amount
The recoverable amounts of the CGU and fields have been determined on a fair
value less costs to sell basis. The key assumptions used in determining the
fair value are often subjective, such as the future long-term oil and gas
price assumption, or the operational performance of the assets. Discounted
cash flow models comprising asset-by-asset life of field projections using
Level 3 inputs (based on the IFRS 13 fair value hierarchy) have been used to
determine the recoverable amounts. The fair value of the Group's intangible
assets used to assess the goodwill recoverable amount is based on post-tax
cash flows or benchmarked multiples, which are based on market information.
The cash flows have been modelled on a post-tax and post-decommissioning
basis, inflated at 2.5 per cent per annum from 1 January 2029, and discounted
at the Group's post-tax discount rate of between 9.0 per cent and 14.5 per
cent (2024: 8.8 - 14.5 per cent post-tax). Risks specific to assets within the
CGU are reflected within the cash flow forecasts.
Key assumptions used in calculations
Assumptions involved in impairment measurement include estimates of future oil
and gas prices, commercial reserves and resources and production volumes,
discount and foreign exchange rates and the level and timing of expenditures,
all of which are inherently uncertain.
Management's commodity price curve assumptions used for the purposes of
management's impairment assessments are benchmarked against a range of
external forward price data on a regular basis. Individual field price
differentials are then applied.
Commodity and carbon prices
Management's commodity price curve assumptions are benchmarked against a range
of external forward price curves on a regular basis. The first three years
reflect management's best estimate taking into account the market consensus
and forward prices curves transitioning to a long-term price thereafter. The
long-term commodity prices and carbon prices are shown in note 2 of the
financial statements.
Production volumes and oil and gas reserves and resources
Based on life of field production profiles for each asset within the CGUs.
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 and resources using standard recognised evaluation
techniques and they are assessed at least annually by management and by an
independent consultant. Proven and probable reserves are determined using
estimates of oil and gas in place, recovery factors and future commodity
prices.
Costs
Operating expenditure, capital expenditure and decommissioning costs, which
have been inflated at 2.5 per cent per annum from 1 January 2029, are derived
from the Group's business plan.
Discount rates
Discount rates used represent management's estimate of the Group's
country-based weighted average cost of capital (WACC), considering both debt
and equity. The cost of equity is derived from an expected return on
investment by the Group's investors, and the cost of debt is based on its
interest-bearing borrowings. Segment-specific risk is incorporated by applying
a beta factor based on publicly available market data. The discount rate is
based on an assessment of a relevant peer group's post-tax WACC.
Foreign exchange rates
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
The Group has run sensitivities on its long-term commodity price assumptions,
which have been based on long-range forecasts from external financial
analysts, using alternate long-term price assumptions, and discount rates.
These are considered to be reasonably possible changes for the purposes of
sensitivity analysis. As shown in note 2 of the financial statements, the
sensitivity analysis on commodity prices reflecting a 10 per cent reduction in
the long-term oil and gas price deck applied in the impairment test would
result in $567 million goodwill impairment. A 1 per cent increase in the
discount rate would result in an impairment to goodwill of $32 million.
11 Other intangible assets
Oil and gas assets Non-oil and gas assets1 Carbon allowances Total
Note $ million $ million $ million $ million
Cost
As at 1 January 2024 1,016 172 86 1,274
Additions 398 51 36 485
Additions from business combinations and joint arrangements 14 4,407 2 - 4,409
Transfers (to)/from property, plant and equipment 12 (39) 1 - (38)
Increase in decommissioning asset 21 12 - - 12
Exploration write-off (173) - - (173)
Utilised - - (54) (54)
Disposals - (42) - (42)
Currency translation adjustment (76) (3) (3) (82)
As at 31 December 2024 5,545 181 65 5,791
Additions 327 51 45 423
Transfers to property, plant and equipment 12 (17) (8) - (25)
Increase in decommissioning asset 21 (2) - - (2)
Exploration write-off(2) (200) - - (200)
Utilised - - (74) (74)
Reclassification of asset held for sale 18 (113) - - (113)
Currency translation adjustment 32 16 5 53
As at 31 December 2025 5,572 240 41 5,853
Amortisation
As at 1 January 2024 - 102 - 102
Charge for the year - 19 - 19
Disposals - (42) - (42)
Currency translation adjustment - (2) - (2)
As at 31 December 2024 - 77 - 77
Charge for the year - 20 - 20
Currency translation adjustment - 7 - 7
As at 31 December 2025 - 104 - 104
Net book value
As at 31 December 2024 5,545 104 65 5,714
As at 31 December 2025 5,572 136 41 5,749
(1) Non-oil and gas assets relate to Group Information Systems software of
$67 million and carbon capture and storage activities of $69 million.
(2) The exploration write-off of $200 million (2023: $173 million)
includes the write-off of costs associated with licence relinquishments in the
UK ($40 million) and Mexico ($107 million), and project cancellations in
Norway ($22 million).
12 Property, plant and equipment
Oil and gas assets Fixtures and fittings & office equipment Land and buildings(1) Total
Note $ million $ million $ million $ million
Cost
As at 1 January 2024 12,055 42 - 12,097
Additions 1,037 21 1 1,059
Additions from business combinations and joint arrangements 14 9,986 20 40 10,046
Transfers from intangible assets 11 39 - (1) 38
Reclassification of asset held for sale (198) - - (198)
Increase in decommissioning asset 21 760 - - 760
Disposals (1) (24) - (25)
Currency translation adjustment (258) (2) (2) (262)
As at 31 December 2024 as restated 23,420 57 38 23,515
Additions(2) 1,511 11 1 1,523
Transfers from intangible assets 11 17 1 7 25
Reclassification of asset held for sale 18 (274) - - (274)
Decrease in decommissioning asset(3) 21 (193) - - (193)
Disposals (3) (1) - (4)
Currency translation adjustment 702 4 4 710
As at 31 December 2025 25,180 72 50 25,302
Accumulated depreciation
As at 1 January 2024 7,233 28 - 7,261
Charge for the year 1,516 5 1 1,522
Impairment charge 352 - - 352
Reclassification of asset held for sale (124) - - (124)
Disposals (1) (24) - (25)
Currency translation adjustment (49) - - (49)
As at 31 December 2024 8,927 9 1 8,937
Charge for the year 2,758 12 3 2,773
Impairment charge 330 - - 330
Reclassification of asset held for sale 18 (191) - - (191)
Currency translation adjustment 242 1 - 243
As at 31 December 2025 12,066 22 4 12,092
Net book value:
As at 31 December 2024 as restated 14,493 48 37 14,578
As at 31 December 2025 13,114 50 46 13,210
(1) Land and buildings include investment property of $3 million (2024: $3
million).
(2) Included within property, plant and equipment additions of $1,523
million (2023: $1,059 million) are associated cash flows of $1,435 million
(2024: $884 million) and non-cash flow movements of $88 million (2024: $175
million) represented by a $7 million increase in capital accruals (2024: $93
million increase), $45 million of capitalised lease depreciation (2024: $64
million) and $36 million of capitalised interest (2024: $18 million).
(3) A decrease in the decommissioning assets of $193 million (2024:
increase, $760 million) was made during the year as a result of both an update
to the decommissioning estimates and new obligations (note 21).
During the year, the Group recognised a pre-tax impairment charge of $330
million (post-tax $283 million) (2024: $352 million; post-tax $185 million).
This comprised a pre-tax impairment charge representing a write-down of
property, plant and equipment assets of $289 million (2024: $163 million)
across the UK, Mexico and North Africa, mainly driven by reserves reductions
and field performance. The recoverable amount of all the CGUs for which an
impairment charge was recognised is $141 million, $7 million, and $285
million, respectively. A pre-tax impairment charge of $41 million (2024: $174
million) was also recorded in respect of revisions to decommissioning
estimates on late-life assets, and non-producing assets with no remaining net
book value (see note 21).
In 2024, a net pre-tax impairment charge of $352 million was recognised as a
result of impairments on three UK CGUs of $163 million, mainly driven by
further changes to the UK Energy Profits Levy and changes in life of field
outlook, in addition to a fair value impairment on the Vietnam held for sale
asset of $15 million and a pre-tax impairment charge of $174 million in
respect of revisions to decommissioning estimates on the Group's non-producing
assets with no remaining net book value. The recoverable amount of all the
CGUs in the UK for which an impairment charge was recognised was $311 million.
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 with a Level 3
fair value measurement (see note 23). 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 benchmarked consensus and market forward price curves
transitioning to a long-term price from 2028, thereafter inflated at 2.5 per
cent per annum. Harbour utilised real long-term commodity price assumptions
from 2028 for Brent crude $74 per barrel, for UK NBP gas, 89 pence per therm
and for European gas price $11.6 per mmbtu.
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.
Discount rates
The discount rate reflects management's estimate of the Group's country-based
weighted average cost of capital (WACC).
Foreign exchange rates
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 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 2028 specified above would result in a further pre-tax
impairment of $478 million (post-tax: $281 million) and increases to the
long-term oil and gas prices would result in no material change to the
impairment charge.
Considering the discount rates, the Group believes a 1 per cent increase in
the post-tax discount rate is considered to be a reasonable possibility for
the purpose of sensitivity analysis. A 1 per cent increase in the post-tax
discount rate would lead to a further pre-tax impairment of $77 million
post-tax $47 million, (2024: pre-tax $113 million, post-tax $33 million) on
oil and gas assets and $32 million on goodwill (2024: $10 million).
13 Leases
This note provides information for leases where the Group is a lessee.
Balance sheet
Land and buildings Drilling rigs FPSO Offshore facilities Equipment Total
Right-of-use assets Note $ million $ million $ million $ million $ million $ million
Cost
As at 1 January 2024 114 208 625 328 26 1,301
Additions 27 166 - - - 193
Additions from business combinations and joint arrangements(1) 14 55 4 - - 47 106
Cost revisions/remeasurements 6 38 3 32 (11) 68
Reclassification of asset held for sale 2 - - (71) - (2) (73)
Disposals (5) - - - - (5)
Currency translation adjustment (3) (5) - - (1) (9)
As at 31 December 2024 194 411 557 360 59 1,581
Additions(1) 7 - - - 2 9
Cost revisions/remeasurements (4) (2) 54 (2) 5 51
Reclassification of asset held for sale 18 (3) - - - (7) (10)
Disposals (3) (277) - - (25) (305)
Currency translation adjustment 11 28 (4) - 3 38
As at 31 December 2025 202 160 607 358 37 1,364
Accumulated depreciation
As at 1 January 2024 32 159 309 150 19 669
Charge for the year 16 99 83 76 11 285
Impairment charge(2) 20 - - - - 20
Reclassification of asset held for sale 2 - - (40) - - (40)
Disposals (5) - - - - (5)
Currency translation adjustment (1) (3) - - - (4)
As at 31 December 2024 62 255 352 226 30 925
Charge for the year 17 80 63 49 24 233
Reclassification of asset held for sale 18 (2) - - - (5) (7)
Disposals (4) (276) - - (25) (305)
Currency translation adjustment 4 21 (4) - 1 22
As at 31 December 2025 77 80 411 275 25 868
Net book value
As at 31 December 2024 132 156 205 134 29 656
As at 31 December 2025 125 80 196 83 12 496
(1) Additions of $9 million were made to the right-of-use assets during
the year (2024: total additions of $299 million including $106 million related
to business combinations).
(2) The impairment charge of $20 million relates to one of the Group's
office buildings in the UK.
2025 2024
Lease liabilities Note $ million $ million
At 1 January 792 768
Additions 9 193
Additions from business combinations and joint arrangements 14 - 118
Remeasurement 51 67
Finance costs charged to income statement 7 40 53
Finance costs charged to decommissioning provision 21 3 1
Disposal of subsidiaries 8 -
Reclassification of liabilities as held for sale 18 (3) (78)
Lease payments (294) (319)
Currency translation adjustment 28 (11)
At 31 December 634 792
Classified as:
Current 168 241
Non-current 466 551
Total lease liabilities 634 792
The significant portion of the Group's lease liabilities represent lease
arrangements for an FPSO vessel and offshore facilities in the UK Business
Unit.
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 and terminate 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
2025 2024
Note $ million $ million
Depreciation charge of right-of-use assets
Land and buildings - non-oil and gas assets(1) 17 35
Land and buildings - oil and gas assets 1 1
Drilling rigs 80 99
FPSO 62 83
Offshore facilities 49 77
Equipment - non-oil and gas assets - 1
Equipment - oil and gas assets 24 9
Depreciation charge 233 305
Capitalisation of IFRS 16 lease depreciation(2)
Drilling rigs (61) (77)
Equipment (6) (4)
Depreciation charge included within consolidated income statement 166 224
Lease interest 7 40 53
(1) Included within 2024 is an impairment charge of $20 million related to
one of the Group's office buildings in the UK.
(2) Of the $67 million (2024: $81 million) capitalised IFRS 16 lease
depreciation,$45 million (2024: $64 million) has been capitalised within
property, plant and equipment and $22 million (2024: $17 million) within
provisions (note 21).
The total cash outflow for leases in 2025 was $294 million (2024: $319
million).
14 Business combinations
No business combinations occurred during the year ended 31 December 2025.
Business combinations during the year ended 31 December 2024
On 3 September 2024, the Group closed the transaction to acquire substantially
all of Wintershall Dea's upstream assets from BASF and LetterOne, including
those in Norway, Germany, Denmark, Argentina, Mexico, Egypt, Libya and Algeria
as well as Wintershall Dea's carbon capture and storage (CCS) licences in
Europe. The Group acquired the portfolio as it significantly increased
production capacity and provided geographic diversification, adding
high-quality assets with material positions in Norway, Germany, Argentina,
North Africa and Mexico. It also strengthened the Group's financial position,
delivering investment grade credit ratings post-transaction. The Group
acquired control through the payment of cash and issuance of shares to BASF
and LetterOne.
A purchase price allocation (PPA) exercise has been performed under which the
identifiable assets and liabilities of Wintershall Dea were recognised at
fair value. The fair values, and resulting goodwill, were provisional and have
been finalised in 2025. Details of how these fair values were determined are
given in Harbour's 2024 Annual Report & Accounts. After the finalisation
of PPA exercise, the fair value of the net identifiable assets were $3,073
million, an increase of $79 million from the provisional amounts. The increase
was due to additional deferred tax assets recognised of $44 million, following
the finalisation of certain tax filing positions. The facts and circumstances
associated with these filing positions existed as at the date of completion.
This had a corresponding $85 million decrease to goodwill, from $3,845 million
to $3,760 million.
The goodwill arises principally from the requirement to recognise deferred tax
assets and liabilities for the difference between the assigned fair values and
the tax bases of the acquired assets and liabilities assumed in a business
combination. The assessment of fair values of oil and gas assets acquired is
based on cash flows after tax. Nevertheless, in accordance with IAS 12 Income
Taxes, paragraphs 15 and 19, a provision is made for deferred tax
corresponding to the tax rate multiplied by the difference between the
acquisition cost and the tax base. The offsetting entry to this deferred tax
is goodwill. Hence, goodwill arises as a technical effect of deferred tax
(technical goodwill).
There are no specific IFRS guidelines pertaining to the allocation of
technical goodwill and management has therefore applied the general guidelines
for allocating goodwill. Technical goodwill is allocated by segment, in line
with where it arises, and none is expected to be deductible for income tax
purposes.
As reported in 2024, net cash consideration of $1,792 million was paid to the
former owners of Wintershall Dea. This payment is reflected in the
consolidated statement of prior year cash flows. Per the terms of the business
combination agreement, a reduction in cash consideration payable of $10
million was identified in 2024. A further $6 million was identified during
2025, reducing the cash consideration to $1,776 million. This is reflected in
the fair value of consideration below. Both amounts reducing the consideration
payable were received in 2025.
Provisional fair values recognised on acquisition Adjustments during the measurement period Fair values recognised on acquisition
Note $ million $ million $ million
Non-current assets
Other intangible assets 11 4,409 - 4,409
Property, plant and equipment 12 10,011 35 10,046
Right-of-use assets 13 106 - 106
Deferred tax assets 8 147 - 147
Other receivables 16 56 - 56
Other financial assets 23 52 - 52
Current assets
Inventories 15 213 - 213
Trade and other receivables 16 1,305 - 1,305
Other financial assets 23 188 - 188
Cash and cash equivalents 17 748 - 748
Total assets 17,235 35 17,270
Non-current liabilities
Borrowings 22 3,038 - 3,038
Provisions 21, 29 2,616 - 2,616
Deferred tax 8 5,500 (44) 5,456
Trade and other payables 20 25 - 25
Lease liabilities 13 86 - 86
Other financial liabilities 23 99 - 99
Current liabilities
Trade and other payables 20 1,134 - 1,134
Borrowings 22 41 - 41
Lease liabilities 13 32 - 32
Provisions 21,29 324 - 324
Current tax liabilities 8 1,128 - 1,128
Other financial liabilities 23 218 - 218
Total liabilities 14,241 (44) 14,197
Fair value of identifiable net assets acquired 2,994 79 3,073
Subordinated notes measured at fair value(1) 27 (1,548) - (1,548)
Goodwill arising on acquisition 10 3,845 (85) 3,760
Purchase consideration transferred 5,291 (6) 5,285
1. Subordinated notes accounted for within equity, see note 27.
The Wintershall Dea Business Combination Agreement (BCA) entered into with
BASF and LetterOne (together, the Sellers) in connection with Harbour's
acquisition of Wintershall Dea provides for certain customary post-completion
adjustments to be agreed between the parties in respect of the cash
consideration amount paid to the Sellers. In seeking to agree such
adjustments, Harbour and the Sellers have identified differing leakage
amounts. The Sellers have taken the position, on procedural grounds, that the
expert determination mechanism (as set out in the BCA) is not available to the
parties to resolve this discrepancy. Absent a resolution between the parties,
the BCA requires Harbour to refer the matter to arbitration to determine the
availability of the expert determination mechanism under the BCA. If the
Sellers' position is upheld, the relevant adjustment may be nil but, in all
circumstances, Harbour does not expect any adverse financial impact on the
Group.
Contingent consideration
As part of the purchase agreement with the previous owners of the
Wintershall Dea assets, contingent consideration has been agreed, dependent
on the average Brent price during six six-month periods ending 18, 24, 30, 36,
42 and 48 months after completion. If during any of these six-month periods,
the average Brent price is:
▪ greater than or equal to $86 per barrel but less than or equal to
$100 per barrel, a cash payment of $30 million will be made;
▪ greater than $100 per barrel, a cash payment of $50 million will
be made; or
▪ less than $86 per barrel, no cash payment will be made.
As at the acquisition date, the fair value of the contingent consideration was
estimated to be $52 million, determined using an option pricing model. The
contingent consideration is classified as a long-term other financial
liability (see note 23). The fair value of the contingent consideration at
31 December 2025 is $12 million.
15 Inventories
2025 2024
As at 31 December $ million $ million
Hydrocarbons 40 56
Consumables and subsea supplies 358 312
Total inventories 398 368
Inventories of consumables and subsea supplies include a provision of $30
million (2024: $39 million) where it is considered that the net realisable
value is lower than the original cost.
Inventories recognised as an expense during the year ended 31 December 2025
amounted to $23 million (2024: $7 million). These expenses are included within
production costs.
16 Trade and other receivables
2024
2025 As restated
As at 31 December $ million $ million
Trade receivables 776 1,203
Underlift position 122 175
Other debtors 371 255
Prepayments 67 86
Accrued income 608 545
Corporation tax receivable 10 58
Matured financial instruments 40 -
Total trade and other receivables 1,994 2,322
Trade receivables are non-interest bearing and are generally on 20-to-30-day
terms. As at 31 December 2025, there were $261 million of trade receivables
that were past due (2024: $433 million), primarily relating to operations in
the Mexico and North Africa segments.
Accrued income mainly comprise amounts due, but not yet invoiced, for the sale
of oil and gas. Other debtors includes a $100 million (2024: $nil) deposit
associated with the acquisition of LLOG Exploration Company LLC that was
announced in December 2025.
The carrying value of the trade and other receivables are equal to their fair
value as at the balance sheet date.
During the fourth quarter of 2024, the Group issued a credit default swap
(CDS) for a notional amount of $60 million to a third-party financial
institution. The CDS relates to secured borrowing provided by the financial
institution to one of the Group's customers in Mexico. The secured borrowing
was utilised by the customer to pay certain of our outstanding receivables.
The notional amount of the CDS outstanding as of 31 December 2025 was $32
million and will reduce on a monthly basis over its 22-month term. The fair
value of this derivative liability was not material as at 31 December 2025
(2024: $nil).
Other non-current receivables
2025 2024
As at 31 December $ million $ million
Decommissioning funding asset(1) 65 59
Other receivables(2) 51 107
Prepayments 10 10
Total other non-current receivables 126 176
(1) The decommissioning funding asset relates to the decommissioning
liability agreement entered into with E.ON who will reimburse 70 per cent on
the net share of the total decommissioning cost of the two assets in the UK to
a maximum possible funding of £63 million. At 31 December 2025, a long-term
decommissioning funding asset of $65 million (2024: $59 million) has been
recognised.
(2) Other receivables at 31 December 2025 includes $17 million related to
the non-current element of the unamortised portion of issues costs and bank
fees related to the revolving credit facility (see note 22). In 2024, this
included $44 million in cash held in escrow accounts for expected future
decommissioning expenditure in Indonesia.
17 Cash and cash equivalents
2025 2024
As at 31 December $ million $ million
Cash at bank 846 805
Cash and cash equivalents comprise only cash at bank. Cash at bank earns
interest at floating rates based on daily bank deposit rates. The Group only
deposits cash with major banks of high-quality credit standing.
Included in cash and cash equivalents at 31 December 2025 were amounts in
Argentina totalling $42 million (2024: $173 million) subject to currency
controls or other legal restrictions. In addition, the cash and cash
equivalents balance includes an amount of $68 million (2024: $43 million)
primarily relating to collateral associated with letters of credit but also
includes amounts required to cover initial margin on trading exchanges,
counterparty margining on outstanding commodity trades and all other balances
subject to restriction.
18 Disposals
Assets held for sale
In December 2025, the Group entered into a Share and Purchase Agreement (SPA)
to sell its 28.67 per cent operated interest in the producing Natuna Sea Block
A (NSBA) field and the 50 per cent operated interest in the Tuna development
project in Indonesia to Prime Group for a cash consideration of $215 million,
of which, a deposit of $50 million was received in December 2025.
The Natuna Sea Block A sale has an effective date of 1 January 2025 and the
Tuna sale will be effective on completion. The consideration is subject to
customary adjustments. The assets and liabilities of NSBA and the Tuna
development project that are to be disposed are classified as assets held for
sale in the balance sheet as at 31 December 2025, as completion is expected
to be achieved by the second quarter of 2026, subject to the usual regulatory
approvals.
The Group's Indonesian operations are included in the Southeast Asia 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
Group will maintain a presence in Indonesia through other interests held.
The major classes of assets and liabilities of the Group as held for sale as
at 31 December 2025 are as follows:
2025
Note $ million
Assets
Other intangible assets 11 113
Property, plant and equipment 12 83
Right-of-use assets 13 3
Other receivables and working capital 191
Assets held for sale 390
Liabilities
Provisions 21 80
Lease liabilities 13 3
Trade and other payables 109
Deferred tax 8 22
Liabilities directly associated with assets held for sale 214
Net assets directly associated with disposal group 176
Impairment loss recorded -
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 2025, no impairment was recognised as the fair value less cost to
sell, being the expected consideration adjusted for items agreed under the
SPA, was above the carrying amount of the disposal group. The net assets
directly associated with the disposal group held on the consolidated balance
sheet were $176 million as at 31 December 2025.
Disposal of subsidiaries
In December 2024, the Group entered into an exclusivity agreement to sell its
business in Vietnam, which held 53.125 per cent interest in the Chim Sáo and
Dua producing fields, to EnQuest for a consideration of $84 million. The
transaction had an effective date of 1 January 2024. The assets and
liabilities of Vietnam were classified as assets held for sale in the balance
sheet as at 31 December 2024, with a pre-tax impairment recognised of $15
million (post tax: $10 million) 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 $44 million. A further, pre-tax impairment of $35 million
(post-tax: $24 million) was recognised in 2025, reducing the carrying amount
of the disposal group's net assets to $25 million.
The disposal was completed on 9 July 2025. Consideration of $25 million was
received, resulting in no gain or loss on disposal being recognised.
19 Commitments
Capital commitments
As at 31 December 2025, the Group had commitments for future capital
expenditure amounting to $852 million (2024: $1,690 million). Where the
commitment relates to a joint arrangement, the amount represents the Group's
net share of the commitment. Where the Group is not the operator of the joint
arrangement then the amounts are based on the Group's net share of committed
future work programmes.
20 Trade and other payables
2025 2024
As at 31 December $ million $ million
Current
Trade payables 1,114 1,365
Overlift position 99 207
Other payables 190 132
Matured financial instruments - 27
Deferred income(1) 21 24
1,424 1,755
Non-current
Other payables 28 19
Non-current income tax 31 -
Deferred income(1) 9 11
68 30
(1) Deferred income includes $30 million (2024: $19 million) relating to
payments for oil not yet delivered
21 Provisions
Decommissioning provision Pension provision Employee obligation provision Onerous contract provision Other provisions Total
$ million $ million $ million $ million $ million $ million
As at 1 January 2024 4,108 - 27 - - 4,135
Additions 36 - - - - 36
Additions from business combinations and joint arrangements 2,511 40 40 65 284 2,940
Changes in estimates - increase to oil and gas tangible decommissioning assets 550 - - - - 550
Changes in estimates - increase to oil and gas intangible assets 6 - - - - 6
Changes in estimate on oil and gas tangible assets - debit to income statement 174 - - - - 174
Changes in estimate on oil and gas intangible assets - debit to income 6 - - - - 6
statement
Changes in estimate - debit to income statement 3 3 29 - 28 63
Actuarial gains and losses - 7 - - - 7
Amounts used (284) (1) (25) (30) (36) (376)
Reclassification of liabilities directly associated with assets held for sale (90) - - - - (90)
Interest on decommissioning lease (1) - - - - (1)
Depreciation, depletion and amortisation on decommissioning right-of-use (17) - - - - (17)
leased asset
Unwinding of discount 221 - - - - 221
Currency translation adjustment (109) (3) (3) - (18) (133)
As at 31 December 2024 7,114 46 68 35 258 7,521
Additions 15 - 3 - - 18
Changes in estimates - decrease to oil and gas tangible decommissioning assets (240) - - - - (240)
Changes in estimates - decrease to oil and gas intangible assets (1) - - - - (1)
Changes in estimate on oil and gas tangible assets - debit to income statement 32 - - - - 32
Changes in estimate on oil and gas intangible assets - credit to income (1) - - - - (1)
statement
Changes in estimate - debit to income statement - 9 33 (1) 41 82
Actuarial gains and losses - (36) - - - (36)
Amounts used (374) (10) (37) (1) (46) (468)
Reclassification of liabilities directly associated with assets held for sale (57) - (23) - - (80)
Interest on decommissioning lease (3) - - - - (3)
Depreciation, depletion and amortisation on decommissioning right-of-use (22) - - - - (22)
leased asset
Unwinding of discount 284 4 - 1 4 293
Reclassifications - 20 - - (20) -
Currency translation adjustment 274 3 5 - 36 318
As at 31 December 2025 7,021 36 49 34 273 7,413
Non-current liabilities Current liabilities Total
Classified within $ million $ million $ million
At 31 December 2024 7,024 497 7,521
At 31 December 2025 6,967 446 7,413
All of the $15 million decommissioning provision additions relate to oil and
gas tangible assets (2024: $36 million).
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, around half 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 (2024: 2.5 per cent per annum) and discounted at a
risk-free US dollar rate of between 3.1 per cent and 4.8 per cent (2024: 2.2
per cent and 0.1 per cent) reflecting 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.
Pension provision
Please refer to note 29 for pension provisions.
Employee obligation provisions
Employee obligation provisions of $49 million relate to obligations to pay
long-service bonuses, anniversary bonuses, and variable remuneration,
including the associated social security contributions and provisions due to
early retirement as well as phased-in early retirement models. This includes a
termination benefit provision in Indonesia of $nil (2024: $26 million), where
the Group operates a service, severance and compensation pay scheme under a
collective labour agreement with the local workforce.
Onerous contract provision
The onerous contract provision of $34 million (2024: $35 million) relates to
working programmes in Libya due to force majeure conditions in-country.
Other provisions
Other provisions mainly includes a $141 million (2024: $132 million) provision
related to gas migration in Rehden, Germany arising from a commercial
settlement entered into by Wintershall Dea and a third party at the time of
the Wintershall and Dea merger in 2019 and a $60 million (2024: $61 million)
provision related to restructuring programmes within Norway, Germany and
Mexico.
22 Borrowings and facilities
The Group's borrowings are carried at amortised cost:
2025 2024
As at 31 December $ million $ million
Bonds 5,151 5,011
Revolving credit facility - 218
Total borrowings 5,151 5,229
Classified within:
Non-current liabilities 4,915 4,215
Current liabilities 236 1,014
Total borrowings 5,151 5,229
Bonds
2025 2024
Nominal value Fair value Carrying value Nominal value Fair value Carrying value
As at 31 December % Maturity Currency €/$ million $ million $ million €/$ million $ million $ million
Bond ISIN: XS2054209833 0.8 2025 EUR - - - 1,000 1,019 1,014
Bond ISIN: US411618AB75/ USG4289TAA19 5.5 2026 USD 238 237 236 500 499 496
Bond ISIN: XS2054210252 1.3 2028 EUR 1,000 1,118 1,107 1,000 962 954
Bond ISIN: XS2908093805 3.8 2029 EUR 700 830 819 700 729 720
Bond ISIN: XS2055079904 1.8 2031 EUR 1,000 1,042 1,042 1,000 905 901
Bond ISIN: XS2908095172 4.4 2032 EUR 900 1,057 1,053 900 940 926
Bond ISIN: US411618AD32/ USG4289TAB91 6.3 2035 USD 900 911 894 - - -
In October 2021, Harbour Energy plc issued a $500 million bond under Rule
144A and with a tenor of five years to maturity. The coupon was set at 5.5 per
cent and interest is payable semi-annually. $262 million of these bonds were
repaid in March 2025.
Under the terms of the business combination entered into between the company,
BASF and LetterOne in September 2024, three existing Wintershall Dea bonds
were ported to Harbour Energy on completion of the acquisition. The bond
€1,000 million ($1,129 million) due in 2025 was repaid in September 2025. As
at 31 December 2025, the fair value of these bonds, which is determined using
quoted market prices in an active market, amounts to $2,160 million. The
repayment obligation is €2,000 million ($2,349 million, 2024: €3,000
million, $3,106 million).
On 26 September 2024, Harbour announced that Wintershall Dea Finance BV as
issuer, a subsidiary of Harbour, priced an offering on 25 September 2024 of
€700 million in aggregate principal amount of 3.830 per cent senior notes
due 2029 and €900 million in aggregate principal amount of 4.357 per cent
senior notes due 2032. Harbour primarily used the proceeds from this offering
to repay and cancel the $1.5 billion bridge facility utilised for the
Wintershall Dea acquisition which completed on 3 September 2024.
On 24 March 2025, Harbour Energy plc priced an offering of $900 million of
6.327 per cent senior bonds due 2035. Harbour used the proceeds to finance the
purchase of $262 million of the $500 million 5.5 per cent senior bonds due
2026 and for general corporate purposes, including towards repayment of
upcoming debt maturities. $6 million of arrangement fees and related costs
were capitalised as part of this offering.
At the balance sheet date, the outstanding revolving credit facility (RCF)
balance, excluding incremental arrangement fees, related costs and letters of
credit, was $nil (2024: $250 million). As at 31 December 2025, $2,344 million
remained available for drawdown under the RCF (2024: $1,854 million).
The Group has facilities to issue up to $1,750 million of letters of credit
from the RCF (2024: $1,750 million), of which $656 million (2024: $871
million) was in issue as at 31 December 2025, mainly in respect of future
decommissioning liabilities. In addition, the Group had a €35 million
letter of credit facility of which €29 million ($34 million) was drawn at
31 December 2025 (2024: €nil, $nil).
At 31 December 2025, $81 million (2024: $102 million) of arrangement fees and
related costs were amortised during the year and are included within financing
costs. 2024 included $66 million related to the RBL facility and $13 million
related to the bridge facility, upon termination of those facilities.
At 31 December 2025, $215 million of arrangement fees and related costs
remain capitalised (2024: $284 million). Of these arrangement fees $nil (2024:
$32 million) fees relate to the RCF, and $215 million (2024: $252 million)
relate to the bond facilities.
Interest of $46 million on the bonds and RCF facilities (2024: $34 million)
had accrued by the balance sheet date and has been classified within accruals.
The table below details the change in the carrying amount of the Group's
borrowings arising from financing cash flows:
2025 2024
$ million $ million
Total borrowings as at 1 January 5,229 509
Reclassification of capitalised RBL arrangement fees and related costs as - (61)
borrowings
Proceeds from RBL facility - 178
Proceeds from bridge facility - 1,500
Proceeds from Euro bonds - 1,728
Proceeds from USD bonds 900 -
Proceeds from revolving credit facility 440 2,225
Repayment of RBL facility - (178)
Repayment of bridge facility - (1,500)
Repayment of revolving credit facility (690) (1,975)
Repayment of Euro bonds (1,129) -
Repayment of USD bonds (262) -
Repayment of financing arrangement - (17)
Bond debt arising on business combination (net of arrangement fees and related - 3,038
costs)
Financing arrangement interest payable - 1
Arrangement fees and related costs capitalised (6) (58)
Amortisation of arrangement fees and related costs 81 102
Reclassification of RCF arrangement fees and related costs to current and 24 -
non-current assets
Currency translation adjustment on Euro bonds 564 (263)
Total borrowings as at 31 December 5,151 5,229
23 Other financial assets and liabilities
The Group held the following financial instruments at fair value at
31 December 2025. The fair values of all derivative financial instruments are
classified in accordance with the hierarchy described in IFRS 13.
31 December 2025 31 December 2024
Assets Liabilities Assets Liabilities
Current $ million $ million $ million $ million
Derivatives not designated as hedging instruments
Foreign exchange derivatives 22 (1) - (25)
Commodity derivatives - (1) 26 (14)
Fair value of embedded derivatives within gas contract 34 - 5 -
56 (2) 31 (39)
Derivatives designated as hedging instruments
Commodity derivatives 404 (2) 89 (396)
Foreign exchange derivatives - (17) - (27)
404 (19) 89 (423)
Financial instruments at fair value through profit and loss
Short-term investments 25 - 25 -
25 - 25 -
Total current 485 (21) 145 (462)
Non-current
Derivatives not designated as hedging instruments
Commodity derivatives - - 1 (2)
- - 1 (2)
Derivatives designated as hedging instruments
Commodity derivatives 92 - 36 (215)
Interest rate derivatives 9 (5) - -
Foreign exchange derivatives 102 (2) - (146)
203 (7) 36 (361)
Financial instruments at fair value through profit and loss
Contingent consideration(1) - (12) - (52)
Other financial assets - investment 6 - 7 -
6 (12) 7 (52)
Total non-current 209 (19) 44 (415)
Total current and non-current 694 (40) 189 (877)
(1) Contingent consideration relates to the Wintershall Dea transaction
and will be paid between 18-48 months after completion, depending on the
average Brent crude price during six-month periods. This is valued using an
option pricing model.
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 1 Level 2 Level 3 Level 2 Level 3
As at 31 December 2025 $ million $ million $ million $ million $ million
Fair value of embedded derivative within gas contract - 34 - - -
Commodity derivatives - 496 - (3) -
Interest rate derivatives - 9 - (5) -
Foreign exchange derivatives - 124 - (20) -
Short-term investments 25 - - - -
Investments - - 6 - -
Contingent consideration - - - - (12)
Total fair value 25 663 6 (28) (12)
Financial assets Financial liabilities
Level 1 Level 2 Level 3 Level 2 Level 3
As at 31 December 2024 $ million $ million $ million $ million $ million
Fair value of embedded derivative within gas contract - 5 - - -
Commodity derivatives - 152 - (627) -
Foreign exchange derivatives - - - (198) -
Short-term investments 25 - - - -
Investments - - 7 - -
Contingent consideration - - - - (52)
Total fair value 25 157 7 (825) (52)
There were no transfers between fair value levels in 2024 or 2025.
Fair value movements recognised in the income statement on financial
instruments are shown below:
2025 2024
Year ended 31 December $ million $ million
Finance income
Change in fair value of embedded derivative within gas contract 29 -
Commodity derivatives - 5
Short-term investments - 7
Foreign exchange derivatives 41 -
70 12
2025 2024
Year ended 31 December $ million $ million
Finance expenses
Change in fair value of embedded derivative within gas contract - 5
Short-term investments 7 -
Interest rate derivatives 4 -
Foreign exchange derivatives - 30
11 35
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.
2025 2024
Book value Fair value Book value Fair value
As at As at 31 December $ million $ million $ million $ million
USD bonds 1,130 1,148 496 499
EUR bonds 4,021 4,047 4,515 4,555
Total 5,151 5,195 5,011 5,054
The fair value of the bonds 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.
Cash flow hedge
Foreign currency risk
Certain foreign exchange forward contracts are designated as hedging
instruments in cash flow hedges of the variability in cash flows arising from
fixed rate foreign currency denominated debt. The hedged risk is the foreign
currency risk associated with future interest and principal payments on the
debt. These forecast cash flows are considered highly probable, and the hedge
relationship is expected to be highly effective in offsetting changes in cash
flows attributable to movements in foreign exchange rates.
The nominal amount and maturity profile of the foreign exchange forward
contracts are aligned with the timing and amount of the expected foreign
currency cash outflows associated with the debt. The fair values of the
forward contracts fluctuate with changes in spot and forward foreign exchange
rates during the hedge period.
The effective portion of changes in the fair value of these forward contracts
is recognised in other comprehensive income and accumulated in the hedging
reserve. Any ineffective portion is recognised immediately in profit or loss.
Amounts accumulated in the hedging reserve are reclassified to profit or loss
in the periods in which the hedged foreign currency interest and principal
payments affect profit or loss. If the hedging relationship ceases to meet the
qualifying criteria, hedge accounting is discontinued prospectively.
The table below summarises the carrying amount and notional amount of the
foreign exchange forward contracts designated as hedging instruments in cash
flow hedge relationships.
Derivative Carrying amount Currency pair Notional amount Period of hedge Terms
$ million
31 December 2025 Cross-currency interest rate swaps 55 USD:EUR €1,403 million 1-5 years $1.1017-$1.1209:€1
28 €1,150 million >5 years $1.1209-1.1680:€1
31 December 2024 Cross-currency interest rate swaps (27) USD:EUR €363 million <1 year $1.1015:€1
(108) €1,403 million 2-5 years $1.1017-$1.1209:€1
(38) €650 million >5 years $1.1209:€1
Commodity price risk
The Group uses a combination of fixed price physical sales contracts and
cash-settled fixed price commodity swaps and options to manage the price risk
associated with its underlying oil and gas revenues. As at 31 December 2025,
all of the Group's cash-settled fixed price commodity swap derivatives have
been designated as cash flow hedges of highly probable forecast sales of oil
and gas.
The following table indicates the volumes, average hedged price and timings
associated with the Group's commodity hedges:
Position as at 31 December 2025 2026 2027 2028
Oil
Total oil volume hedged (thousand bbls) 16,258 7,574 -
- of which swaps 14,159 1,643 -
- of which collars 2,099 5,931 -
Weighted average fixed price ($/bbl) 72.57 68.08 -
Weighted average collar floor and cap ($/bbl) 60.00 - 75.24 60.00 - 76.99 -
Natural gas
Gas volume hedged (thousand boe) 26,483 12,602 1,804
- of which swaps/fixed price forward sales 19,830 5,506 510
- of which zero cost collars 6,653 7,096 1,294
Weighted average fixed price ($/mscf) 11.67 10.92 10.87
Weighted average collar floor and cap ($/mscf) 9.38 - 17.75 8.15 - 14.63 7.95 - 16.00
Amounts deferred in other comprehensive income will be released to the income
statement as the underlying hedged transactions occur. As at 31 December
2025, net deferred pre-tax gains of $308 million (2024: $307 million) are
expected to be released to the income statement within one year.
Fair value hedge
Foreign currency risk
The Group holds interest rate swap contracts as fair value hedges of the
interest rate risk arising from its fixed rate debt issuances. The interest
rate swaps are used to convert US dollar and Euro denominated fixed rate
borrowings into floating rate debt.
There is an economic relationship between the hedged item and the hedging
instrument as the terms of the interest rate swap match the terms of the fixed
rate loan (i.e., notional amount, maturity, payment and reset dates). The
Group has established a hedge ratio of 1:1 for the hedging relationships as
the underlying risk of the interest rate swap is identical to the hedged risk
component.
The Group has identified the source of ineffectiveness, which is not expected
to be material, as the derivative counterparty's credit risk which is not
offset by the hedged item. This risk is mitigated by entering into derivative
transactions only with high-credit-quality counterparties.
The table below summarises the carrying and notional amounts of derivatives
designated as hedging instruments in fair value hedge relationships:
Derivative Carrying amount Currency Notional amount Period of hedge Terms
$ million
As at 31 December 2025 Interest rate swaps (5) EUR €750 million >5 years 3M EURIBOR + 0.3049
9 USD $900 million >5 years SOFR + 2.4159
As at 31 December 2024 Interest rate swaps - - - - -
Hedge ineffectiveness
The following table summarises the change in the fair value of hedging
instruments and the hedged item used to calculate ineffectiveness in the
period:
2025 2024
Change in fair value of hedging instrument used to calculate ineffectiveness Change in fair value of hedged item used to calculate ineffectiveness Hedge ineffectiveness recognised in income statement Change in fair value of hedging instrument used to calculate ineffectiveness Change in fair value of hedged item used to calculate ineffectiveness Hedge ineffectiveness recognised in income statement
$ million $ million $ million $ million $ million $ million
Cash flow hedges
Commodity price risk
Highly probable forecast sales 1,144 1,150 6 517 517 -
Foreign currency risk
Highly probable forecast interest and principal repayments 235 278 43 121 113 (8)
Fair value hedges
Foreign currency risk
Interest rate swaps 3 3 - - - -
1,382 1,431 49 638 630 (8)
24 Other reserves
Capital redemption reserve Cash flow hedge reserve Costs of hedging reserve Currency translation reserve Total
$ million $ million $ million $ million $ million
As at 1 January 2024 8 3 4 3 18
Amounts recognised in other comprehensive income/(loss) - (561) (7) 130 (438)
Amounts reclassified to the income statement - 23 - - 23
Tax on amounts recognised and reclassified - 350 29 - 379
Other comprehensive (loss)/income - (188) 22 130 (36)
Total comprehensive income - (188) 22 130 (36)
As at 31 December 2024 8 (185) 26 133 (18)
Amounts recognised in other comprehensive income/(loss) - 1,250 140 (182) 1,208
Amounts reclassified to the income statement - (113) (96) - (209)
Tax on amounts recognised and reclassified - (727) (25) - (752)
Other comprehensive income/(loss) - 410 19 (182) 247
Total comprehensive income - 410 19 (182) 247
As at 31 December 2025 8 225 45 (49) 229
25 Financial risk factors and risk management
The Group's principal financial assets and liabilities comprise trade and
other receivables, cash and short-term deposits accounts, trade payables,
interest bearing loans and derivative financial instruments. The main purpose
of these financial instruments is to manage short-term cash flow, price
exposures and raise finance for the Group's expenditure programme.
Risk exposures and responses
The Group manages its exposure to key financial risks in accordance with its
financial risk management policy. The objective of the policy is to support
the delivery of the Group's financial targets while protecting future
financial security. The main risks that could adversely affect the Group's
financial assets, liabilities or future cash flows are market risks comprising
commodity price risk, interest rate risk and foreign currency risk, liquidity
risk, and credit risk. Management reviews and agrees policies for managing
each of these risks which are summarised in this note.
The Group's management oversees the management of financial risks. The Group's
senior management ensures that financial risk-taking activities are governed
by appropriate policies and procedures and that financial risks are
identified, measured and managed in accordance with Group policies and risk
objectives. All derivative activities for risk management purposes are carried
out by specialist teams that have the appropriate skills, experience and
supervision. It is the Group's policy that no trading in derivatives for
speculative purposes shall be undertaken.
Market risk
Market risk is the risk that the fair value of future cash flows of a
financial instrument will fluctuate because of changes in market prices.
Market risk comprises three types of risk: commodity price risk, interest rate
risk and foreign currency risk. Financial instruments mainly affected by
market risk include loans and borrowings, deposits and derivative financial
instruments.
The sensitivity analyses in the following sections relate to the position as
at 31 December 2025 and 31 December 2024.
The sensitivity analyses have been prepared on the basis that the number of
financial instruments is constant. The sensitivity analyses are intended to
illustrate the sensitivity to changes in market variables on the composition
of the Group's financial instruments at the balance sheet date and show the
impact on profit or loss and shareholders' equity, where applicable.
The following assumptions have been made in calculating the sensitivity
analyses:
▪ The sensitivity of the relevant profit before tax item and/or
equity is the effect of the assumed changes in respective market risks for the
full year based on the financial assets and financial liabilities held at the
balance sheet date
▪ The sensitivities indicate the effect of a reasonable increase in
each market variable. Unless otherwise stated, the effect of a corresponding
decrease in these variables is considered approximately equal and opposite
▪ Fair value changes from derivative instruments designated as cash
flow hedges are considered fully effective and recorded in shareholders'
equity, net of tax
▪ Fair value changes from derivatives and other financial
instruments not designated as cash flow hedges are presented as a sensitivity
to profit before tax only and not included in shareholders' equity
Commodity price risk
The Group is exposed to the risk of fluctuations in prevailing market
commodity prices on the mix of oil and gas products. On a rolling basis, the
policy allows the Group to hedge the commodity price exposure associated with
40 to 70 per cent of the next 12 months' production (year 1), between 30 and
60 per cent of year 2 production, from year 3 up to 50 per cent of production
and from year 4 up to 40 per cent of production. The current target is to
hedge circa 50 per cent of year 1 and up to 25 per cent of year 2 commodity
price exposure. The Group manages these risks through the use of fixed price
contracts with customers for physical delivery and derivative financial
instruments including fixed price swaps and options.
Commodity price sensitivity
The following table summarises the impact on the Group's pre-tax profit and
equity from a reasonably foreseeable movement in commodity prices on the fair
value of commodity-based derivative instruments held by the Group at the
balance sheet date.
2025 2024
Effect on profit before tax Effect on equity Effect on profit before tax Effect on equity
As at 31 December Market movement $ million $ million $ million $ million
Brent oil price $10/bbl increase - (74) - (91)
Brent oil price $10/bbl decrease - 70 - 91
NBP gas price £0.1/therm increase - (23) - (36)
NBP gas price £0.1/therm decrease - 23 - 36
TTF $1.5/MMBtu increase - (36) 15 (14)
TTF $1.5/MMBtu decrease - 36 (15) 14
THE $1.5/MMBtu increase - - (15) (46)
THE $1.5/MMBtu decrease - - 15 46
Interest rate risk
Interest rate risk is the risk that the fair value of future cash flows of a
financial instrument will fluctuate because of changes in market interest
rates. While the Group issues debt and hybrid bonds in a variety of currencies
based on market opportunities, it uses derivatives to swap the economic
exposure to a floating rate basis,mainly Euro and US dollar floating, but in
certain defined circumstances maintains a Euro and US dollar fixed rate
exposure for a proportion of the Group's debt.
The Group manages its interest rate risk by having a balanced portfolio of
fixed and variable rate loans and borrowings. The Group's policy is to
maintain fixed-rate exposure within a range of 30 per cent to 70 per cent of
its loan portfolio. To manage this, the Group enters into interest rate swaps,
in which it agrees to exchange, at specified intervals, the difference between
fixed and variable rate interest amounts calculated by reference to an
agreed-upon notional principal amount. At 31 December 2025, after taking into
account the effect of interest rate swaps, approximately 67 per cent of the
Group's borrowings are at a fixed rate of interest (2024: 95 per cent).
At 31 December 2025, there are no floating rate borrowings and fixed rate
borrowings comprise $1.1 billion of bonds which incur interest at between 5.5
per cent and 6.3 per cent per annum and bonds of €3.6 billion which incur
interest at between 1.3 per cent and 4.4 per cent per annum (see note 22).
As at 31 December 2024, floating rate borrowings comprised loans under the
RCF which incurred interest between 5.9 and 6.6 per cent (based on the Secured
Overnight Financing Rate (SOFR) plus a 1.45 per cent margin) and fixed rate
borrowings comprised a $500 million high yield bond which incurs interest at
5.5 per cent per annum and bonds of €4.6 billion which incurred interest at
between 0.8 per cent and 4.4 per cent per annum. Floating rate financial
assets comprise cash and cash equivalents which earn interest at the relevant
market rate. The Group monitors its exposure to fluctuations in interest rates
and uses interest rate derivatives to manage the fixed and floating
composition of its borrowings.
The interest rate and currency profile of the Group's interest-bearing
financial assets and liabilities are shown below:
Cash at bank Fixed rate borrowings Floating rate borrowings Total
As at 31 December 2025 $ million $ million $ million $ million
US dollar 676 (1,130) - (454)
Pound sterling 18 - - 18
Euro 67 (4,021) - (3,954)
Norwegian krone 17 - - 17
Argentinian pesos 54 - - 54
Mexican pesos 1 - - 1
Egyptian pound 13 - - 13
846 (5,151) - (4,305)
Cash at bank Fixed rate borrowings Floating rate borrowings Total
As at December 31, 2024 $ million $ million $ million $ million
US dollar 416 (496) (218) (298)
Pound sterling 75 - - 75
Euro 75 (4,515) - (4,440)
Norwegian krone 36 - - 36
Argentinian pesos 173 - - 173
Mexican pesos 10 - - 10
Egyptian pound 8 - - 8
Other 12 - - 12
805 (5,011) (218) (4,424)
Interest rate sensitivity
The following table demonstrates the indicative pre-tax effect on profit and
equity of applying a reasonably foreseeable increase in interest rates to the
Group's financial assets and liabilities, after the impact of hedge
accounting, at the balance sheet date.
Effect on profit before tax Effect on equity
Market movement $ million $ million
31 December 2025
US dollar interest rates +100 basis points 7 -
31 December 2024
US dollar interest rates +100 basis points 1 -
Foreign currency risk
Foreign currency risk is the risk that the fair value or future cash flows of
a financial instrument will fluctuate because of changes in foreign exchange
rates.
The Group is exposed to foreign currency risk primarily arising from exchange
rate movements in the US dollar against a range of foreign currencies. To
mitigate exposure to movements in exchange rates, wherever possible financial
assets and liabilities are held in currencies that match the functional
currency of the relevant entity. The Group has material subsidiaries with
functional currencies of pound sterling, US dollar, Norwegian krone, Euro and
Mexican pesos. Exposures can also arise from sales or purchases denominated in
currencies other than the functional currency of the relevant entity; such
exposures are monitored and hedged with agreement from the Board.
The Group enters into forward contracts as a means of hedging its exposure to
foreign exchange rate risks. As at 31 December 2025, the Group had:
▪ £170.0 million hedged at a forward average rate of $1.2794:£1
for January 2026
▪ NOK7.2 billion hedged at forward rates of between NOK 10.0536 and
NOK 11.0221:£1 for the period January 2026 to June 2026
As at 31 December 2024, the Group had:
▪ £212 million hedged at forward rates of between $1.2482 and
$1.2774:£1 for the period from January 2025
▪ NOK9.6 billion hedged at forward rates of between NOK 10.9805 and
NOK 11.3963:£1 for the period January 2025 to May 2025
Foreign currency sensitivity
Changes in exchange rates could lead to losses in the value of financial
instruments and adverse changes in future cash flows. Foreign currency risks
from financial instruments arise from the translation of financial
receivables, cash and cash equivalents and financial liabilities into the
functional currency of the Group company at the closing rates. The following
table demonstrates the sensitivity to a reasonably foreseeable change in US
dollars against other currencies with all other variables held constant, on
the Group's profit before tax (due to foreign exchange translation of monetary
assets and liabilities). The impact of translating the net assets of foreign
operations into US dollars is excluded from the sensitivity analysis.
Sensitivity (+10%) Sensitivity (-10%)
$ million $ million
31 December 2025
Pound sterling 146 (146)
Argentinian peso (4) 4
Euro (99) 99
Norwegian krone 246 (246)
Danish krone 4 (4)
Mexican peso 4 (4)
Egyptian pound 14 (14)
31 December 2024
Pound sterling 239 (239)
Argentinian peso (14) (14)
Euro (267) 267
Norwegian krone 81 (81)
Danish krone 7 (7)
Mexican peso (1) 1
Egyptian pound (1) 1
Credit risk
Credit risk is the risk that a counterparty will not meet its obligations
under a financial instrument or customer commercial contract, leading to
financial loss. Credit risks are managed on a Group basis. Group-wide
procedures cover applications for credit approval for both financial and
non-financial counterparties where appropriate. These procedures cover the
granting and renewal of counterparty credit limits, the monitoring of
exposures with respect to these limits and the requirements triggering secured
payment terms.
The solvency of and credit exposures with all counterparties are monitored and
assessed on a timely basis. If customers are independently rated, these
ratings are primarily used for assessment. If there is no independent rating,
the credit risk management function assesses customers' credit quality based
on their financial position or bases the assessment on experience and other
factors. In these cases, individual risk limits are set based on internal
equivalent or by external ratings.
Credit risk in financial instruments arises from cash or cash equivalents and
financial derivatives. The placing of liquid funds is subject to credit
approval. Banks with a credit rating of 'A' are normally used. In some cases,
funds may be held in an overseas business unit with lower credit quality which
may also be impacted by the country sovereign rating. In these situations,
credit approval is given within the country risk environment. Derivative
financial instruments are conducted with credit approved banks and financial
institutions normally rated A- or better and selected credit approved
commercial counterparties. Selectively derivatives may be conducted with local
banks in asset territories below this rating subject to credit approval.
The Group is exposed to credit risk from its operating activities, primarily
for trade receivables, and from its financing activities. The Group seeks to
trade only with recognised, creditworthy third parties. Trade receivables are
monitored on an ongoing basis and credit exposures related to receivables'
mark to market positions are monitored closely for credit decline which may
allow the provision of contractual credit support by a third party.
An indication of the concentration of credit risk on trade receivables is
shown in note 4, whereby the revenue from three customers exceeds 45 per cent
(2024: 54 per cent for one customer) of the Group's consolidated revenue.
With regard to Harbour's own credit risk management, as at 31 December 2025
it has corporate credit ratings, including outlooks, from the following
agencies:
▪ S&P Global at BBB- (Credit Watch Negative)
▪ Fitch at BBB- (Stable)
▪ Moody's at Baa2 (Negative Outlook)
In addition, each of the traded bonds have ratings from the credit ratings
agencies.
Impairment on financial assets
In order to determine the impairment of financial assets, Harbour Energy uses
either a general three-stage approach or the simplified approach, according to
IFRS 9, as applicable. In the case of financial assets for which the
simplified approach does not apply, their assessment takes place as at each
reporting date to determine whether the credit risk on a financial instrument
has increased significantly since its initial recognition.
Trade accounts receivable, other receivables including cash at bank and
deposits are subject to the expected credit loss model. This is generally
based on either externally provided or internal ratings for each debtor which,
in certain cases, are updated based on recently available information.
To measure the expected credit losses on trade accounts receivable,
Harbour Energy applies the simplified approach according to IFRS 9.
Accordingly, the loss allowance is measured at an amount equal to the lifetime
expected credit losses. For trade accounts receivable, the contractual payment
term is usually 30 days. In deviation to this general rule, terms of up to one
year are considered for the calculation of expected credit losses due to
different regional payment practices. The Group uses a provision matrix to
calculate the expected credit losses for trade receivables, which is based on
historical observed default rates, adjusted for forward-looking information.
The expected credit loss on trade receivables at 31 December 2025 was $20
million (2024: $20 million), which represents 2.6 per cent (2024: 1.7 per
cent) of all trade receivables. The charge to the income statement for the
year ended 31 December 2025 was $nil (2024: $19 million).
The loss allowance for other receivables, including cash at bank and deposits,
is measured at an amount equal to the 12-month expected credit loss. If the
term of the financial instrument is shorter than 12 months, the lifetime
expected credit loss is applied. The expected credit loss reversal on other
receivables at 31 December 2025 was $nil (2024: $2 million credit loss). The
credit to the income statement for the year ended 31 December 2025 was $2
million (2024: $2 million charge).
Liquidity risk
Liquidity risk is the risk that the Group will encounter difficulty in meeting
obligations associated with financial liabilities that are settled by
delivering cash or another financial asset. The Group monitors the amount of
borrowings maturing within any specific period and expects to meet its
financing commitments from the operating cash flows of the business and
existing committed lines of credit. The table below summarises the maturity
profile of the Group's financial liabilities based on contractual undiscounted
payments:
Within one year 1 to 2 years 2 to 5 years Over 5 years Total
As at 31 December 2025 $ million $ million $ million $ million $ million
Non-derivative financial liabilities
Bonds 238 - 1,997 3,132 5,367
Trading contracts within the scope of IFRS 9 (settled physically) 72 - - - 72
Trade and other payables 1,304 28 - - 1,332
Lease obligations 192 175 276 70 713
Total non-derivative financial liabilities 1,806 203 2,273 3,202 7,484
Derivative financial liabilities
Net-settled commodity derivatives 303 105 10 - 418
Net-settled foreign exchange derivatives 25 23 29 1 78
Net-settled interest rate derivatives 4 8 10 - 22
2,138 339 2,322 3,203 8,002
Within one year 1 to 2 years 2 to 5 years Over 5 years Total
As at 31 December 2024 $ million $ million $ million $ million $ million
Non-derivative financial liabilities
Bonds 1,173 629 2,049 2,127 5,978
Other loans 251 - - - 251
Trading contracts within the scope of IFRS 9 (settled physically) 54 8 - - 62
Trade and other payables 1,548 30 - - 1,578
Lease obligations 295 206 394 92 987
Total non-derivative financial liabilities 3,321 873 2,443 2,219 8,856
Derivative financial liabilities
Net-settled commodity derivatives 191 92 23 - 306
Net-settled foreign exchange derivatives 48 39 97 29 213
3,560 1,004 2,563 2,248 9,375
The maturity profiles in the above tables reflect only one side of the Group's
liquidity position and will be recorded in the income statement against future
production and revenue which are not recognised on the balance sheet as
assets. Interest-bearing loans and borrowings and trade payables mainly
originate from the financing of assets used in the Group's ongoing operations
such as property, plant and equipment and working capital such as inventories.
These assets are considered part of the Group's overall liquidity risk.
Financial instruments subject to offsetting, enforceable master netting
arrangements
The following table shows the amounts recognised for financial assets and
liabilities which are subject to offsetting arrangements on a gross basis, and
the amounts offset in the balance sheet.
Gross amounts of recognised financial assets/(liabilities) Amounts set off Net amounts presented on the balance sheet
As at 31 December 2025 $ million $ million $ million
Commodity derivative assets 993 (497) 496
Commodity derivative liabilities (500) 497 (3)
As at December 31, 2024
Commodity derivative assets 748 (596) 152
Commodity derivative liabilities (1,223) 596 (627)
Derivatives are offset in the financial statements where the Group has a
legally enforceable right and intention to offset.
26 Share capital
2025
2024
Issued and fully paid Number $ million Number $ million
Ordinary shares of 0.002p each 1,409,983,625 - 1,440,109,512 -
Ordinary non-voting shares of 0.002p each 251,488,211 - 251,488,211 -
Ordinary non-voting deferred shares of 12.4999p each 925,532,809 171 925,532,809 171
171 171
The rights and restrictions attached to the ordinary shares are as follows:
▪ Dividend rights: the rights of the holders of ordinary shares
shall rank pari passu in all respects with each other in relation to dividends
▪ Winding up or reduction of capital: on a return of capital on a
winding up or otherwise (other than on conversion, redemption or purchase of
shares) the rights of the holders of ordinary shares to participate in the
distribution of the assets of the company available for distribution shall
rank pari passu in all respects with each other
▪ Voting rights: the holders of ordinary shares shall be entitled to
receive notice of, attend, vote and speak at any general meeting of
the company
The rights and restrictions to the ordinary non-voting shares are as follows.
Further information on the rights and obligations attached to the non-voting
ordinary shares is set out in the circular and prospectus published by the
company on 12 June 2024.
▪ Dividend rights: each non-voting share will be entitled to receive
an amount equal to a 13 per cent premium to the amount of any distribution per
ordinary share made by the company, whether by cash dividend, dividend in
specie, scrip dividend, capitalisation issue or otherwise
▪ Winding up or reduction of capital: on a winding up or liquidation
of the company, holders of non-voting ordinary shares will be paid in priority
to any other payment to holders of shares in the company
▪ Voting rights: a holder of non-voting ordinary shares shall not be
entitled, in its capacity as a holder of such non-voting shares, to receive
notice of any general meeting of the company nor to attend speak or vote at
any such general meeting, unless the business of the meeting includes the
consideration of a resolution to: (a) wind up the company; or (b) re-register
the company as a private company
▪ Transferability: the non-voting ordinary shares are not admitted
to listing or trading. The non-voting ordinary shares may be transferred to
certain permitted transferees, in certain cases only with the consent of the
company and in accordance with the terms of the non-voting ordinary shares
▪ Conversion rights: a holder of non-voting ordinary shares will be
entitled to convert at least 25,000,000 non-voting shares either:
(i) in conjunction with the sale of non-voting ordinary shares to market sale
places, which upon completion of such sale will be redesignated as ordinary
shares; or (ii) following the satisfaction of the conversion conditions (as
defined in the terms of the non-voting ordinary shares). The non-voting
ordinary shares will be convertible into ordinary shares on a one-for-one
basis except that following any allotment or issue of ordinary shares by way
of capitalisation of profits or reserves or any sub-division or consolidation
of ordinary shares by the company (an adjustment event), the non-voting
ordinary shares will convert into such number of ordinary shares and the
non-voting shareholder will receive the same proportion of voting rights and
entitlement to participate in distributions of the company, as nearly as
practicable, as would have been the case had no adjustment event occurred.
Additionally, subject to certain exceptions, the company will be required to
procure the conversion of the non-voting ordinary shares into ordinary shares
following: (i) the cancellation of the listing of the ordinary shares; and
(ii) the acquisition of more than 50 per cent of the voting rights of the
company by any person (other than the holder of the non-voting shares and any
of such holder's concert parties)
The rights and restrictions attached to the non-voting deferred shares are as
follows:
They will have no voting or dividend rights and, on a return of capital or on
a winding up of the company, will have the right to receive the amount paid up
thereon only after holders of all ordinary shares have received, in aggregate,
any amounts paid up on each ordinary share plus £10 million on each ordinary
share. The non-voting deferred shares will not give the holder the right to
receive notice of, nor attend, speak or vote at, any general meeting of the
company
Issue of ordinary shares
During the year the company issued 13,246 (2024: 24,655) ordinary shares at a
nominal value of 0.002 pence per share in relation to the exercise of SAYE
awards. In 2024 the company issued 921,226,893.00 shares at a nominal value of
0.002 pence per share. This primarily consisted of 669,714,027 ordinary voting
shares issued to BASF and 251,488,211 ordinary non-voting shares issued to
LetterOne on completion of the Wintershall Dea acquisition.
The issue of the ordinary shares to BASF and non-voting shares to LetterOne
resulted in an amount of $3,457 million that was recognised as a merger
reserve. These shares were issued at a share price of £2.86 per share, being
the closing price of ordinary shares on the acquisition date and translated at
the spot pound sterling to US dollar rate on that date of £1:$1.3122.
Purchase and cancellation of own shares
During 2025, the company repurchased 31,203,917 ordinary shares for a total
consideration, including transaction costs, of $90 million (recognised in
retained earnings), as part of the share buyback programme announced on 7
August 2025. Of the shares repurchased 30,139,133 ordinary shares had been
cancelled by year end with the remaining shares cancelled in early January
2026. During 2024, none of the company's ordinary shares were repurchased or
cancelled as previously announced share buybacks had been completed.
2025 2024
Own shares $ million $ million
At 1 January 36 24
Purchase of ESOP trust shares 15 25
Release of shares (17) (13)
At 31 December 34 36
The own shares represent the net cost of shares in Harbour Energy plc
purchased in the market or issued by the company into the Harbour Energy plc
Employee Benefit (ESOP) Trust. This ESOP Trust holds shares to satisfy awards
under the Group's share incentive plans. At 31 December 2025, the number of
ordinary shares of 0.002 pence each held by the trust was 10,903,041 (2024:
9,223,652).
27 Subordinated notes
On 22 February 2024, the bondholders of two series of subordinated resettable
fixed rate notes (subordinated notes) in the aggregate principal amount of
€1,500 million approved a change in guarantor from Wintershall Dea AG to
Harbour Energy plc which became effective upon completing the
Wintershall Dea acquisition transaction; these bonds were issued by Harbour's
acquired subsidiary Wintershall Dea Finance 2 BV. The subordinated notes are
callable three months prior to the first reset date for the NC2026 series and
six months prior to the first reset date for the NC2029 series, there is no
mandatory repayment. €521 million of the NC2026 series was repaid in May
2025.
On 30 April 2025, Harbour announced that Wintershall Dea Finance 2 BV as
issuer, a subsidiary of Harbour, priced an offering on 29 April 2025 of €900
million in aggregate principal amount of subordinated resettable fixed rate
notes at a rate of 6.117 per cent. Harbour primarily used the proceeds from
this offering to repay certain of its NC2026 subordinated notes, repayment of
existing debt and for general corporate purposes. This offering is callable
three months prior to the first reset date, there is no mandatory
repayment.
2025 2024
Nominal value Fair value Carrying value Nominal value Fair value Carrying value
As at 31 December % Reset date Currency € million $ million $ million € million $ million $ million
Bond ISIN: XS2286041517 2.5 2026 EUR 129 150 143 650 718 690
Bond ISIN: XS2286041947 3.0 2029 EUR 850 966 873 850 939 873
Bond ISIN: XS3066591119 / XS3066590574 6.1 2030 EUR 900 1,085 1,009 - - -
Total 1,879 2,201 2,025 1,500 1,657 1,563
2025 2024
$ million $ million
As at 1 January 1,563 -
Fair value on acquisition - 1,548
Fair value adjustment to subordinated notes 27 -
Accrued interest 81 15
Distributions to subordinated notes investors (58) -
Issuance of subordinated notes 970 -
Repayment of subordinated notes (558) -
As at 31 December 2,025 1,563
Under IAS 32, subordinated notes are wholly classified as equity. The issued
subordinated notes are recognised in equity at fair value, based on the market
prices of these instruments as of the acquisition date. Accrued interest
payable to the subordinated notes investors increases equity, whereas the
distribution of interest payments reduces equity. In 2025 a fair value
adjustment was made to the subordinated notes of $27 million (2024: $nil)
relating to the unwinding of a purchase price allocation adjustment made upon
the acquisition of the Wintershall Dea portfolio. The unwinding was triggered
following the repayment of the acquired subordinated notes of $558 million
(2024: $nil).
28 Share-based payments
The company currently operates a Long Term Incentive Plan (LTIP) for certain
employees, a Share Incentive Plan (SIP), a Save As You Earn (SAYE) scheme for
UK-based employees, and a Global Employee Share Purchase Plan currently used
for UK expatriate employees only.
For the year ended 31 December 2025, the total cost recognised by the company
for share-based payment transactions was $44 million (2024: $51 million). A
credit of $44 million (2024: $51 million) has been recorded in retained
earnings for all equity-settled payments of the company.
Like other elements of remuneration, this charge is processed through a cost
allocation process, which uses approved allocation keys to distribute costs to
various entities within the Group. Part of this cost is therefore recharged to
the relevant subsidiary undertakings, part is capitalised as directly
attributable to capital projects and part is charged to the income statement
as operating costs, pre-licence exploration costs or general and
administration costs.
Details of the various share incentive plans currently in operation are set
out below:
2025 Long Term Incentive Plan Rules (2025 LTIP)
At the 2025 AGM, shareholders approved the 2025 LTIP Rules, which have
replaced the previous 2017 LTIP Rules, The 2025 LTIP Rules have broadly the
same terms as the 2017 LTIP, with a number of changes made to align the 2025
Rules with current market practice and ensure that it is an effective tool for
incentivising key employees and directors of the company. The 2025 LTIP Rules
also align with the revised Directors' Remuneration Policy approved at the
2025 AGM.
The following types of award have been granted under the 2025 LTIP:
▪ Performance share awards (PSAs): vesting is subject to a
performance target, normally measured over a three-year period from 1 January
based on total shareholder return (TSR) relative to (i) FTSE 100 index, and
(ii) a bespoke peer group of oil and gas companies. From 2026, the performance
target for PSAs will also include free cash flow delivery target
▪ Conditional share awards (CSAs): vesting is only subject to
continued employment
▪ Deferred bonus share (DBS) awards: certain employees are required
to defer a portion of their annual bonus into shares which vest over a
three-year period subject to continued employment
▪ Restricted share awards (RSAs): vest subject to continued
employment over the vesting period. The rules permit the Committee to set
additional conditions on grant where appropriate. In line with the
Remuneration Policy, RSAs granted to Executive Directors are normally subject
to a performance underpin, requiring the Remuneration Committee to be
satisfied with Company's underlying performance over the vesting period before
release
All LTIP awards are granted in the form of conditional share awards, and no
exercise price payable on the exercise of these awards.
Legacy Awards Under the 2017 LTIP
Awards granted prior to the introduction of the 2025 LTIP continue to be
governed by the terms of the Harbour Energy 2017 Long Term Incentive Plan. No
further awards will be granted under the 2017 LTIP, but outstanding awards
will remain subject to its rules until they vest or lapse.
The following table shows the movement in the number of LTIP awards:
2025 2024
million shares million shares
Outstanding at 1 January 38 34
Granted 30 16
Exercised (10) (3)
Forfeited (3) (9)
Outstanding at 31 December(1) 54 38
(1) This includes nil cash-settled awards at 31 December 2025 (2024: 0.7
million), which are revalued using the year-end share price.
LTIP awards totalling 10.3 million shares were vested during the period (2024:
2.6 million). The weighted average remaining contractual life of the LTIP
awards at 31 December 2025 was 1.4 years (2024: 1.3 years). The weighted
average share price of the LTIPs awards, at exercise date, during the year was
£1.75 (2024: £3.01).
Key assumptions used to calculate the fair value of awards
The fair value of PSAs which are subject to TSR conditions is determined using
a Monte Carlo simulation. The fair value of all other awards is calculated
using the share price at the date of grant, adjusted for dividends not
received during the vesting period.
The following table lists the inputs to the model used in respect of the PSAs
granted during the financial year:
2025 2024
Share price at date of grant £1.71-£2.54 £2.39-£3.22
Dividend yield 0% 0%
Expected term 1.4-3 years 3 years
Risk-free rate 3.7%-4.3% 4.1%-4.3%
Share price volatility of the company 34.9%-43.6% 47.0%-47.5%
The weighted average fair value of the PSA awards granted in 2025 was $1.50
(2024: $1.64).
Expected volatility was determined by reference to both the historical
volatility of the company and the historical volatility of a group of
comparable quoted companies over a period in line with the expected term
assumption.
Global Employee Share Purchase Plan (GESPP)
The Global Employee Share Purchase Plan was approved by shareholders at the
2025 AGM. The following types of award are currently made under the GESPP:
▪ New Joiner Awards: Permanent employees who have completed one year
of service as at 1 April in a given year receive an award of 250 shares
▪ Share purchase plan awards: a structure mirroring the UK SIP
(below) operated currently for UK expatriate staff. Employees are invited to
make contributions to buy partnership shares. If an employee agrees to buy
partnership shares the company currently matches the number of partnership
shares bought with a restricted share award (matching shares), on a one-for
one basis. In 2025, 365 shares were awarded to employees.
UK Share Incentive Plan (SIP)
Under the Share Incentive Plan employees are invited to make contributions to
buy partnership shares. If an employee agrees to buy partnership shares the
company currently matches the number of partnership shares bought with an
award of shares (matching shares), on a one-for-one basis. In 2025, 0.7
million matching shares were awarded to employees (2024: 0.6 million). The SIP
matching shares are valued based on the quoted share price on the grant date.
Save As You Earn (SAYE) scheme
Under the SAYE scheme, UK qualifying employees with one month or more
continuous service can join the scheme. Employees can save up to a maximum of
£500 per month through payroll deductions for a period of three years, after
which time they can acquire shares at the option price, which is set at a
discount of up to 20 per cent to the prevailing market price at the grant
date, determined in accordance with SAYE scheme rules. In 2025, 2.4 million
SAYE options were granted (2024: 1.0 million).
The SAYE options outstanding at 31 December 2025 had exercise prices ranging
from £1.81 to £2.37 (2024: £2.32 to £2.72) and a weighted average
remaining contractual life of 2.6 years (2024: 2.3 years).
29 Group pension schemes
In addition to state pension plans, most employees are granted company pension
benefits from either defined contribution or defined benefit plans. Benefits
generally depend on the length of service, compensation and contributions and
take into consideration the legal framework of labour, tax and social security
laws in the countries where the employing subsidiaries are located.
Defined contribution schemes
The Group primarily operates defined contribution retirement benefit schemes.
The only obligation of the Group with respect to the retirement benefit
schemes is to make specified contributions. Payments to the defined
contribution schemes are charged as an expense as they fall due.
Defined benefit plans
Germany
Employees of Harbour Energy companies in Germany may participate in a capital
market-oriented defined benefit pension scheme. The scheme is open to
employees joining Harbour Energy and is funded by employer and employee
contributions. Typically, Harbour Energy guarantees the sum of applicable
employer and employee contributions as individual minimum benefit. Funds are
invested in plan assets held in a contractual trust arrangement (CTA). The
pension scheme allows for voluntary contributions through deferred
compensation. All other pension plans (including deferred compensation plans)
have been closed to new employees.
Harbour Energy participates in the BASF Group's pension plans for periods of
service already rendered (past service). Some pension benefits by BASF
Pensionskasse VVaG are subject to periodic adjustments that are borne by
Harbour Energy. Additionally, other defined benefit pension schemes are
operated by Harbour Energy. Only employees who participated in these plans
before 2022 are allowed to continue to participate in these plans.
For some pension plans, funds have been transferred to Willis Towers Watson
Treuhand GmbH trust and to Willis Towers Watson Pensionsfonds AG pension fund
to protect against insolvency. Willis Towers Watson Pensionsfonds AG falls
within the scope of the Act on Supervision of Insurance Undertakings and
Oversight by the German Federal Financial Supervisory Authority (BaFin). Under
rare circumstances, the fund may request supplementary contributions from the
employer. Irrespective of the external funding, the liability of the employer
remains in place. The bodies of Willis Towers Watson Treuhand GmbH and Willis
Towers Watson Pensionsfonds AG are responsible for ensuring that the funds
under management are used in compliance with the contract and thus fulfil the
requirements for their recognition as plan assets.
The defined benefit pension plans are subject to longevity risk.
Norway
The Harbour Energy Norge AS defined benefit plans have been closed to new
employees since 1 January 2016. For Norwegian employees whose remaining
length of service until retirement on 1 January 2016 was 15 years or less, a
final salary commitment continues to apply after the closure of the plan. The
plans are partly funded via Nordea Liv AS. Employees who still had a remaining
length of service of more than 15 years on the date of 1 January 2016 and
employees who joined the company after this date are entitled to benefits
under a defined contribution pension plan. Defined contribution plans are
either secured with Nordea Liv AS or unfunded and administered by Storebrand
Pensjonstjenester on behalf of Harbour Energy Norge AS.
Moreover, closed defined benefit plans are in place for former DEA Norge
employees. These are secured with DNB ASA. Employees who still had 15 years or
less until retirement on 1 January 2021 remained in the existing plans. All
others were transferred to existing defined contribution plans.
UK
Harbour Energy operates a final salary defined benefit pension plan in the
UK, primarily inflation-linked annuities based on an employee's length of
service and final salary. The scheme is closed to new members. Further details
of this plan have not been provided as the plan is not material to the
financial position or results of the Group.
Actuarial assumptions
The amount of the provision for defined benefit pension schemes was
determined by actuarial methods based on the following key assumptions.
31 December 2025 December 31, 2024
Key assumptions (%) Germany Norway Germany Norway
Discount rate 4.1 4.1 3.4 3.1
Pension growth 2.3 2.3 2.3 1.8
The assumptions used to determine the present value of the entitlements as at
31 December 2025 are used in the following fiscal year to determine the
expenses for pension plans.
The valuation of the defined benefit obligation is generally performed using
the most recent actuarial mortality tables as at 31 December 2025.
Actuarial mortality tables as at 31 December 2025
Germany Heubeck Richttafeln 2018 G
Norway K2013
Provision for pensions
2025 2024
$ million Defined benefit obligations Plan assets Total Defined benefit obligations Plan assets Total
As at 1 January 468 (422) 46 - - -
Current service costs 9 - 9 3 - 3
Interest expense 17 (13) 4 5 (5) -
Return on plan assets, excluding amounts already recognised in interest income - 3 3 - - -
Actuarial gains/losses
- of which effect of changes in financial assumptions (34) - (34) 10 - 10
- of which effect of experience adjustments (1) - (1) (3) - (3)
Currency effect 59 (57) 2 (31) 28 (3)
Employer contribution to the funded plans - (2) (2) - (1) (1)
Employee contribution to the funded plans - (1) (1) - - -
Benefit payments (34) 24 (10) (9) 9 -
Reclassification from other provisions 20 - 20 - - -
Additions from business combinations and joint arrangements - - - 493 (453) 40
As at 31 December 504 (468) 36 468 (422) 46
The present value of the defined benefit obligations less plan assets
measured at fair value results in the net defined benefit obligation arising
from funded and unfunded plans and is recognised as pension provision on the
balance sheet. Of the present value of defined benefit obligations, $431
million relate to benefit obligations in Germany and $73 million to benefit
obligations in Norway.
German pensions are subject to an obligation to review for adjustments every
three years pursuant to Section 16 of the German Occupational Pensions Act
(BetrAVG). Additionally, some commitments grant annual pension adjustments,
which may exceed the legally mandated adjustment obligation.
The weighted average duration of the pension obligations is 12 years in
Germany (2024: 12 years) and 15 years in Norway (2024: 15 years).
Sensitivity analysis of defined benefit obligations
An increase or decrease in the discount rate and pension growth would have the
following impact on the present value of the defined benefit obligations:
Change in actuarial assumptions
Impact on defined benefit obligations
31 December 2025 31 December 2024
$ million $ million
Discount rate
Increase of 0.5 percentage points (26) (26)
Reduction of 0.5 percentage points 29 29
Pension growth
Increase of 0.5 percentage points 21 19
Reduction of 0.5 percentage points (19) (18)
The sensitivity analyses above have been determined based on a method that
extrapolates the impact on the defined benefit obligation as a result of
reasonable changes in key assumptions occurring at the end of the reporting
period. The sensitivity analyses are based on a change in a significant
assumption, keeping all other assumptions constant. The sensitivity analyses
may not be representative of an actual change in the defined benefit
obligation as it is unlikely that changes in assumptions would occur in
isolation from one another.
Plan assets
The investment policy in Germany is based on detailed asset liability
management (ALM) studies. Portfolios are identified that can achieve the best
target return within a given risk budget. From these efficient portfolios, one
is selected, and the strategic asset allocation is determined. The strategic
asset allocation consists of two main elements. The first one is used to hedge
fluctuations. This involves the use of capital market instruments that hedge
the financial risks arising from the valuation of pension obligations. The
second part of the allocation is used to generate income and for
diversification purposes. The broadly diversified portfolio includes
investments in bonds, equities, real estate and other asset classes. The
assets are continuously monitored and managed from a risk and return
perspective.
Composition of plan assets (fair values)
31 December 2025
Germany Of which has an active market Norway Of which has an active market
$ million $ million
Assets held in insurance company 3 - 23 100 %
Specialised funds 441 100 % - -
444 23
31 December 2024
Germany Of which has an active market Norway Of which has an active market
$ million $ million
Assets held in insurance company 3 - 22 100 %
Specialised funds 397 100 % - -
400 22
30 Notes to the statement of cash flows
Net cash flows from operating activities consist of:
2025 2024
Year ended 31 December $ million $ million
Profit before taxation 2,801 1,219
Adjustments to reconcile profit before tax to net cash flows
Finance cost, excluding foreign exchange 669 602
Finance income, excluding foreign exchange (462) (55)
Depreciation, depletion and amortisation 2,959 1,745
Net impairment of property, plant and equipment 365 352
Impairment of right-of-use asset - 20
Share-based payments 44 51
Decommissioning payments (398) (284)
Fair value movements on derivatives 146 (68)
Changes in provisions (3) (31)
Exploration costs written-off 200 173
Movement in realised cash flow hedges not yet settled 5 (31)
Unrealised foreign exchange loss/(gain) 481 (116)
Working-capital adjustments
(Increase)/decrease in inventories (16) 39
Decrease/(increase) in trade and other receivables 208 (32)
Decrease in trade and other payables (137) (470)
Net tax payments (3,476) (1,499)
Net cash inflow from operating activities 3,386 1,615
Reconciliation of net cash flow to movement in net debt
2025 2024
$ million $ million
Proceeds from drawdown of RBL facility - (178)
Proceeds from Euro bonds - (1,728)
Proceeds from USD bonds (900) -
Proceeds from RCF (440) (2,225)
Proceeds from bridge facility - (1,500)
Repayment of RBL facility - 178
Repayment of bridge facility - 1,500
Repayment of RCF 690 1,975
Repayment of USD bonds 262 -
Repayment of Euro bonds 1,129 -
Repayment of financing arrangement - 17
Bond debt arising on business combination(1) - (3,038)
Financing arrangement interest payable - (1)
Arrangement fees and related costs on bonds capitalised 6 11
Arrangement fees and related costs on RCF capitalised - 34
Arrangement fees and related costs on bridge facility capitalised - 13
Amortisation of arrangement fees and related costs capitalised (81) (102)
Reclassification of RCF arrangement fees and related costs to current and (24) -
non-current assets
Currency translation adjustment on Euro bonds (564) 263
Movement in total borrowings 78 (4,781)
Cash acquired on business combination - 748
Movement in cash and cash equivalents 41 (229)
Decrease/(increase) in net debt in the year 119 (4,262)
Opening net debt (4,424) (162)
Closing net debt (4,305) (4,424)
(1) Net of capitalised arrangement fees and related costs of $nil (2024:
$276 million).
Analysis of net debt
2025 2024
As at 31 December $ million $ million
Cash and cash equivalents 846 805
RCF - (218)
Bonds (5,151) (5,011)
Net debt after unamortised fees (4,305) (4,424)
The carrying values on the balance sheet are stated net of the unamortised
portion of issue costs and bank fees of $215 million of which $nil relates to
the RCF and $215 million is netted against the bonds (2024: $284 million of
which $32 million related to the RCF and $252 million related to the bonds).
31 Related party disclosures
Transactions between the company and its subsidiaries, which are related
parties, have been eliminated on consolidation and are not disclosed in this
note.
BASF and LetterOne have been classified as related parties because they are
substantial shareholders. At 31 December 2025, BASF held 657.7 million (2024:
669.7 million) of voting ordinary shares. LetterOne held 56.9 million (2024:
nil) of voting ordinary shares and 251.5 million (2024: 251.5 million) of
non-voting ordinary shares, respectively. The BASF shareholding represents
46.7 per cent (2024: 46.5 per cent) of voting ordinary shares.
BASF is entitled to dividends as per note 32 which, whilst denominated in
pound sterling will, specifically for BASF, be paid in US dollars.
Compensation of key management personnel of the Group
Remuneration of key management personnel, including directors of the Group, is
shown below:
2025 2024
$ million $ million
Salaries and short-term employee benefits 28 16
Payments made in lieu of pension contributions 1 1
Termination benefits - 1
29 18
32 Distributions made and proposed
A final dividend of 13.19 cents per ordinary share in relation to the year
ended 31 December 2024 was paid on 21 May 2025 pursuant to shareholder
approval received on 8 May 2025.
An interim dividend of 13.19 cents per ordinary share in relation to the half
year ended 30 June 2025 was paid on 24 September 2025.
2025 2024
Year ended 31 December $ million $ million
Cash dividends on ordinary shares declared and paid
Final dividend for 2024 13.19 cents per share (2023: 13 cents per share) 228 100
Interim dividend for 2025 13.19 cents per share (2024: 13 cents per share) 227 99
455 199
Proposed dividends on ordinary shares
Final dividend for 2025: 8.05 cents per share (2024: 13.19 cents per share) 150 228
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.
33 Events after the reporting period
On 11 February 2026, Harbour announced it had completed the acquisition of
LLOG Exploration Company LLC for $3.2 billion, marking the Company's strategic
entry into the US Gulf of America. Harbour financed the acquisition through
$2.7 billion of cash and the issuance of 174,855,744 new Harbour voting
ordinary shares to LLOG Holdings LLC with an agreed value of $0.5 billion. The
cash was funded by a $1.0 billion bridge facility, a $1.0 billion 3-year term
loan and $0.7 billion from existing sources of liquidity.
At the time when the financial statements were authorised for issue, the group
had not yet completed the accounting for the acquisition of LLOG Exploration
Company LLC. The proximity of the completion of the acquisition to the
authorisation of the financial statements has meant the fair values of the
assets and liabilities have not been finalised. It is also not yet possible to
provide detailed information about each class acquired receivables and any
contingent liabilities of the acquired entities.
In 2024, the German non-governmental organisation Deutsche Umwelthilfe (NGO)
filed a lawsuit against the German mining authority (LBEG) challenging the
operating permit of Harbour Energy Germany GmbH (HEGG) for HEGG's Mittelplate
field. HEGG is a joined party in this lawsuit. On 26 February 2026, a court of
first instance (Schleswig-Holsteinisches Verwaltungsgericht) decided that the
operating permit is to be considered invalid during the duration of the main
court proceeding. HEGG filed an appeal on 27 February 2026 with the Appellate
Court (Schleswig-Holsteinisches Oberverwaltungsgericht). This Court confirmed
the receipt of the appeal and stated in writing that its Senate, which will
decide on the appeal, assumes that the operations of the drilling and
production island Mittelplate will continue until a decision has been
determined. Based on this first response by the Appellate Court, and in close
alignment with the mining authority, HEGG is focused on continuing safe
operations.
34 Group information
Subsidiary undertakings of the company which were all wholly owned at
31 December 2025 were:
Name of company Area of operation Country of incorporation Main activity
Chrysaor (U.K.) Alpha Limited(16) UK UK Exploration, production, and development
Chrysaor (U.K.) Beta Limited(16) UK UK Decommissioning activities
Chrysaor (U.K.) Sigma Limited(16) UK UK Exploration, production, and development
Chrysaor (U.K.) Theta Limited(16) UK UK Exploration, production, and development
Chrysaor CNS Limited(16) UK UK Exploration, production, and development
Chrysaor Developments Limited(16) UK UK Decommissioning activities
Chrysaor E&P Limited(16) UK UK Intermediate holding company
Chrysaor Holdings Limited(1,6) UK Cayman Islands Intermediate holding company
Chrysaor Limited(16) UK UK Exploration, production, and development
Chrysaor North Sea Limited(16) UK UK Exploration, production, and development
Chrysaor Petroleum Company U.K. Limited(16) UK UK Exploration, production, and development
Chrysaor Petroleum Limited(16) UK UK Decommissioning activities
Chrysaor Production (U.K.) Limited(16) UK UK Exploration, production, and development
Chrysaor Production Holdings Limited(16) UK UK Intermediate holding company
Chrysaor Resources (Irish Sea) Limited(16) UK UK Exploration, production, and development
DEA Cyrenaica GmbH(7) Libya Germany Exploration, production, and development
DEA E&P GmbH(7) Germany Germany Exploration, production, and development
DEA North Africa/Middle East GmbH(7) North Africa Germany Exploration, production, and development
DEM México Erdoel, S.A.P.I. de C.V.(11) Mexico Mexico Intermediate holding company
E&A Internationale Explorations-und Produktions GmbH(7) Germany Germany Exploration, production, and development
FP Mauritania A BV(13) Mauritania Netherlands Decommissioning activities
FP Mauritania B BV(13) Mauritania Netherlands Decommissioning activities
Harbour Energy Algeria GmbH(7) Algeria Germany Exploration, production, and development
Harbour Energy Bloque 7, S.A. de C.V.(12) Mexico Mexico Exploration, production, and development
Harbour Energy Central Andaman Limited(16) Indonesia UK Exploration, production, and development
Harbour Energy Egypt BV(13) Egypt Netherlands Exploration, production, and development
Harbour Energy Finance Limited(16) UK UK Financing company
Harbour Energy Finance (2) plc(1,16) UK UK Financing company
Harbour Energy Germany GmbH(7) Germany Germany Exploration, production, and development
Harbour Energy International GmbH(7) Germany Germany Exploration, production, and development
Harbour Energy Marketing Limited(16) UK UK Gas trading
Harbour Energy Netherlands Holdings BV(1,13) Netherlands Netherlands Intermediate holding company
Harbour Energy Norge AS(14) Norway Norway Exploration, production, and development
Harbour Energy Services Limited(16) UK UK Service company
Harbour Energy Unidad Zama, S. de R.L. de C.V(11) Mexico Mexico Exploration, production, and development
Harbour Energy US Holdings LLC(19) USA USA Intermediate holding company
Izta Energia, S. de R.L. de C.V.(11) Mexico Mexico Intermediate holding company
Premier Oil Aberdeen Services Limited(16) UK UK Service company
Premier Oil and Gas Services Limited(16) UK UK Service company
Premier Oil Andaman I Limited(16) Indonesia UK Exploration, production, and development
Premier Oil Andaman Limited(16) Indonesia UK Exploration, production, and development
Premier Oil Barakuda Limited(16) Indonesia UK Exploration, production, and development
Premier Oil E&P Holdings Limited(16) UK UK Intermediate holding company
Premier Oil E&P UK EU Limited(16) UK UK Exploration, production, and development
Premier Oil E&P UK Limited(16) UK UK Exploration, production, and development
Premier Oil Exploration (Mauritania) Limited(10) Mauritania Jersey Decommissioning activities
Premier Oil Group Holdings Limited(1,16) UK UK Intermediate holding company
Premier Oil Group Limited(18) UK UK Intermediate holding company
Premier Oil Holdings Limited(16) UK UK Intermediate holding company
Premier Oil Mauritania B Limited(10) Mauritania Jersey Decommissioning activities
Premier Oil Mexico Holdings Limited(16) UK UK Intermediate holding company
Premier Oil Mexico Investments Limited(16) UK UK Intermediate holding company
Premier Oil Mexico Recursos S.A. de C.V.(11) Mexico Mexico Exploration, production, and development
Premier Oil Natuna Sea BV(13) Indonesia Netherlands Exploration, production, and development
Premier Oil Overseas BV(13) Netherlands Netherlands Intermediate holding company
Premier Oil South Andaman Limited(16) Indonesia UK Exploration, production, and development
Premier Oil Tuna BV(13) Indonesia Netherlands Exploration, production, and development
Premier Oil UK Limited(18) UK UK Exploration, production, and development
Servicios Unidad PWTH S. de R.L. de C.V.(11) Mexico Mexico Service company
Sierra Blanca P&D, S. de R.L. de C.V.(11) Mexico Mexico Exploration, production, and development
Sierra Coronado E&P, S. de R.L. de C.V.(11) Mexico Mexico Exploration, production, and development
Sierra Nevada E&P, S. de R.L. de C.V.(11) Mexico Mexico Exploration, production, and development
Sierra Offshore Exploration, S. de R.L. de C.V.(11) Mexico Mexico Exploration, production, and development
Sierra Oil & Gas Holdings, L.P.(5) Mexico Canada Intermediate holding company
Sierra Oil & Gas S.de R.L. de C.V.(11) Mexico Mexico Exploration, production, and development
Sierra Perote E&P, S. de R.L de C.V.(11) Mexico Mexico Exploration, production, and development
SE Argentina Holdings BV(13) Argentina Netherlands Exploration, production, and development
Wintershall Dea Argentina S.A.(2) Argentina Argentina Exploration, production, and development
Wintershall Dea Carbon Management Solutions BV(13) Netherlands Netherlands CCS Activities
Wintershall Dea Finance 2 BV(1,13) Netherlands Netherlands Financing company
Wintershall Dea Finance BV(1,13) Netherlands Netherlands Financing company
Wintershall Dea Global Holding GmbH(7) Germany Germany Exploration, production, and development
Wintershall Dea Global Support BV(13) Netherlands Netherlands Service company
Wintershall Dea Insurance Limited(9) Guernsey Guernsey Risk mitigation services
Wintershall Dea Marketing Services GmbH(7) Germany Germany Distribution, transportation and trade
Wintershall Dea Mexico Holding BV(13) Mexico Netherlands Intermediate holding company
Wintershall DEA Mexico Holdings GP Ltd(4) Mexico Canada Intermediate holding company
Wintershall DEA México, S. de R.L. de C.V.(11) Mexico Mexico Exploration, production, and development
Wintershall Dea Middle East GmbH(7) United Arab Emirates Germany Exploration, production, and development
Wintershall Dea Nederland BV(13) Netherlands Netherlands Servicing and financing company
Wintershall Dea Nile GmbH(7) Egypt Germany Exploration, production, and development
Wintershall Dea South East Asia GmbH(7) Germany Germany Exploration, production, and development
Wintershall Dea Suez GmbH(7) Egypt Germany Exploration, production, and development
Wintershall Dea Technology Ventures GmbH(7) Germany Germany Investment company
Wintershall Dea Vermögensverwaltungs gesellschaft mbH(7) Germany Germany Intermediate holding company
Wintershall Dea WND GmbH(7) Egypt Germany Exploration, production, and development
Wintershall Petroleum (E&P) BV(13) Netherlands Netherlands Exploration, production, and development
Chrysaor (U.K.) Britannia Limited(16) - UK Dormant company
Chrysaor (U.K.) Lambda Limited(15) - Ireland Dormant company
DEA Trinidad & Tobago GmbH(7) - Germany Non-trading
Harbour Energy Argentina Limited(16) - UK Dormant company
Harbour Energy Developments Limited(16) - UK Dormant company
Harbour Energy Production Limited(16) - UK Dormant company
Harbour Energy Secretaries Limited(16) - UK Dormant company
Premier Oil ANS Limited(16) - UK Non-trading
Premier Oil do Brasil Petroleo e Gas Ltda(3) - Brazil Dormant company
Premier Oil ONS Limited(16) - UK Dormant company
Premier Oil Pakistan Offshore BV(13) - Netherlands Dormant company
Premier Oil Vietnam 121 Limited(16) - UK Non-trading
Viking CCS Limited(16) - UK Dormant company
Ebury Gate Limited(8) - Guernsey Voluntary strike-off
EnCore (NNS) Limited(17) - UK Liquidation
EnCore Oil Limited(17) - UK Liquidation
Premier Oil (EnCore Petroleum) Limited(17) - UK Liquidation
Premier Oil Exploration Limited(17) - UK Liquidation
Premier Oil Far East Limited(17) - UK Liquidation
Note:
(1) Held directly by the company. All other companies are held through a
subsidiary undertaking.
(2 ) Registered office - Della Paolera 261, Piso 14 Ciudad de Buenos
Aires, C1001ADA Argentina.
(3) Registered office - Avenida Rio Branco, 123, Grupo 1102, Centro, Rio
de Janeiro, CEP: 20040-905, Brazil.
(4 ) Registered office - 100 King Street West, 3400, Toronto, ON
MX51A4, Canada.
(5 ) Registered office - 44 Chipman Hill, Suite 1000, Saint John, NB
E2L 2A9, Canada.
(6 ) Registered office - Cricket Square, Hutchins Drive, PO Box 2681,
Grand Cayman, KY1-1111, Cayman Islands.
(7 ) Registered office - Hamburg, Germany. Business address: Am
Lohsepark 8, 20457 Hamburg, Germany.
(8) Registered office - Level 5, Mill Court, La Charroterie, St Peter
Port, Guernsey, GY1 1EJ.
(9 ) Registered office - Level 3, Mill Court, La Charroterie, St Peter
Port, Guernsey, GY1 4ET.
(10 ) Registered office - 2(nd) Floor, Lime Grove House, Green Street, St.
Helier, JE2 4UB, Jersey.
(11 ) Registered office - Campos Eliseos 345, floor 12, Polanco V Seccion,
Mexico City, CP 11560, Mexico.
(12 ) Registered office - Presidente Masaryk 111, Piso 1, Polanco V
Seccion, Mexico City, CP 11560, Mexico.
(13 ) Registered office - Lange Kleiweg 56H, 2288 GK, Rijswijk,
Netherlands.
(14 ) Registered office - Jåttåflaten 27, 4020 Stavanger, Norway.
(15 ) Registered office - Riverside One, Sir John Rogerson's Quay, Dublin
2, Ireland.
(16 ) Registered office - 151 Buckingham Palace Road, London, SW1W 9SZ,
United Kingdom.
(17 ) Registered office - C/O Teneo Financial Advisory Limited The Colmore
Building, 20 Colmore Circus Queensway, Birmingham, B4 6AT, United Kingdom.
(18 ) Registered office - 4(th) Floor, Saltire Court, 20 Castle Terrace,
Edinburgh, EH1 2EN, United Kingdom.
(19 ) Registered office - 1209 Orange Street, Wilmington, County of New
Castle, State of Delaware 19801, USA.
( )
Joint operations and investments
Companies that are not wholly owned or controlled by the Group were:
Name of company Effective % ownership Registered office address
Luna Carbon Storage ANS 60 Jåttåflaten 27, 4020, Stavanger, Norway
Havstjerne ANS 60 Jåttåflaten 27, 4020, Stavanger, Norway
Kaupang Karbonlager ANS 60 Jåttåflaten 27, 4020, Stavanger, Norway
Disouq Petroleum Company 50 Plot No. 188 (Dana Gas Building), City Center, 5th Settlement, New Cairo,
Egypt
JV East Damanhur Gas Company 50 Plot No. 188 (Dana Gas Building), City Center, 5th Settlement, New Cairo,
Egypt
Erdgas Münster GmbH 33.7 Johann-Krane-Weg 46, 48149, Münster, Germany
Wellstarter AS 24.4 Stiklestadveien 3, 7041, Trondheim, Norway
AMBARtec AG 24.4 Erna-Berger-Str. 17, 01097, Dresden, Germany
Southern Energy S.A. 15.0 Avenida Leandro N. Alem 1180, Piso 9, Ciudad de Buenos Aires, C1001AAT,
Argentina
Gasoducto Cruz del Sur S.A. 10.0 La Cumparsita 1373 office 402, 11200, Montevideo, Uruguay
HiiROC Limited 9.6 Number 22 Mount Ephraim, Tunbridge Wells, TN4 8AS, United Kingdom
Gas Links S.A. 5.1 Don Bosco 3672 6th floor, C1206ABF, City of Buenos Aires, Argentina
Joint operations that are not managed through separate companies are mainly
located in Norway, the UK, Germany, Mexico and Argentina. The Group applies
the equity method in accounting for its investment in Southern Energy S.A.
Group reserves and resources
Oil and gas 2P reserves and 2C resources(1)
2P reserves (working interest) 2P reserves(5) (entitlement) 2C resources (working interest)
1 January 2025 Inorganic revisions(3) Organic revisions(4) Production 31 December 2025 31 December 2025 31 December 2025
mmboe mmboe mmboe mmboe mmboe mmboe mmboe
Norway Oil and NGLs 172 - - (21) 151 151 150
Gas(2) 285 - (4) (41) 240 240 150
Total 458 - (6) (62) 390 390 300
UK Oil and NGLs 153 - 9 (28) 134 134 63
Gas(2) 142 - 19 (29) 132 132 39
Total 295 - 27 (56) 266 266 102
Argentina Oil and NGLs 20 - 5 (2) 23 23 70
Gas(2) 236 - 32 (25) 243 243 652
Total 256 - 37 (27) 266 266 722
Germany Oil and NGLs 92 - (2) (7) 83 83 13
Gas(2) 34 - - (4) 30 30 23
Total 126 - (3) (10) 113 113 36
North Africa Oil and NGLs 8 - 1 (2) 7 4 4
Gas(2) 44 - - (10) 34 21 33
Total 52 - - (11) 41 25 37
Mexico Oil and NGLs 39 - (2) (3) 34 21 350
Gas(2) 8 - - (1) 6 5 25
Total 47 - (3) (4) 40 26 375
Southeast Asia Oil and NGLs 6 (5) - (1) - - 40
Gas(2) 8 (1) - (2) 5 4 228
Total 14 (6) - (3) 5 4 268
Total Oil and NGLs 491 (5) 8 (63) 431 415 690
Gas(2) 758 (1) 43 (110) 690 675 1,149
Total 1,249 (6) 51 (173) 1,121 1,090 1,839
(1) The volumes in the above table reflect internal estimates. DeGolyer
and MacNaughton (D&M) audited by means of independent assessment a
material proportion, 77 per cent of working interest, of the company's 2P plus
a reasonable proportion, 29 per cent of working interest, of 2C estimates.
D&M's opinion on these estimates is as follows: it is D&M's opinion
that the proved-plus-probable 2P reserves estimates prepared by Harbour on the
properties evaluated by D&M, when compared on the basis of working
interest millions of barrels of oil equivalent, in aggregate, do not differ
materially from those prepared by D&M and it is D&M's opinion that the
2C contingent resources estimates prepared by Harbour on the properties
evaluated by D&M, when compared on the basis of working interest millions
of barrels of oil equivalent, in aggregate, do not differ materially from
those prepared by D&M.
(2) Gas volumes are converted to boe using conversion factors of 5.8 mmbtu/boe
for 2P reserves. 2C gas volumes are converted to mmboe using 5.8 mmbtu/boe,
where gas calorific values can be meaningfully determined, and 5.6 mscf/boe,
where otherwise. Fuel gas is not included in the 2P reserves estimates.
(3) Relates to Harbour's divestment of the Vietnam assets that completed on
9 July 2025.
(4) 2P reserves organic revisions include both additions and changes from
re-estimation. The overall revision predominantly reflects additions made for
forward drilling plans in APE and licence extension in CMA-1 in Argentina, and
life extension on AELE in the UK.
(5) Harbour's net entitlement 2P reserves are lower than its working
interest 2P reserves for some assets in Mexico, North Africa and Southeast
Asia, reflecting the terms of the production sharing contracts (PSC) for the
relevant assets.
Because of rounding, some totals may not agree exactly with the sum of their
component parts.
C0(2) storage 2P capacity and 2C resources(1
)
2P capacity 2C resources
million tonnes million tonnes
31 December 2025 31 December 2025
Norway 0.4 399.2
UK - 381.7
Denmark 1.0 101.7
Total(2) 1.4 882.6
(1) All numbers are representative of Harbour's working interest.
(2 ) The volumes in the above table reflect internal estimates. The
discovered storage capacity (2P) that has been independently assessed through
Competent Persons Reports (CPRs) amounts to c.70 per cent of the total Harbour
storage capacity, and the discovered storage resources (2C) that have been
independently assessed through Competent Persons Reports (CPRs) amounts to
c.62 per cent of the total Harbour storage resources. The independent
assessment of these resources confirms that the internal Harbour estimates are
reasonable.
Alternative performance measures
Alternative performance measures are key performance indicators that
management consider to be important to monitor the operational and financial
performance of the business. They are not specifically defined under United
Kingdom adopted International Accounting Standards or other generally accepted
accounting principles. Harbour uses the following:
a) EBITDAX/Adjusted EBITDAX h) Capital investment
b) Adjusted profit after taxation i) Free cash flow
c) Adjusted earnings per share (EPS) j) GHG intensity
d) Adjusted effective tax rate k) Leverage ratio
e) Operating cost per barrel l) Liquidity
f) DD&A per barrel m) Net cash/debt
g) Total capital expenditure n) Shareholder returns paid
Definitions, and for financial performance measures, a reconciliation from the
alternative performance measure to the nearest IFRS reported number, are
provided below. We have introduced additional alternative performance measures
in our 2025 reporting covering "adjusted EBITDAX", "adjusted profit after
taxation", "adjusted effective tax rate" and "adjusted earnings per share".
These are indicators that management consider better reflect true operational
and financial performance in the period and facilitate a more meaningful
period-on-period comparison.
a) EBITDAX/Adjusted EBITDAX
EBITDAX is defined as operating profit/(loss) for the period adjusted for
depreciation, depletion and amortisation, impairment of property, plant and
equipment, impairment of right-of-use assets, impairment of goodwill,
impairment of operating receivables, exploration and evaluation expenditure,
and new ventures, and exploration costs written-off. Adjusted EBITDAX is
defined as EBITDAX adjusted for gains/losses on disposal of assets, M&A,
restructuring and reorganisation costs, and other gains/losses that, by size
and nature, do not relate to the underlying financial performance of the
Group.
Both are a measure of profitability and provide useful information for
stakeholders because they are tracked by management to evaluate the Group's
operating performance and to make financial, strategic and operating
decisions. Further, they may help stakeholders to better understand and
evaluate, in the same manner as management, the underlying trends in the
Group's operational performance on a comparable basis, period-on-period.
EBITDAX and Adjusted EBITDAX are reconciled to operating profit/(loss) as
follows:
2025 2024
$ million $ million
Operating profit 3,490 1,648
Depreciation, depletion and amortisation 2,959 1,745
Impairment of property, plant and equipment 365 352
Impairment of right-of-use asset - 20
(Reversal)/impairment of receivables (2) 21
Exploration and evaluation expenditure, and new ventures 106 68
Exploration costs written-off 200 173
EBITDAX 7,118 4,027
M&A, restructuring and reorganisation costs 78 119
Adjusted EBITDAX 7,196 4,146
b) Adjusted profit after taxation
Adjusted profit after taxation is defined as profit after tax for the period
adjusted for impairment of property, plant and equipment, impairment of
right-of-use assets, impairment of goodwill, gains/losses on disposal of
assets, M&A, restructuring and reorganisation costs, other gains/losses
that, by size and nature, do not relate to the underlying financial
performance of the Group, and the tax effects of these items and changes in
tax law.
Adjusted profit after taxation, which is adjusted for items which can distort
year-on-year comparisons, is reconciled to profit after taxation as follows:
2025 2024
$ million $ million
Profit before taxation 2,801 1,219
Adjustments:
Impairment of property, plant and equipment 365 352
Impairment of right-of-use assets - 20
M&A, restructuring and reorganisation costs 78 119
Other gains/losses:
Foreign exchange differences on intercompany balances 168 17
Profit before taxation, as adjusted 3,412 1,727
Income tax expense (2,983) (1,312)
Tax effect of adjustment items to profit before taxation (90) (45)
Changes in tax law 264 -
Income tax expense, as adjusted (2,809) (1,357)
Loss after taxation (182) (93)
Adjusted profit after taxation 603 370
c) Adjusted earnings per share
Adjusted earnings per share is calculated as adjusted profit after taxation
attributable to shareholders divided by average number of shares for the year
of 1,710 million (2024: 1,083 million).
2025 2024
$ million $ million
Adjusted profit after taxation 603 370
Profit attributable to subordinated notes investors 81 15
Adjusted net profit attributable to shareholders 522 355
Average number of shares(1) 1,710 1,083
Adjusted earnings per share 31 33
1 Earnings per share for non-voting shares reflects the 13 per cent
incremental premium on this class of shares increasing the number of shared
used in the calculation.
d) Adjusted effective tax rate
Adjusted effective tax rate represents the effective tax rate that results
from adjusting both profit before taxation and income tax expense for the
impact of the adjustments made in arriving at Adjusted profit after taxation
as set out in section b) above. The nearest equivalent measure on an IFRS
basis is the effective tax rate on profit before taxation for the period.
2025 2024
$ million $ million
Profit before taxation 2,801 1,219
Profit before taxation, as adjusted 3,412 1,727
Income tax expense (2,983) (1,312)
Income tax expense, as adjusted (2,809) (1,357)
Reported effective tax rate (%) 106 108
Adjusted effective tax rate (%) 82 79
e) 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.
2025 2024
$ million $ million
Cost of operations
Field operating costs 2,317 1,612
Non-cash depreciation on non-oil and gas assets (52) (25)
Tariff income (48) (32)
Operating costs 2,217 1,555
Operating costs per barrel ($ per barrel) 12.8 16.5
f) DD&A per barrel
Depreciation, depletion and amortisation (DD&A) 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.
2025 2024
$ million $ million
Depreciation, depletion and amortisation (DD&A) before impairment charges
Depreciation of oil and gas properties 2,907 1,704
Depreciation of non-oil and gas properties 32 22
Amortisation of intangible assets 20 19
Total DD&A 2,959 1,745
DD&A before impairment charges ($ per barrel) 16.8 18.5
g) Total capital expenditure
Capital investment 'additions' per notes 11 and 12, decommissioning
expenditure 'amounts used' per note 21 , and energy transition expenditure per
note 5.
h) 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.
i) Free cash flow
Operating cash flow less cash flow from investing activities (exclusive of net
expenditure on business combinations) less interest and lease payments
(principal and interest).
j) GHG intensity
Reported on a gross operated basis and excluding offsets.
k) Leverage ratio
Net debt/last twelve months EBITDAX.
l) 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.
m) Net cash/debt
Total revolving credit facility and bonds (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.
n) 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.
Glossary
2C Contingent resources
2P Proven and probable reserves
AGM Annual general meeting
AHFS Asset held for sale
APS Announced Pledges Scenario (IEA)
bbl Barrel
boe Barrel of oil equivalent
bnboe Billion barrels of oil equivalent
CCS Carbon capture and storage
CGU Cash generating unit
COP Cessation of production
DD&A Depreciation, depletion and amortisation
DRIP Dividend re-investment plan
E&E Exploration and evaluation
EBITDAX Earnings before interest, tax, depreciation, amortisation and exploration
ECL Expected credit losses
EFF Exploration financing facility
EIR Effective interest rate
EPL Energy Profits Levy (UK)
EPS Earnings per share
ESOP Employee stock ownership plan
ETS Emission trading system
FEED Front End Engineering & Design
FLNG Floating liquefied natural gas
FPSO Floating production storage offtake vessel
FVLCD Fair value less cost of disposal
FVOCI Fair value through other comprehensive income
FVTPL Fair value through profit or loss
GAAP Generally accepted accounting principles
GHG Greenhouse gas emissions
IAS International Accounting Standards
IASB International Accounting Standards Board
IFRSs International Financial Reporting Standards
kboepd Thousand of barrels of oil equivalent per day
kgCO2e Kilograms of carbon dioxide equivalent
LC Letter of credit
LTM Last twelve months
LTIP Long Term Incentive Plan
mmbtu Million British thermal unit
mmbbl Million barrels of oil
mmboe Million barrels of oil
equivalent
mt Million tonnes
mtpa Million tonnes per annum
mscf Thousand standard cubic feet
NBP National Balancing Point (UK natural gas prices)
NOK Norwegian krone
NZE Net Zero Emissions Scenario (IEA)
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
SAYE Save As You Earn
SOFR Secured Overnight Financing Rate
SPA Sales and purchase agreement
STEPS IEA Stated Policies (IEA)
TCFD Task Force on Climate-related Financial Disclosures
Therm Unit of UK natural gas
TRIR Total Recordable Injury Rate (The number of fatalities, lost
time injuries, substitute work, and other injuries requiring
treatment by a medical professional per million hours worked)
USD US dollar
WACC Weighted average cost of capital
(#_ftnref1) (1) See Glossary for the definition of non-IFRS measures used in
this section.
2 (#_ftnref2) Includes $46 million initial base dividend paid on non-voting
ordinary shares
3 (#_ftnref3) Includes $23 million initial base dividend paid on non-voting
ordinary shares
4 (#_ftnref4) Excludes one off transactions costs of c.$0.2billion
5 (#_ftnref5) Reflects $65/bbl and $11/mscf for 2026 and $70/bbl and
$10/mscf 2027 onwards escalated at 2.5% in line with costs
6 (#_ftnref6) Based on YE 2025 2P reserves and 2C resources and midpoint of
original FY 2026 Harbour standalone production guidance
7 (#_ftnref7) Includes $46 million initial base dividend paid on non-voting
ordinary shares
8 (#_ftnref8) Excludes one off transaction costs of c.$0.2 billion
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