REG - Harbour Energy PLC - Full year results for the year to 31 December 2024
06/03/2025 07:15
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RNS Number : 6176Z Harbour Energy PLC 06 March 2025
Harbour Energy plc
Full year results for the year to 31 December 2024
6 March 2025
Harbour Energy plc ("Harbour" or the "Company" or the "Group") today announces
its results for the year ended 31 December 2024.
Actuals to 31 December 2024 reflect the completion of the Wintershall Dea
transaction on 3 September 2024 and include approximately four months of
contribution from the acquired portfolio.
Linda Z Cook, Chief Executive Officer, commented:
"2024 was a transformational year with the completion of the Wintershall Dea
transaction, our fourth significant transaction since 2017. As a result, we
achieved a step change in the scale, resilience and longevity of our business
underpinning the potential for material free cash flow generation well into
the next decade. At the same time, we delivered another year of solid
operational and financial performance.
"Looking to 2025, we have had a strong start to the year. We continue to
prioritise safe and efficient operations, mature our significant 2C resource
base and maintain disciplined capital allocation. We remain excited about our
future and look forward to realising the potential of our company for all our
stakeholders."
Operational highlights
§ Completed transformational acquisition of Wintershall Dea portfolio;
integration progressing as planned
§ Production of 258 kboepd (2023: 186 kboepd), a c.40 per cent increase on 2023
§ Unit operating costs of $16.5/boe (2023: $16.4/boe)
§ Total recordable injury rate of 1.0 per million hours worked (2023: 0.7)
§ Successful drilling in the UK, Norway, Argentina and Indonesia; new projects
online in the UK and Argentina
§ Total capital expenditure (including decommissioning) of $1.8 billion (2023:
$1.0 billion)
§ 2P reserves and 2C resources more than tripled to 3.2 bnboe (2023: 880 mmboe),
representing 19 years 2P reserves and 2C resource life
§ Appointment of Chief Operating Officer, Nigel Hearne, in February 2025
Financial highlights(( 1 (#_ftn1) ))
§ Revenue and EBITDAX of $6.2 billion (2023: $3.7 billion) and $4.0 billion
(2023: $2.7 billion), up c.65 per cent and c.50 per cent respectively, versus
2023
§ Profit before tax of $1.2 billion (2023: $0.6 billion) impacted by c.$0.8
billion of period specific predominantly non-cash accounting charges largely
driven by adverse changes to the UK fiscal regime
§ Loss after tax of $93 million (2023: $45 million profit) reflecting a 108%
effective tax rate (2023 restated: 93%)
§ Free cash flow of $0.1 billion (2023: $1.0 billion), including a $0.5 billion
negative working capital movement and before one-off acquisition-related costs
and shareholder distributions.
§ Proposed final dividend of $227.5 million (13.19 cents per ordinary share), in
line with Harbour's increased annual dividend policy of $455 million ($380
million to be paid on the ordinary shares)
§ Net debt before unamortised fees of $4.7 billion (2023: $0.2 billion);
year-end leverage (net debt before unamortised fees/pro forma EBITDAX) of 0.7x
(2023: 0.1x)
§ Corporate and senior unsecured issue credit ratings upgraded to investment
grade Baa2, BBB- and BBB- from Moody's, S&P and Fitch, respectively
2025 outlook
§ Production of 450-475 kboepd, a c.80% increase versus 2024; production of
c.500 kboepd to end February 2025
§ Unit operating cost of c.$14/boe, a c.15% reduction versus 2024
§ Total capital expenditure (including decommissioning spend) of c.$2.4-2.6
billion
§ At Brent oil price of $80/bbl and European and UK natural gas prices of
$13/mscf, estimated free cash flow of c.$1.0 billion
Enquiries
Harbour Energy plc +44 20 3833 2421
Elizabeth Brooks, SVP Investor Relations
Andy Norman, SVP Communications
Brunswick +44 20 7404 5959
Patrick Handley, Will Medvei
Analyst and investor conference call and webcast
Harbour will host a Capital Markets Update today, including a presentation of
its 2024 Full Year Results, at 9.00am (UK time). The link to register for the
webcast, and the presentation, will be available on www.harbourenergy.com
(http://www.harbourenergy.com) . A replay will be available on Harbour's
website shortly after the event.
Details of the Capital Markets Update is outlined in a separate announcement
issued this morning.
Forward looking statements
This statement contains certain forward-looking statements that are subject to
the usual risk factors and uncertainties associated with the oil and gas
exploration and production business. Whilst Harbour believes the expectations
reflected herein to be reasonable in light of the information available to
them at this time, the actual outcome may be materially different owing to
factors beyond Harbour's control or within Harbour's control where, for
example, Harbour decides on a change of plan or strategy. Accordingly, no
reliance may be placed on the figures contained in such forward-looking
statements.
Auditors Report
In accordance with the UK Listing Rule 6.4, the 2024 Auditors Report will be
submitted to the Financial Conduct Authority via the National Storage
Mechanism today and will be available for inspection at:
http://data.fca.org.uk/#/nsm/nationalstoragemechanism
(http://data.fca.org.uk/#/nsm/nationalstoragemechanism)
Performance
Solid operational performance materially enhanced by acquisition
Production averaged 258 kboepd (2023: 186 kboepd) during 2024, split c.40 per
cent liquids, c.45 per cent European natural gas and c.15 per cent other
natural gas.
The c.40 per cent increase in production in 2024 versus 2023 was driven by the
acquisition of the Wintershall Dea assets. The acquisition completed in
September resulting in our expanded and diversified global portfolio achieving
rates of c.500 kboepd in the fourth quarter with material contributions from
Norway, the UK and Argentina.
Production was also supported by new projects and development wells coming
on-stream in the UK, Argentina and Norway in the second half of the year.
Looking to 2025, production on a full year basis is expected to increase to
between 450-475 kboepd reflecting a full 12 months' contribution from the
acquired Wintershall Dea assets and broadly stable production in the UK.
Absolute operating costs for 2024 were $1.6 billion (2023: $1.1 billion)
which, on a unit of production basis, equated to $16.5/boe (2023: $16.4/boe).
This reflects the addition of the lower cost Wintershall Dea portfolio offset
by higher unit operating costs at our UK assets due to lower production
volumes. In 2025, unit operating costs are expected to reduce to c.$14/boe,
benefitting from a full year's contribution from the Wintershall Dea portfolio
and continued management of our UK cost base.
2024 capital expenditure including decommissioning totalled $1.8 billion
(2023: $1.0 billion). The increase on the prior year reflects the additional
capital expenditure associated with the acquired Wintershall Dea assets, and
accelerated capital investment in the UK ahead of anticipated changes to the
UK fiscal regime. 2025 total capital expenditure is expected to be between
$2.4-2.6 billion, reflecting 12 months of the Wintershall Dea portfolio
partially offset by materially reduced capital investment in the UK.
Safe and responsible operations
A priority during the year was the safe transfer of the Wintershall Dea
portfolio which we achieved in September. However, after consistently
improving our safety record, 2024 saw Harbour's total recordable injury rate
increase to 1.0 per million hours worked (2023: 0.7), in part reflecting the
higher TRIR from the newly acquired assets for the last four months of 2024.
Further, we recorded our first-ever Tier 1 process safety event - in Indonesia
- along with three Tier 2 events (2023: zero). All events have been rigorously
investigated, resulting in actions to improve performance with a particular
focus on strengthening our process safety defences in Indonesia and reducing
our TRIR in Germany.
In 2024, our GHG intensity improved to 14 kgCO(2)e/boe, (2023: 22
kgCO(2)e/boe) on a net equity, pro forma basis, reflecting the lower emissions
intensity of the acquired portfolio. We remain on track to halve our gross
operated emissions by 2030.
Maximising the value of our producing assets
The majority of Harbour's capital programme is focused on infrastructure-led
opportunities, converting reserves into production and cash flow. These
opportunities are typically low risk, high return investments concentrated
around our existing production hubs, predominantly in Norway, the UK,
Argentina and Germany.
In the UK, 2024 saw Harbour accelerate drilling around its operated hubs,
taking advantage of tax credits which expired before year end 2024. This
included a return to drilling at the Britannia satellite fields, with the
Callanish F6 infill well on-stream in July while, at AELE, the North West
Seymour well started up production in September. At Jocelyn South, we made a
gas condensate discovery which is being brought on-stream through Harbour's
Judy platform post period end in Q1 2025. In addition, in November, Harbour
delivered first oil from its operated Talbot project, a three well subsea
tie-back to J-Area. The project marked a material milestone for Harbour and
was completed on schedule, within budget and with no recordable injuries.
In Norway, we continued to mature our pipeline of high value, short cycle
developments. This includes the Harbour-operated Maria Phase 2 project, a four
well subsea tieback to existing infrastructure in the Maria field, with
production start-up expected during summer 2025, and Dvalin North, a subsea
tieback to Dvalin. At Dvalin North, fabrication of the subsea infrastructure
is well advanced with development drilling expected to commence in 2026.
Harbour has a proven exploration track record in Norway, helping to support
reserve replacement. This continued in 2024 with six successes from six
exploration and appraisal wells drilled, including the Storjo gas discovery
and successful appraisal drilling at Adriana/Sabina, both potential tie-backs
to the Skarv hub.
In Argentina, Harbour holds a material non-operated position and is one of the
country's largest gas producers. Production at our offshore CMA-1 concession
in the Tierra del Fuego province was supported by the Fenix gas project,
comprising a three well unmanned platform tied into existing CMA-1 facilities,
which came on-stream ahead of schedule in September. Onshore in the Neuquén
province, a multi-pad drilling campaign is ongoing to maintain gas production
from our Aguada Pichana Este concession in the Vaca Muerta unconventional
play. Production is currently constrained by offtake and local market
capacity.
Elsewhere, in Germany, development activities across our three production hubs
continued to support stable production. In Egypt, the two Raven West infill
wells at West Nile Delta were progressed with production start-up from the
first well achieved post period end in February 2025. In Indonesia, Harbour
successfully amended its gas sales agreements with the Singapore buyers of
Natuna Sea Block A gas, increasing the take-or-pay commitment under a tiered
pricing structure, enabling higher production in the second half of 2024.
As at year end 2024, Harbour's proven and probable (2P) reserves on a working
interest basis stood at 1.25 bnboe, more than three times higher than that at
year end 2023 (2023: 0.36 bnboe). This increase was driven by the addition of
1.0 bnboe from the Wintershall Dea transaction, offsetting the impact of
production by more than tenfold.
Strategic investment options
A broad set of major projects with the potential for material reserves
replacement
During 2024, Harbour's 2C resources more than tripled to 1.91 bnboe (2023:
0.52 bnboe), driven by the Wintershall Dea transaction and providing
significant reserve replacement opportunities. Organic additions to our 2C
resources included exploration success in Indonesia, Norway and the UK,
partially offset by revisions to our UK resources, largely the result of
changes to the fiscal environment.
Harbour's 2C resources are split c.40 per cent in high value, near
infrastructure opportunities, mainly in Norway, the UK and Argentina; c.30 per
cent in conventional offshore growth projects in Mexico and Indonesia; with
the remaining c.30 per cent in the globally competitive, unconventional Vaca
Muerta shale play, onshore Argentina.
In Mexico, through the Wintershall Dea transaction, Harbour increased its
interest in the offshore Zama and Kan oil fields and obtained an interest in
the offshore Polok and Najaal discoveries. At Zama, FEED on the approved unit
development plan was substantially completed in 2024. The Zama partners are
now in discussions with Pemex to optimise the development concepts and
accelerate first oil. A positive final investment decision at Zama would
result in significant 2C resource moving into 2P reserves, replacing the
equivalent of over a year's worth of Group production. To the southwest of
Zama, appraisal drilling was successfully completed at the Harbour operated
Kan oil discovery in Block 30. Work to identify the optimum development
concept will be undertaken during 2025.
In August, a multi-well exploration and appraisal campaign across our Andaman
Sea acreage in Indonesia was completed and included material gas discoveries
at Layaran and Tangkulo on Andaman South (Harbour 20 per cent). In addition,
Harbour secured a 60 per cent operated interest in the Central Andaman
licence, which includes an extension of the Layaran discovery. Harbour,
together with its partners, is now evaluating potential development options,
including an accelerated development at Tangkulo.
Argentina represents the largest single component of Harbour's 2C resources,
with 770 mmboe of 2C resources. In Q4, Harbour signed a participation
agreement to acquire a 15 per cent interest in Southern Energy SA which is
looking to develop a 2.45 million tonnes per annum (mtpa) FLNG export project
off the coast of the Rio Negro province. It is anticipated that the upstream
partners in Southern Energy SA will supply the natural gas for the FLNG
project, enabling Harbour's Argentina natural gas to access global LNG export
markets. This marks a significant milestone towards unlocking the accelerated
development of Harbour's huge natural gas resource in Argentina. Harbour also
has an interest in the San Roque licence, which is in the oil window of the
Vaca Muerta play, and discussions with partners for the potential development
of the resource are ongoing.
Building a competitive CCS business
Harbour's pipeline of potential CCS projects was strengthened in 2024 by the
acquisition of the Wintershall Dea portfolio which added CO(2) storage
licences in Denmark, Norway and the UK, where we already have our Viking
project.
At Viking, FEED was substantially completed in 2024 and the Development
Consent Order (DCO) for the proposed new onshore CO(2) pipeline was submitted
to the Secretary of State for approval in December. Clarity on commercial
terms of the project is anticipated following the conclusion of the UK
Government's Critical Spending Review in 2025. Viking's gross storage resource
increased to 417 million tonnes as at 31 December 2024 (2023: 300 million
tonnes), following the addition of the storage resources of two new CCS
licences in Viking's vicinity awarded in 2023.
In December 2024, Harbour together with its partners announced a final
investment decision for the Greensand Future project in Denmark, marking
Harbour's first CCS project to reach FID. Greensand Future is a small, short
cycle project with high returns, driven by the ability to reuse existing
infrastructure and defer decommissioning at the Nini field. The project is
targeting first injection from 2026. Harbour also has an interest in the
cost-advantaged, onshore Greenstore CCS project in Denmark, which is being
progressed through the appraisal work programme.
M&A remains a core part of our strategy
With the addition of the Wintershall Dea portfolio, we have a much wider
organic investment opportunity set with the potential to support material
production well into the next decade. However, M&A remains a core
dimension of our strategy, and we will continue to leverage our capabilities
in this area to strengthen our portfolio.
The opportunity set for M&A remains rich including potential asset sales
from large companies following consolidation, private companies continuing to
look for liquidity, and small companies seeking scale, access to capital and
relevance with investors. We will however continue to be disciplined,
prioritising high-quality assets which lengthen our reserve life, provide a
balance of oil and gas, and increase our operational control while, at the
same time, are supportive to our investment grade credit ratings.
We will also continue to actively manage our portfolio, ensuring our capital
and resources are deployed in line with our strategy. To this end, we agreed
the sale of our Vietnam business, post period end, and exited an uncompetitive
CCS licence in the UK.
Strong financial position
The acquisition of the Wintershall Dea assets is expected to deliver a step up
in the scale and sustainability of our free cash flow, underpinned by our
improved reserve life and expanded resource base. For 2024, Harbour delivered
free cash flow of $0.1 billion for the year, before shareholder distributions
and one-off acquisition-related costs. Cash flow is impacted by a number of
period specific items including a material negative working capital movement,
driven by the adjustment of our working capital cycle to the increased size of
our business, significant planned shutdowns in Norway in September post
completion, and payment of previously deferred UK taxes on 2023 earnings.
The Board has declared a final dividend of $227.5 million in respect of the
2024 financial year to be paid in May 2025 equating to 13.19 cents per
ordinary share, subject to shareholder approval. This is in line with the
Board's commitment at the time of acquisition announcement to increase the
annual dividend to $455 million and signals the Board's ongoing confidence in
the scale and longevity of our free cash flow generation.
Harbour's debt structure was transformed over 2024 with the reserves-based
debt facility replaced with unsecured, lower cost and more flexible bank
facilities and bonds. Harbour's corporate and senior bond credit ratings were
upgraded to investment grade from all leading credit rating agencies and in
October, Harbour issued €1.6 billion of Euro denominated, investment grade
bonds. At year-end 2024, net debt (before unamortised fees) stood at $4.7
billion with leverage, on a pro forma basis, of 0.7x.
Since becoming a public company in 2021, our sustained operational and
financial delivery along with our disciplined approach to capital allocation
enabled us to repay c.$2.9 billion of debt and return c.$1.2 billion to
shareholders while retaining the flexibility to complete a transformational
acquisition.
2025 Annual General Meeting (AGM) and Board update
Harbour Energy's Annual General Meeting will be held on Thursday 8 May 2025.
The Notice of Meeting will be published alongside the full annual report and
accounts in March 2025. Andy Hopwood will be standing down from the Board at
the close of the AGM and will not therefore be put forward for re-election by
shareholders.
Harbour plans to seek authority from its shareholders at its upcoming AGM to
conduct an off-market buyback of shares held by BASF, its largest shareholder.
While BASF remain a significant shareholder, it is Harbour's intention to seek
such authority each year from its shareholders to retain maximum flexibility.
The Company is not obliged to exercise the authority or proceed with an
off-market buyback once the authority has been approved.
Outlook(1)
Looking to 2025, Harbour will benefit from a full year's contribution from the
Wintershall Dea assets resulting in another step up in production, a reduction
in unit operating costs and increased free cash flow generation. In these
times of continued geopolitical uncertainty and commodity price volatility,
the resilience our more diverse and lower cost portfolio provides is ever more
important. It is also why we aim for a balance of oil and gas and employ a
disciplined and consistent approach to hedging. At Brent oil prices of $80/bbl
and UK and European natural gas prices of $13/mscf, we expect to generate free
cash flow of c. $1.0 billion(1) in 2025. With a $5/bbl change in Brent oil
prices or $1/mscf change in European natural gas prices impacting free cash
flow by c.$115 million, we still expect to generate material free cash flow at
current prices.
As we look to the future, we will continue to prioritise safe and efficient
operations as we complete the integration of our new Business Units, mature
our significant 2C resource base and maintain disciplined capital allocation.
Our high-quality portfolio with significant optionality, financial strength
and strong management team mean we are well-positioned for continued execution
of our strategy and delivery of competitive shareholder returns.
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(1) 2025 guidance/outlook assumes a US dollar to GBP sterling exchange rate of
$1.25/£, US dollar to Euro exchange rate of $1.1/€ and a Norwegian NOK to
US dollar exchange rate of NOK11/$. Free cash flow sensitivity assumes
mid-point of production and capex guidance. A 1:1 conversion rate for $/mmbtu
to $/mscf has been assumed.
Financial Review
Summary of financial results
Units 2024 2023
As restated(1)
Production and post-hedging realised prices
Production kboepd 258 186
Crude oil $/boe 82 78
European gas(2) $/mscf 11 7
Other gas(2) $/mscf 4 13
Income statement
Revenue and other income $ million 6,226 3,751
EBITDAX(3) $ million 4,006 2,675
Profit before taxation $ million 1,219 616
(Loss)/profit after taxation $ million (93) 45
Basic (loss)/earnings per ordinary voting share cents/share (10) 6
Other financial key figures
Total capital expenditure(3) $ million 1,828 969
Operating cash flow $ million 1,615 2,150
Free cash flow(3) $ million (118) 1,048
Shareholder returns paid(3) $ million 199 439
Net debt(3) $ million 4,424 207
Leverage ratio(3) times 1.1 0.1
1 2023 results throughout this financial review have been restated with
respect to the Vietnam asset held for sale classification given the previous
sales process did not conclude.
2 2024 reflects the impact of the Wintershall Dea portfolio. Europe includes
UK, Norway and Germany with 2023 comparative restated to $/mscf. For Other
gas, the 2023 comparative relates solely to the Indonesia business.
3 See Glossary for the definition of non-IFRS measures. Reconciliations
between IFRS and non-IFRS measures are provided within this financial review.
Income Statement
2024 2023
$ million $ million
As restated
Revenue and other income 6,226 3,751
Cost of operations (3,613) (2,376)
EBITDAX(1) 4,006 2,675
Operating profit 1,648 932
Profit before tax 1,219 616
Taxation (1,312) (571)
(Loss)/profit after tax (93) 45
Cents/share Cents/share
As restated
Basic (loss)/earnings per ordinary voting share (10) 6
1 Non-IFRS measure - see Glossary for the definition.
Revenue and other income
Total revenue and other income increased to $6,226 million (2023: $3,751
million). This was driven by higher production, primarily due to the
Wintershall Dea transaction with the newly acquired portfolio contributing
$2,021 million in the four months post completion, and increased commodity
prices, especially European natural gas.
2024 2023
$ million $ million
Revenue and other income 6,226 3,751
Crude oil 2,878 2,086
Gas 2,936 1,415
Condensate 283 179
Tariff income and other revenue 61 35
Other income 68 36
Revenue earned from hydrocarbon production activities increased to $6,097
million (2023: $3,680 million) after realised hedging losses of $18 million
(2023: $911 million). This increase was mainly driven by higher production due
to the acquired portfolio and higher post-hedging realised European natural
gas prices. Of Harbour's total annual production of 258 kboepd and revenue
of $6,226 million, 98 kboepd and $2,021 million revenue was delivered by the
acquired portfolio in the four months post completion.
Crude oil sales increased to $2,878 million (2023: $2,086 million) after
realised hedging gains of $32 million (2023: losses of $93 million). This was
driven by higher production volumes from the acquired portfolio as well as a
higher realised post-hedging oil price of $82/bbl (2023: $78/bbl). Of
Harbour's total annual crude oil production of 90 kboepd and total $2,878
million post-hedging crude oil revenue, 27 kboepd and $590 million was
delivered by the acquired portfolio in the four months post completion.
Gas revenue was $2,936 million (2023: $1,415 million), split between European
gas revenue of $2,644 million (2023: $1,284 million) including realised
hedging losses of $50 million (2023: $818 million) and other gas revenue of
$292 million (2023: $131 million). The increase in both categories is
primarily due to the acquired portfolio. Of Harbour's total annual gas
production of 149 kboepd, 67 kboepd was delivered by the acquired portfolio in
the four months post completion with associated European and Other
post-hedging gas revenue of $1,121 million and $174 million respectively. The
realised post-hedging price for our European and other gas was $11/mscf (2023:
$7/mscf) and $4/mscf (2023: $13/mscf), respectively. The fall in the realised
other gas price reflects the lower price environments of the acquired
portfolio.
Condensate revenue was $283 million (2023: $179 million) and tariff income $61
million (2023: $35 million). Other income amounted to $68 million (2023: $36
million) which includes partner recovery on lease obligations and government
subsidies in Argentina.
Cost of operations
Cost of operations increased to $3,613 million (2023: $2,376 million, as
restated) driven primarily by costs associated with the acquired assets and a
negative movement in hydrocarbon inventories and over/underlift. Cost of
operations includes operating costs of $1,612 million (2023: $1,171 million)
and depreciation, depletion and amortisation expense of $1,704 million (2023:
$1,414 million, as restated) as discussed below along with over/underlift
movements and other items for an expense of $297 million (2023: $209 million,
credit).
2024 2023
$ million $ million
As restated
Operating costs
Field operating costs 1,612 1,171
Non-cash depreciation on non-oil and gas assets (25) (26)
Tariff income (32) (30)
Total operating costs 1,555 1,115
Operating costs per barrel ($ per barrel)(1) 16.5 16.4
Movement in over/underlift balances and hydrocarbon inventories 201 (225)
Depreciation, depletion and amortisation (DD&A)
before impairment charges
Depreciation of oil and gas properties 1,704 1,414
Depreciation of non-oil and gas properties 22 12
Amortisation of intangible assets 19 23
Total DD&A 1,745 1,449
DD&A before impairment charges ($ per barrel)(1) 18.5 21.3
1 Non-IFRS measure - see Glossary for the definition.
Total operating costs increased to $1,555 million (2023: $1,115 million)
driven by the four-month contribution of the acquired portfolio. However, they
were materially unchanged on a unit of production basis at $16.5/boe (2023:
$16.4/boe).
Depreciation, depletion and amortisation unit expense, which reflects the
capitalised costs of producing assets divided by produced volumes, decreased
to $18.5/boe (2023: $21.3/boe, as restated).
General and administrative expenses
General and administrative expenses amounted to $352 million (2023: $149
million). The increase was driven by the enlarged group, including expansion
of our corporate centre, and additional and one-off M&A transaction costs
of $119 million (2023: $33 million) associated with the Wintershall Dea
acquisition.
EBITDAX(1)
EBITDAX(1) was $4,006 million (2023: $2,675 million, as restated), with the
increase driven by the four-month contribution of the acquired assets.
2024 2023
$ million $ million
As restated
Operating profit 1,648 932
Depreciation, depletion and amortisation 1,745 1,449
Impairment of property, plant and equipment 352 176
Impairment of right-of-use asset 20 -
Impairment of goodwill - 25
Exploration and evaluation expenditure, and new ventures 68 36
Exploration costs written-off 173 57
EBITDAX(1) 4,006 2,675
1 Non-IFRS measure - see Glossary for the definition.
The Group has recognised a net pre-tax impairment charge on property, plant
and equipment of $352 million (2023: $176 million, as restated). Of this, $174
million was in respect of revisions to decommissioning estimates on mainly
non-producing assets with no remaining book value. The remainder largely
relates to impairments on three fields in the UK due to impacts from further
changes to the UK Energy Profits Levy (EPL) and changes in life of field
outlook.
During the year, the Group expensed $241 million (2023: $93 million) of
exploration and appraisal activities. This covers exploration write-off
expense of $173 million (2023: $57 million) including write-off of costs
associated with projects in the UK ($79 million) and licence relinquishments
in Norway ($64 million), and $40 million (2023: $29 million) costs primarily
associated with carbon capture and storage activities.
Net financing costs
Finance income amounted to $173 million (2023: $104 million). The increase
compared to 2023 is primarily due to unrealised foreign exchange gains of $118
million during the year which predominantly arose on the revaluation of the
Group's tax liabilities due to the strengthening of the US dollar in the year.
Finance expenses amounted to $602 million (2023: $420 million). This included:
§ interest expense incurred of $78 million (2023: $42 million) related to debt
facilities and bonds;
§ bank and financing fees of $139 million (2023: $100 million);
§ unwinding of the discount on decommissioning provisions of $221 million (2023:
$156 million) which
increased due to the acquired assets and increased estimates in the UK;
§ $53 million (2023: $51 million) of lease interest;
§ $43 million related to changes in the fair value of foreign exchange
derivatives (2023: $nil); and
§ realised losses on foreign exchange forward contracts $71 million (2023: $9
million, gain).
Earnings and taxation
Loss after tax amounted to $93 million (2023: $45 million profit, as
restated). This resulted in a loss per ordinary voting share of 10 cents
(2023: 6 cents, earnings, as restated) after taking into account the weighted
average number of ordinary voting shares in issue of 990 million (2023: 804
million) following the issue of shares to BASF and LetterOne as part of the
acquisition. After taking into consideration $15 million (2023: $nil)
attributable to subordinated notes investors, loss after tax attributable to
equity owners of the company amounted to $108 million (2023: $45 million gain
attributable to equity owners of the company).
Harbour's tax expense increased to $1,312 million in 2024 (2023: $571 million,
as restated), primarily driven by higher pre-tax profits resulting from the
additional earnings contributed by the acquisition and specific UK adjustments
due to the EPL. The tax expense comprises a current tax expense of $1,415
million (2023: $677 million) and a deferred tax credit of $103 million (2023:
$106 million, credit).
The effective tax rate of 108 per cent (2023: 93 per cent, as restated) is
materially higher than the statutory tax rate of 78 per cent (2023: 75 per
cent). This is primarily due to several UK-specific exceptional items. Key
contributors include the increase in UK decommissioning obligations in the
period (15 per cent), the impairment of tangible and intangible assets in the
UK (4 per cent) and the increase in the EPL rate from 35 per cent to 38 per
cent (6 per cent).
Shareholder distributions
A final dividend with respect to 2023 of 13.00 cents per ordinary share was
proposed on 7 March 2024 and approved by shareholders at the AGM on 9 May
2024. The dividend was paid on 22 May 2024 to all shareholders on the register
as at 12 April 2024, totaling $100 million. An interim dividend was announced
on 8 August 2024 at 13 cents per share and was paid on 25 September 2024 at a
value of $99 million 2 (#_ftn2) .
The Board is proposing a final dividend with respect to 2024 of 13.19 cents
per voting ordinary share to be paid in pound sterling at the spot rate
prevailing on the record date. This dividend is subject to shareholder
approval at the AGM, to be held on 8 May 2025. If approved, the dividend will
be paid on 21 May 2025 to shareholders as of 11 April 2025. The ex-dividend
date is 10 April 2025. A dividend reinvestment plan (DRIP) is available to
shareholders who would prefer to invest their dividends in the shares of the
company. The last date to elect for the DRIP in respect of this dividend is 29
April 2025.
A DRIP is provided by Equiniti Financial Services Limited. The DRIP enables
the Company's shareholders to elect to have their cash dividend payments used
to purchase the Company's shares. More information can be found
at www.shareview.co.uk/info/drip (http://www.shareview.co.uk/info/drip) .
Statement of Financial Position
2024 2023
$ million $ million
As restated
Assets
Goodwill 5,147 1,302
Non-current assets, excluding goodwill and deferred taxes 21,133 7,061
Deferred tax assets 130 7
Current assets 3,634 1,546
Assets held for sale 277 -
Total assets 30,321 9,916
Liabilities and Equity
Borrowings net of transaction fees 5,229 509
Provisions 7,521 4,135
Deferred tax liabilities 6,221 1,297
Lease creditor 792 768
Derivative liabilities 826 284
Other liabilities 3,248 1,370
Liabilities directly associated with assets held for sale 233 -
Total liabilities 24,070 8,363
Equity 6,251 1,553
Total liabilities and equity 30,321 9,916
Net debt 4,424 207
Assets
The increase in total assets of $20,405 million to $30,321 million (2023:
$9,916 million, as restated) is mainly as a result of the acquisition,
primarily property, plant and equipment of $10,011 million, exploration,
evaluation and other intangible assets of $4,409 million and goodwill arising
from purchase price allocation exercise of $3,845 million. Total assets
include assets held for sale in respect of the Vietnam disposal of $277
million.
The goodwill of $3,845 million arises principally from the requirement to
recognise undiscounted deferred tax liabilities for the difference between the
fair value and the tax base of the acquired assets and liabilities assumed in
the business combination. This goodwill will ultimately be charged to the
income statement over time as an impairment charge, primarily as the deferred
tax balances unwind.
Liabilities
The increase in total liabilities of $15,707 million to $24,070 million (2023:
$8,363 million, as restated) is primarily driven by the recognition of the
liabilities assumed as a result of the acquisition. Liabilities assumed
included deferred tax liabilities of $5,500 million, borrowings net of
transaction fees of $3,079 million, provisions of $2,940 million, trade and
other payables of $1,159 million and current tax liabilities of $1,128
million. Additionally, the Group increased its borrowings by $1,914 million
being $250 million drawn under the $3 billion revolving credit facility (RCF)
and new issue of Euro-denominated bonds of $1,664 million (nominal €1,600
million). Total liabilities included liabilities directly associated with
assets held for sale in respect of the Vietnam disposal of $233 million.
The net deferred tax position on the statement of financial position is a
liability of $6,091 million (2023: $1,290 million, as restated). This is
primarily made up of a deferred tax liability in respect of the future profits
which will flow from our property, plant and equipment of $9,600 million
offset by a deferred tax asset in respect of future tax relief on
decommissioning spend of $2,791 million, fair value losses on derivatives of
$336 million and tax losses of $288 million (before adjustment for assets held
for sale).
Equity and reserves
Total equity increased by $4,698 million to $6,251 million (2023: $1,553
million, as restated) mainly due to the recognition of merger reserve of
$3,457 million associated with the 921 million shares issued to BASF and
LetterOne as part of the acquisition as well as the recognition of
subordinated notes that were assumed as part of the acquisition of $1,548
million. Movements in equity also included unfavourable post-tax fair value
movements on cash flow hedges of $166 million (2023: favourable of $792
million) and gains on currency translation of $130 million (2023: $103
million) all recognised in other comprehensive income. Equity was reduced by
dividend payments of $199 million (2023: $190 million) in addition to the loss
for the year.
Net debt
As at 31 December 2024, net debt of $4,424 million (2023: $207 million, as
restated). This consisted of borrowings amounting to $5,512 million (2023:
$500 million) net of unamortised fees of $283 million (2023: $7 million) less
cash balances of $805 million (2023: $286 million, as restated). During the
year the RBL facility was replaced by the RCF and, as at 31 December 2024,
$250 million was outstanding. At the end of 2023 the drawdown in the RBL was
$nil and there were $61 million of unamortised fees classified in debtors
which were expensed in 2024. As part of the acquisition, $3,079 million worth
of borrowings were assumed, and a $1,500 million bridge facility was used to
complete the acquisition. This was subsequently refinanced into two
Euro-denominated bonds amounting to $1,664 million (€900 million and €700
million, respectively). In addition, Harbour had surety bonds of $675 million
(£540 million) at year end which provide cover for decommissioning
securities.
Available liquidity, comprising undrawn portion of the RCF facility of $1.9
billion ($250 million debt and $0.9 billion letters of credit for
decommissioning have been drawn) plus cash balances of $0.8 billion (2023:
$0.3 billion), was $2.7 billion (2023: $1.6 billion) at the end of the year.
As at 31 December 2024, the leverage ratio(1) was 1.1x (2023: 0.1x) which has
increased primarily as a result of the significant increase in net debt due to
the acquisition, as well as only four months of EBITDAX contribution from the
acquired portfolio. The balance sheet is in a strong position supported by the
RCF facility and investment grade credit ratings.
2024 2023
$ million $ million
As restated
Leverage ratio
Net debt(1) 4,424 207
EBITDAX(1) 4,006 2,675
Leverage ratio(1) 1.1x 0.1x
1 Non-IFRS measure - see Glossary for the definition.
Derivative financial instruments
We carry out hedging activity to manage commodity price risk. We have entered
into both a series of fixed-price sales agreements and a financial hedging
programme for both oil and gas, consisting of swap and option instruments.
Hedges realised to date are in respect of both crude oil and natural gas.
The current hedging programme is shown below:
Hedge position 2025 2026 2027
Oil
Total oil volume hedged (thousand bbls) 16,162 12,881 -
- of which swaps 15,598 12,881 -
- of which zero cost collars 564 - -
Weighted average fixed price ($/bbl) 76.47 72.88 -
Weighted average collar floor and cap ($/bbl) 60.00 - 86.78 - -
Natural gas
Gas volume hedged (thousand boe) 33,509 19,924 2,056
- of which swaps/fixed price forward sales 26,912 16,817 2,056
- of which zero cost collars 6,597 3,106 -
Weighted average fixed price ($/mscf) 12.91 10.79 11.29
Weighted average collar floor and cap ($/mscf) 11.46 - 22.50 9.04 - 16.71 -
As at 31 December 2024, our financial hedging programme on commodity
derivative instruments showed a pre-tax negative mark-to-market fair value of
$476 million (2023: $18 million). Most of the commodity derivatives were
designated as cash flow hedges, therefore, changes in fair value were reported
in other comprehensive income.
For foreign exchange derivative instruments, the pre-tax negative
mark-to-market fair value was $198 million (2023: $nil). Of this value, $173
million related to the cross-currency interest rate swaps designated as cash
flow hedges relating to the euro bonds where €2.4 billion was hedged at a
forward rate of between 1.1015 and 1.1209. The remaining $25 million related
to FX forward contracts designated as fair value through income statement.
Acquisition of Wintershall Dea assets
On 3 September 2024, the Group closed the transaction to acquire substantially
all of Wintershall Dea's upstream assets from BASF and LetterOne, including
those in Norway, Germany, Denmark, Argentina, Mexico, Egypt, Libya and Algeria
as well as Wintershall Dea's CCS licences in Europe. Under the purchase price
allocation that was performed, the fair values of identifiable assets and
liabilities of Wintershall Dea, and resulting goodwill, are as follows:
Fair value recognised on acquisition
$ million
Assets
Other intangible assets 4,409
Property, plant and equipment 10,011
Right-of-use assets 106
Deferred tax assets 147
Other assets, excluding cash and cash equivalents 1,814
Cash and cash equivalents 748
Total assets 17,235
Liabilities
Borrowings 3,079
Provisions 2,940
Deferred tax liabilities 5,500
Lease creditor 118
Derivative liabilities 317
Other liabilities 2,287
Total liabilities 14,241
Fair value of net identifiable net assets acquired 2,994
Subordinated notes measured at fair value (1,548)
Goodwill arising on acquisition 3,845
Purchase consideration transferred 5,291
The goodwill of $3,845 million arises principally from the requirement to
recognise undiscounted deferred taxes liabilities for the difference between
the fair value and the tax base of the acquired assets and liabilities assumed
in the business combination. This goodwill will ultimately be charged to the
income statement over time as an impairment charge, primarily as the deferred
tax balances unwind.
From the date of acquisition, the acquired assets contributed $2,021 million
of revenue and $867 million to profit before tax from continuing operations of
the Group. If the combination had taken place at the beginning of the year,
revenue from continuing operations would have been $10,516 million and profit
before tax from continuing operations for the Group would have been $3,017
million.
Statement of cash flows(1)
2024 2023
$ million $ million
As restated
Cash flow from operating activities before tax payments 3,114 2,588
Tax payments (1,499) (438)
Cash flow from operating activities after tax payments 1,615 2,150
Cash flow from investing activities - capital investment (1,322) (718)
Cash flow from investing activities - other(2) 89 25
Operating cash flow after investing activities 382 1,457
Cash flow from financing activities(3) (500) (409)
Free cash flow(4) (118) 1,048
Cash and cash equivalents 805 286
(1) Table excludes financing activities related to debt principal movements.
(2) Excludes net expenditure on business combinations of ($1,044 million, note
14 of the financial statements).
(3) Interest and lease interest and capital payments only, excludes
shareholder distributions.
(4) Non-IFRS measure - see Glossary for the definition.
Net operating cashflow before tax was $3,114 million (2023: $2,588 million, as
restated) reflecting the enlarged group. The timing and magnitude of tax
payments impacted net cash from operating activities after tax which amounted
to $1,615 million (2023: $2,150 million, as restated). Tax payments during the
year were $1,499 million compared to $438 million in 2023 due to the enlarged
portfolio and balancing payments for prior year UK EPL. UK EPL payments
amounted to $732 million (2023: $402 million).
Cash flow working capital movements were negative $494 million (2023: positive
$205 million) as the increase in production within the enlarged business
coupled with overdue receivables in Egypt and Mexico means we carry a
materially higher net working capital position on our balance sheet at year
end.
Capital investment was $1,322 million (2023: $718 million) which included
property, plant and equipment additions of $884 million (2023: $496 million),
exploration and evaluation additions of $359 million (2023: $202 million) and
other intangible additions of $79 million (2023: $20 million). Cash outflow
from financing activities totalled $500 million (2023: $409 million) split
between interest payments of $181 million (2023: $150 million) and lease
payments of $319 million (2023: $259 million).
Free cash flow was $118 million outflow after acquisition related costs of
$235 million. Before these acquisition related costs free cash flow was $117
million inflow.
Shareholder distributions consist of dividends paid of $199 million (2023:
$190 million). In 2023, shareholder distributions also included $249 million
related to the repurchase of Harbour's own shares.
Cash and cash equivalent balances were $805 million (2023: $286 million, as
restated) at the end of the year.
Capital investment is defined as additions to property, plant and equipment,
fixtures and fittings and intangible exploration and evaluation assets,
excluding changes to decommissioning assets.
2024 2023
$million $million
As restated
Additions to oil and gas assets (1,037) (482)
Additions to fixtures and fittings, office equipment & IT software (73) (29)
Additions to exploration and evaluation assets (398) (210)
Additions to other intangible assets (36) -
Total capital investment(1) (1,544) (721)
Movements in working capital 140 (22)
Capitalised interest 18 7
Capitalised lease payments 64 18
Cash capital investment per the cash flow statement (1,322) (718)
(1) Non-IFRS measure - see Glossary for the definition.
During the period, the Group incurred total capital expenditure of $1,828
million (2023: $989 million), split by capital investment $1,544 million
(2023: $721 million) and decommissioning spend $284 million (2023: $268
million) respectively.
The capital investment for operated assets mainly consisted of; in the UK,
project activity at Talbot (J-Area) and development drilling at J-Area,
Callanish F6 (GBA), Greater Britannia appraisal at Leverett and discoveries at
Gilderoy and Jocelyn South and North West Seymour (AELE); in Norway, multiple
tieback projects at Maria, Dvalin North, Irpa, Alva Nord and Idun North plus
Solveig; in Germany, continued development of the Mittelplate field; and in
Mexico, the Kan-2 appraisal well.
For partner-operated assets, capital investment consisted primarily of; in the
UK, drilling at Buzzard, Clair and Schiehallion; in Norway, drilling continued
at Skarv and Njord; in Argentina, the offshore Fenix field development was
completed; and in Egypt, drilling continued on the Raven West field infill
wells. In Indonesia exploration and appraisal wells were drilled at Layaran
and Tangkulo in South Andaman.
Refer to the Operational Review for more detail.
Principal risks
The Directors have identified several changes to the principal risks facing
the company over the period, primarily as a result of how the Wintershall Dea
transaction has diversified the portfolio and strengthened the financial
position of the business. Notably, the principal risk recognised in the 2023
Annual Report as 'Access to capital' has been broadened to 'Financial
Discipline' to encompass broader aspects of the financial management and
control, while the unmitigated risk level of several principal risks has
increased.
Post balance sheet events
On 23 January 2025 Harbour announced it had signed a Sale and Purchase
Agreement to sell its Vietnam business, which includes the 53.125% equity
interest in the Chim Sáo and Dua production fields, to EnQuest for $84
million. The effective date is 1 January 2024 with completion targeted during
2025. This agreement resulted in the Vietnam business unit being classed as
asset held for sale as at 31 December 2024.
On 3 March 2025, the Finance Act 2025 was substantively enacted following its
third reading in the UK Parliament. While the substantive enactment has no
implications for the current accounting period, it confirms that the extension
of the Energy Profits Levy to 31 March 2030 will be reflected in the Group's
results for the interim period to 30 June 2025. If the Finance Act 2025 had
been substantively enacted at the balance sheet date, the deferred tax
liability at the end of the period would have increased by $306 million
(further details are provided in note 8 of the financial statements).
Going concern
The Directors considered the going concern assessment period to be up to 31
December 2026. The Group monitors and manages its capital position and its
liquidity risk regularly to ensure that it has access to sufficient funds to
meet forecast cash requirements. Cash forecasts for management are regularly
produced and sensitivities considered based on, but not limited to, the
Group's latest life of field production and expenditure forecasts,
management's best estimate of future commodity prices based on recent forward
curves, adjusted for the Group's hedging programme and the Group's borrowing
facilities.
The Group's ongoing capital requirements are financed by its $3.0 billion
revolving credit facility (RCF), bonds and subordinated notes $1.6 billion,
and surety bonds of $675 million (£540 million) which provide cover for
decommissioning securities. The RCF is subject to financial covenants that
require the ratio of consolidated total net debt, including letters of credit,
to last twelve months (LTM) EBITDAX to be less than 3.5x and LTM EBITDA
divided by interest expense to exceed 3.5x. Under the Group's base case, the
RCF is forecast to have an undrawn balance of $3.0 billion through 2025 and
2026. When combined with drawn letters of credit and unrestricted cash the
headroom is forecasted to be $2.5 billion in 2026 which provides a robust
liquidity position.
The base case indicates that the Group is able to operate as a going concern
with sufficient headroom and remain in compliance with its loan covenants
throughout the assessment period.
The Group's going concern assessment is based on management's best estimate of
forward commodity price curves and other economic assumptions, production and
expenditure in line with approved asset base case, plus the ongoing capital
requirements of the Group that will be financed by free cash flow, the
existing RCF and bond financing arrangements.
In line with the principal risks that have been identified to impact the
financial capability of the Group to operate as going concern, a single
downside sensitivity scenario has been prepared reflecting a reduction in:
§ Brent crude, UK natural gas and Dutch TTF gas prices of 20 per cent, and
§ the Group's unhedged production of 10 per cent
throughout the entire assessment period. Management considers this represents
a severe but plausible downside scenario appropriate for assessing going
concern and viability.
In this downside scenario when applied individually and in aggregate to the
base case forecast, the Group is forecast to have sufficient liquidity
headroom throughout the assessment period and to remain in compliance with its
financial covenants.
Reverse stress tests have been prepared reflecting reductions in each of
commodity price and production parameters, prior to any mitigation strategies,
to determine at what levels each would need to reach such that either the
lending covenants are breached or liquidity headroom runs out. The results of
these reverse stress tests demonstrated the likelihood that a sustained
significant fall in commodity prices or a significant fall in production over
the assessment period that would be required to cause a risk of funds
shortfall or a covenant breach is remote.
Taking the above analysis into account and considering the findings of the
work performed to support the statement on the long-term viability of the
company and the Group, the Board was satisfied that, for the going concern
assessment period, the Group is able to maintain adequate liquidity and comply
with its lending covenants up to 31 December 2026 and has therefore adopted
the going concern basis for preparing the financial statements.
By order of the Board,
Alexander Krane
Chief Financial Officer
5 March 2024
Financial Statements
Consolidated income statement
For the year ended 31 December 2024
Note 2024 2023
$ million As restated
$ million
Revenue 4 6,158 3,715
Other income 4 68 36
Revenue and other income 6,226 3,751
Cost of operations 5 (3,613) (2,376)
Impairment of property, plant and equipment 5, 12 (352) (176)
Impairment of right-of-use assets 13 (20) -
Impairment of goodwill 5, 10 - (25)
Exploration and evaluation expenses and new ventures 5 (68) (36)
Exploration costs written-off 5 (173) (57)
General and administrative expenses 5 (352) (149)
Operating profit 1,648 932
Finance income 7 173 104
Finance expenses 7 (602) (420)
Profit before taxation 1,219 616
Income tax expense 8 (1,312) (571)
(Loss)/profit for the year (93) 45
(Loss)/profit for the year attributable to:
Equity owners of the company (108) 45
Subordinated notes investors 15 -
(93) 45
(Loss)/earnings per share Note $ cents $ cents
Basic
Ordinary shares voting 9 (10) 6
Ordinary shares non-voting 9 (11) -
Diluted
Ordinary shares voting 9 (10) 6
Ordinary shares non-voting 9 (11) -
Consolidated statement of comprehensive income
For the year ended 31 December 2024
2024 2023
$ million As restated
$ million
(Loss)/profit for the year (93) 45
Other comprehensive income/(loss)
Items that will not be subsequently reclassified to income statement:
Actuarial losses (6) -
Tax credit on actuarial losses 4 -
Net other comprehensive (loss)/income that will not be subsequently (2) -
reclassified to income statement
Items that may be subsequently reclassified to income statement:
Fair value (losses)/gains on cash flow hedges (545) 3,168
Tax credit/(charge) on cash flow hedges 379 (2,376)
Exchange differences on translation 130 103
Net other comprehensive (loss)/income that may be subsequently reclassified to (36) 895
income statement
Other comprehensive (loss)/income for the year, net of tax (38) 895
Total comprehensive (loss)/income for the year (131) 940
Total comprehensive income attributable to:
Equity owners of the company (146) 940
Subordinated notes investors 15 -
(131) 940
Consolidated balance sheet
For the year ended 31 December 2024
Note 2024 2023
$ million As restated
$ million
Assets
Non-current assets
Goodwill 10 5,147 1,302
Other intangible assets 11 5,714 1,172
Property, plant and equipment 12 14,543 4,836
Right-of-use assets 13 656 632
Deferred tax assets 8 130 7
Other receivables 16 176 309
Other financial assets 23 44 112
Total non-current assets 26,410 8,370
Current assets
Inventories 15 368 217
Trade and other receivables 16 2,316 873
Other financial assets 23 145 170
Cash and cash equivalents 17 805 286
3,634 1,546
Assets held for sale 18 277 -
Total current assets 3,911 1,546
Total assets 30,321 9,916
Equity and liabilities
Equity
Share capital 25 171 171
Merger reserve 25 3,728 271
Other reserves (18) 18
Retained earnings 807 1,093
Equity attributable to equity holders of the company 4,688 1,553
Equity attributable to subordinated notes investors 26 1,563 -
Total equity 6,251 1,553
Non-current liabilities
Borrowings 22 4,215 493
Provisions 21 7,024 3,905
Deferred tax 8 6,221 1,297
Trade and other payables 20 30 13
Lease creditor 13 551 552
Other financial liabilities 23 415 87
Total non-current liabilities 18,456 6,347
Current liabilities
Trade and other payables 20 1,755 915
Borrowings 22 1,014 16
Lease creditor 13 241 216
Provisions 21 497 230
Current tax liabilities 1,412 442
Other financial liabilities 23 462 197
5,381 2,016
Liabilities directly associated with the assets held for sale 18 233 -
Total current liabilities 5,614 2,016
Total liabilities 24,070 8,363
Total equity and liabilities 30,321 9,916
The following notes form part of these financial statements.
The financial statements were approved by the board of directors and
authorised for issue on 5 March 2025 and signed on its behalf by:
Alexander Krane
Chief Financial Officer
Consolidated statement of changes in equity
For the year ended 31 December 2024
Share capital Merger Capital Cash flow Costs of Currency Retained Equity Equity Total
$ million reserve(1) redemption hedge hedging translation earnings attributable attributable to sub-ordinated equity
$ million reserve reserve(2) reserve(2) reserve $ million to owners of notes investors $ million
$ million $ million $ million $ million the company $ million
$ million
At 1 January 2023 171 271 8 (776) (9) (100) 1,456 1,021 - 1,021
Profit for the year as restated - - - - - - 45 45 - 45
Other comprehensive income - - - 779 13 103 - 895 - 895
Total comprehensive income as restated - - - 779 13 103 45 940 - 940
Purchase and cancellation of own shares - - - - - - (249) (249) - (249)
Share-based payments - - - - - - 46 46 - 46
Purchase of ESOP trust shares - - - - - - (15) (15) - (15)
Dividend paid - - - - - - (190) (190) - (190)
At 31 December 2023 as restated 171 271 8 3 4 3 1,093 1,553 - 1,553
(Loss)/profit for the year - - - - - - (108) (108) 15 (93)
Other comprehensive (loss)/income - - - (188) 22 130 (2) (38) - (38)
Total comprehensive (loss)/income - - - (188) 22 130 (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
Dividends paid - - - - - - (199) (199) - (199)
At 31 December 2024 171 3,728 8 (185) 26 133 807 4,688 1,563 6,251
(1) The increase in the merger reserve represents the difference between the
fair value and nominal value of the shares issues as consideration for the
acquisition of the Wintershall Dea assets.
(2) Disclosed net of deferred tax.
Consolidated statement of cash flows
For the year ended 31 December 2024
Note 2024 2023
$ million As restated
$ million
Net cash flows from operating activities 29 1,615 2,150
Investing activities
Expenditure on exploration and evaluation assets (359) (202)
Expenditure on property, plant and equipment 12 (884) (496)
Expenditure on non-oil and gas intangible assets (42) (20)
Expenditure on other intangible assets (37) (81)
Acquisition of subsidiaries, net of cash acquired 14 (1,044) -
Finance income received 76 93
Other receipts 13 13
Net cash flows used in investing activities (2,277) (693)
Financing activities
Repurchase of shares - (249)
Proceeds from new borrowings - revolving credit facility 29 2,225 -
Proceeds from new borrowings - reserves based lending facility 29 178 660
Proceeds from bridge facility 29 1,500 -
Proceeds from bond issuance net of transaction costs 29 1,720 -
Payments of principal portion of lease liabilities (265) (207)
Interest paid on lease liabilities (54) (52)
Repayment of revolving credit facility 29 (1,975) -
Repayment of reserves based lending facility 29 (178) (1,435)
Repayment of bridge facility 29 (1,500) -
Repayment of exploration financing facility - (11)
Repayment of financing arrangement 29 (17) (21)
Purchase of ESOP trust shares (25) (12)
Interest paid and bank charges (181) (150)
Dividends paid to shareholders 31 (199) (190)
Net cash inflow/(outflow) from financing activities 1,229 (1,667)
Net increase/(decrease) in cash and cash equivalents 567 (210)
Net foreign exchange difference (37) (4)
Reclassification of Vietnam cash as asset held for sale (11) -
Cash and cash equivalents at 1 January 286 500
Cash and cash equivalents at 31 December 805 286
Notes to the condensed consolidated financial statements
1. Corporate information
Harbour Energy plc is a limited liability company incorporated in Scotland and
listed on the London Stock Exchange. The address of the registered office is
4th Floor, Saltire Court, 20 Castle Terrace, Edinburgh, EH1 2EN, United
Kingdom.
The consolidated financial statements of Harbour Energy plc (Harbour or the
company) and all its subsidiaries (the Group) for the year ended 31 December
2024 were authorised for issue by the board of directors on 5 March 2025.
On 3 September 2024, the Group completed the acquisition of substantially all
of Wintershall Dea's upstream oil and gas assets, including those in Norway,
Germany, Denmark, Argentina, Mexico, Egypt, Libya and Algeria as well as
Wintershall Dea's CCS licences in Europe. Under IFRS 3 Business Combinations,
the Group is the legal and accounting acquirer as it obtained control over the
Wintershall Dea portfolio through the business combination: as it was the
entity that issued equity and paid cash to effect the business combination; at
completion then existing Harbour Energy shareholders held a majority of voting
ordinary shares; and from completion, day-to-day management of the enlarged
group has been led by existing Harbour Energy personnel, with no change to the
executive directorship.
The Group has designated 1 September 2024 as the acquisition date (beginning
of month) rather than the actual acquisition date of 3 September 2024 (during
the month) as the events between the designated acquisition date and the
actual acquisition date do not result in material changes in the amounts
recognised.
The acquired Wintershall Dea portfolio results are fully consolidated in the
financial statements from 1 September 2024, and all results prior to this date
represent those of the legacy Harbour group only.
The Group's principal activities are the acquisition, exploration, development
and production of oil and gas reserves in Norway, the UK, Germany, Mexico,
Argentina, North Africa and Southeast Asia.
2. Material accounting policies
Basis of preparation
The consolidated financial statements have been prepared on a going concern
basis in accordance with UK-adopted International Accounting Standards (IAS)
in conformity with the requirements of the Companies Act 2006. The analysis
used by the directors in adopting the going concern basis considers the
various plans and commitments of the Group as well as various sensitivity and
reverse stress test analyses. The results from the severe but plausible
downside sensitivities and reverse stress tests with regard to production and
commodity price assumptions, which in management's view reflect two of the
principal risks, indicate that material changes within one year that would
impact the going concern basis of preparation are remote.
In 2023, the Vietnam Business Unit was classified as an asset held for sale
however because this deal did not complete the prior year accounts have been
restated to classify the assets and liabilities back to their original balance
sheet line items.
The presentation currency of the Group financial information is US dollars and
all values in the Group financial information are presented in millions ($
million) and all values are rounded to the nearest 1 million, except where
otherwise stated.
The financial statements have been prepared on the historical cost basis,
except for certain financial assets and liabilities, including derivative
financial instruments, which have been measured at fair value.
The accounting policies which follow set out those policies which apply in
preparing the financial statements for the year ended 31 December 2024. All
accounting policies are consistent with those adopted and disclosed in
Harbour's 2023 Annual Report & Accounts.
Basis of consolidation
The consolidated financial statements comprise the financial statements of the
company and its subsidiaries as at 31 December 2024. Subsidiaries are those
entities over which the Group has control. Control is achieved where the Group
has the power over the subsidiary, has rights, or is exposed to variable
returns from the subsidiary and has the ability to use its power to affect its
returns. All subsidiaries are 100 per cent owned by the Group, except for four
entities holding interests in operations in North Africa and CCS projects
which are accounted for as joint operations.
Profit or loss and each component of other comprehensive income (OCI) are
attributed to the equity holders of the company and to the subordinated notes
investors.
If the Group loses control over a subsidiary, it derecognises the related
assets (including goodwill), liabilities, non-controlling interest and other
components of equity, while any resultant gain or loss is recognised in profit
or loss. Any investment retained is recognised at fair value.
The results of subsidiaries acquired or disposed of during the year are
included in the income statement from the effective date of acquisition or up
to the effective date of disposal, as appropriate. Where necessary,
adjustments are made to the financial statements of subsidiaries acquired to
bring the accounting policies used into line with those used by other members
of the Group.
All intra-group transactions and balances have been eliminated on
consolidation.
Prior year adjustment
In August 2023, Harbour announced that it had entered into a sale and purchase
agreement (SPA) to sell its business in Vietnam, which holds its 53.125 per
cent interest in Chim Sáo and Dua producing fields to Big Energy Joint Stock
Company for a consideration of $84 million. At 31 December 2023, the assets
and liabilities of Vietnam were classified as assets held for sale (AHFS). The
transaction, which had a long-stop date of 10 May 2024, could not be completed
within the required timeframe, and was subsequently terminated on 13 May 2024,
and as a result the Vietnam business was no longer classified as AHFS. The
relevant amounts presented as AHFS in the 31 December 2023 consolidated
financial statements have been reclassified. Each of the affected financial
statement line items has been restated and the impact is summarised in the
following table.
Balance sheet at 31 December 2023
As previously reported Adjustments As restated
$ million $ million $ million
Non-current assets
Property, plant and equipment 4,717 119 4,836
Right-of-use assets 587 45 632
Other receivables 184 125 309
Current assets
Inventories 200 17 217
Trade and other receivables 832 41 873
Cash and cash equivalents 280 6 286
Assets held for sale 334 (334) -
Equity
Retained earnings 1,080 13 1,093
Non-current liabilities
Provisions 3,818 87 3,905
Deferred tax 1,260 37 1,297
Lease creditor 474 78 552
Current liabilities
Trade and other payables 886 29 915
Lease creditor 199 17 216
Liabilities directly associated with the assets held for sale 242 (242) -
From the point of classification as AHFS in August 2023, no depreciation was
recorded. In addition, at 31 December 2023, a pre-tax impairment of $38
million was recognised as the fair value less cost to sell was below the
carrying amount of the disposal group. As a result of the reclassification
from AHFS, the impairment of $38 million has been reversed and additional
depreciation covering the period August 2023 to December 2023 has been
recorded, on property, plant and equipment of $14 million and on right-of-use
assets of $5 million, with net deferred tax of $6 million associated with the
impairment reversal and depreciation. As a result of the above adjustments,
retained earnings increased by $13 million.
In December 2024, the Group entered into an exclusivity agreement to sell its
business in Vietnam to EnQuest for a consideration of $84 million. The
transaction has an effective date of 1 January 2024. As a result, the assets
and liabilities of Vietnam have been classified as held for sale as at 31
December 2024 (see note 18).
Significant accounting judgements and estimates
The preparation of the Group's financial statements in conformity with
UK-adopted IAS requires management to make judgements, estimates and
assumptions at the date of the financial statements. Estimates and assumptions
are continuously evaluated and are based on management experience and other
factors, including expectations of future events that are believed to be
reasonable under the circumstances. Uncertainty about these assumptions and
estimates could result in outcomes that require a material adjustment to the
carrying amount of the assets or liabilities affected in future periods.
In preparing these financial statements, management has made judgements and
estimates that affect the application of accounting policies and the reported
amounts of assets and liabilities, income and expenses including those that
have the potential to materially impact the balance sheet over the next twelve
months. Actual results may differ from these estimates.
The significant judgements made by management in applying the Group's
accounting policies, and the key sources of estimation uncertainty, were the
same as those described in Harbour's 2023 Annual Report & Accounts, with
the addition of the purchase price allocation that involved a number of
judgements in regard to assessing the fair value of assets and liabilities
acquired from Wintershall Dea.
Judgements
§ 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 carrying value of property, plant and equipment regarding assessing assets
for indicators of impairment;
§ Decommissioning costs in relation to the timing of when decommissioning would
occur; 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 values the fair value of assets and liabilities acquired
from Wintershall Dea. 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 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;
§ Defined benefit obligations due to volatility arising from actuarial
assumptions, such as the discount rate and pension growth. See note 28 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 ambition is to achieve Net Zero by 2050 with an interim
target of a 50 per cent reduction in Scope 1 and 2 emissions by 2030 against
the 2018 baseline. This will be achieved through several opportunities,
including operational efficiency improvements, targeted decarbonisation
projects and the eventual cessation of production of mature fields. In
addition, the company is investing in the development of CCS projects in the
UK and Europe.
All new economic investment decisions include the cost of carbon, and
opportunities are assessed on their climate-impact potential and alignment
with Harbour Energy's net zero aspiration taking into consideration both GHG
volumes and intensity. The acquisition during the year has helped to advance
our energy transition objective by strategically shifting our portfolio
towards natural gas. Over time this move is expected to notably reduce our
greenhouse gas intensity on a net equity basis. The corporate modelling that
supports the preparation of the financial statements (such as asset and
goodwill impairment assessment, going concern and viability, deferred tax
asset recoverability) includes project costs related to CCS, certain
decarbonisation projects once sanctioned, other activities to reduce gross
operated Scope 1 and 2 GHG emissions, the UK and EU Emissions Trading Scheme
costs and carbon offset purchases. Emissions reduction incentives are part of
staff remuneration through the annual bonus programme.
Climate change and the energy transition have the potential to significantly
impact the accounting estimates adopted by management and therefore the
valuation of assets and liabilities reported on the balance sheet. On an
ongoing basis, management continues to assess the potential impacts on the
significant judgements and estimates used in the preparation of the financial
statements. Estimates adopted in the financial statements reflect management's
best estimate of future market conditions where, in particular, commodity
prices can be volatile. Commodity and carbon price curve assumptions are
described below noting that there is consideration given to other assumptions,
not exhaustively, such as foreign exchange and discount rates. Notwithstanding
the challenges around climate change and the energy transition, it is
management's view that the financial statements are consistent with the
disclosures in the Strategic Report.
This note provides insight into how Harbour has considered the impact on
valuations of key line items in the financial statements and how they could
change based on the climate change scenarios and sensitivities considered. The
scenarios presented show what the possible impact could be on the financial
statements considering both high and low commodity and carbon price outlooks
plus discount rates range. Importantly, these climate change scenarios do not
form the basis of the preparation of the financial statements but rather
indicate how the key assumptions that underpin the financial statements would
be impacted by the climate change scenarios. They are also designed to
challenge management's perspective on the future business environment. It is
recognised that the reality of the nature of progress of energy transition
will bring greater levels of disruption and volatility than these external
scenarios expect and do not represent management's current best estimate.
The financial statements have been prepared using management's current best
estimate for the foreseeable future, based on a range of economic forecasts
and represented by the Harbour scenario oil price curve. Management regularly
reviews these estimates and assumptions to ensure they align with the latest
economic conditions and market information.
Property, plant and equipment, and goodwill
Transitioning to lower carbon energy as the energy transition progresses has
the potential to significantly impact future commodity and carbon prices which
would, in turn, affect the future operating and capital costs, estimates of
cessation of production, useful lives, and consequently the recoverable amount
of property, plant and equipment and goodwill.
The non-current assets of the Group, particularly goodwill and oil and gas
assets within property, plant and equipment, are considered to be the most
sensitive to the energy transition. The carrying value of these assets and
goodwill notably increased during the year, primarily attributed to the
completion of the Wintershall Dea acquisition in the second half of the year.
Depreciation, estimated useful life and risk of stranded assets
The energy transition and the rate of its progression may impact the remaining
lifespan of assets. Typically, the Group's oil and gas assets are depreciated
using a unit of production method, which is based on the ratio of production
in the year to the commercial proven and probable reserves of the field,
considering future capital development expenditures.
As at 31 December 2024, the Group's production plans for existing assets
indicated that 44 per cent, 18 per cent and nil per cent of the commercial
proven and probable reserves would remain by 2030, 2035, and 2050,
respectively. Using the unit of production depreciation method, the carrying
amounts for the oil and gas assets are depreciated in line with the depletion
of reserves. An evaluation of the oil and gas assets as at 31 December 2024
indicated that the oil and gas assets would experience significant additional
depreciation by 2030 and near-complete depreciation by 2035, based on the
planned depletion of reserves.
This indicates that a substantial portion of proven and probable reserves are
anticipated to be produced by 2035, resulting in lower risk of stranded assets
being carried in the consolidated balance sheet. The Group's portfolio
management approach aims to mitigate the risk of stranded assets in the event
of a faster-than-expected structural decline in demand for oil and gas due to
tighter environmental regulations, changes in market demands and global energy
demand.
Impairment of property, plant and equipment, and goodwill
The important assumptions for impairment testing of goodwill and oil and gas
assets applied to the life of fields production and cost profiles include
commodity and carbon prices and discount rates. These key assumptions are
carefully assessed by management, both in isolation and in aggregate, to
ensure there is a fair and balanced view attained with minimal aggregate bias.
These assumptions are inherently uncertain and may ultimately diverge from the
actual amounts.
During the current year's impairment testing, the Harbour scenario utilised
real long-term commodity price assumptions from 2028 for Brent crude at $78
per barrel (2023: $70 per barrel), UK NBP gas at 80 pence per therm (2023: 90
pence per therm), and a European gas price at 2 per cent higher than UK NBP.
These were combined with short-term management forecasts reflecting
benchmarked consensus and market forward curves at the year end.
Carbon costs are expected to evolve over time and are subject to significant
uncertainty due to the rate of transition and the maturity of regulatory
frameworks. For the carbon price, Harbour management's real forward price
curve assumption in 2024 is $72 per tonne (2023: $63 per tonne), projected to
increase to $182 per tonne (2023: $175 per tonne) by 2030. Sensitivity
analysis was conducted using the IEA Net Zero carbon price curve, with a flat
assumed foreign exchange rate of pound sterling to US dollar rate of
£1:$1.30.
Sensitivity to changes in commodity price assumptions
Sensitivity analyses on the impairment of oil and gas assets and goodwill have
been conducted using different commodity price scenarios to demonstrate the
potential impact on their net book carrying values. It should be noted that
the financial statements are based on the Harbour scenario. Impairment
sensitivities have been developed using average -10 per cent and +10 per cent
deviations from the Harbour scenario long-term crude and gas prices as well as
selected published climate change price curves.
The sensitivity scenarios described below incorporate changes to the commodity
price assumptions and assume that all other factors remain unchanged from the
Harbour scenario used for the basis of preparation of the financial
statements. Importantly, these sensitivities are stated before any management
mitigation actions to manage downside risks if the scenarios were to occur.
The Sustainability review within the Annual Report, which will be released on
27 March 2025, discusses both transition and physical risk climate change
scenarios. This analysis covers the transition risks and the graphs below show
the crude oil, UK NBP gas price curves and European TTF gas price for the
period to 2050 for the following IEA scenarios: Net Zero Emissions by 2050,
Stated Policies and Announced Pledges.
All the scenario price curves are dependent on factors covering supply,
demand, economic and geopolitical events and therefore are inherently
uncertain and subject to significant volatility and hence unlikely to reflect
the future outcome.
§ 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 Announced Pledges Scenario (APS): pathway based on current climate
ambitions and targets by governments and industries regardless of whether
these have been legislated
The crude price curves reflect the published IEA price curves for all periods.
For UK NBP there are no IEA published price curves therefore management has
derived the gas price curves by converting from the published IEA European gas
price curve. This was achieved by converting from USD per mbtu to pence per
therm and applying other known correlation coefficients between the European
and UK gas markets. In addition, for the period 2025-2027, the derived gas
price curve matches the Harbour scenario price curve to create a scenario that
was considered reasonably plausible.
Pre-development assets are recorded in other intangible assets ahead of
demonstration of commerciality and recognition of 2P reserves and hence are
not included below, however they are subject to the same management rigour
with the corporate models. The majority of such assets are in developing
countries with a growing future demand for energy which may reduce the climate
change impact from these pre-development assets.
The impact of the sensitivities on the carrying value of oil and gas assets
and goodwill in the consolidated balance sheet are shown in the table below.
31 December 2024
Commodity Carrying value Pre-tax sensitivity in carrying value
$ million
$ million
+10% price to Harbour scenario -10% price to Harbour scenario IEA Net Zero Emissions by 2050 (NZE) IEA Stated IEA Announced Pledges
Policies
(APS)
(STEPS)
Goodwill (note 10) Crude oil 5,147 - (45) (928) - (38)
Gas - (37) (1,431) (997) (1,114)
Oil and gas assets (note 12) Crude oil 14,458 - (323) (2,528) - (415)
Gas - (2) (131) (89) (35)
31 December 2023
Commodity Carrying value Pre-tax sensitivity in carrying value
$ million
$ million
+10% price to Harbour scenario -10% price to Harbour scenario IEA Net Zero Emissions by 2050 (NZE) IEA Stated IEA Announced Pledges
Policies
(APS)
(STEPS)
Goodwill (note 10) Crude oil 1,302 - - - - -
Gas - (4) - - -
Oil and gas assets (note 12) Crude oil 4,822 - (86) (221) - -
Gas - (21) (9) - -
The 2024 results and sensitivities are dominated by the acquired Wintershall
Dea portfolio which has substantially increased the goodwill and property,
plant and equipment carrying values.
The +/-10 per cent price curves used in the Harbour scenarios adjust long-term
prices from 2028.
Under the -10 per cent price to Harbour scenario for crude, there is a pre-tax
impairment to oil and gas assets of $323 million and on goodwill an impairment
of $45 million. For gas a pre-tax impairment of $2 million and on goodwill an
impairment of $37 million.
For crude, under the IEA NZE 2050 scenario, there is a pre-tax impairment to
oil and gas assets on of $2,528 million and on goodwill an impairment of $928
million. For gas, there is a pre-tax impairment to oil and gas assets of $131
million and on goodwill an impairment of $1,431 million.
For crude, under the IEA STEPS scenario, there is no pre-tax impairment to oil
and gas assets or goodwill. For gas, there is a pre-tax impairment to oil and
gas assets of $89 million and on goodwill an impairment of $997 million.
For crude, under the IEA APS scenario, there is a pre-tax impairment to oil
and gas assets on of $415 million and on goodwill an impairment of $38
million. For gas there is a pre-tax impairment to oil and gas assets of $35
million and on goodwill an impairment of $1,114 million.
Sensitivity to changes in carbon price assumptions
The sensitivity scenarios described below incorporate changes to the carbon
price assumptions and assume that all other factors remain unchanged from the
Harbour scenario used for the basis of preparation of the financial
statements. This sensitivity is stated before any management mitigation
actions to manage downside risks if the scenarios were to occur.
The risk of stranded assets may increase in a higher carbon price scenario.
Sensitivity analyses of the carrying value of Harbour's oil and gas assets and
goodwill to carbon prices have been conducted based on the IEA NZE 2050
scenario. This aims to demonstrate the resilience of the assets' carrying
values to higher long-term carbon prices than those reflected in the
consolidated balance sheet.
This analysis covers the transition risks, and the graphs below show the
carbon price per tonne for the period to 2050 for the IEA NZE 2050 scenario.
The scenario price curves are dependent on factors covering supply, demand,
economic and geopolitical events and therefore are inherently uncertain and
subject to significant volatility. As a result, they are unlikely to
accurately predict future outcomes.
§ 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 $9 million
(2023: $27 million) to oil and gas assets with no impairment to goodwill under
this scenario.
Sensitivity to changes in discount rate assumptions
The discount rate applied for impairment testing of the fair value less cost
of disposal is based on a nominal post-tax weighted average cost of capital
(WACC) after considering both cost of debt and equity. In 2024, the Group's
post-tax discount rate ranging from 8.75 per cent to 14.5 per cent (2023: 9.0
per cent to 12.4 per cent) is derived after considering relevant peer group's
post-tax WACC and incorporating segment-specific risk.
Considering the discount rates, the Group deems a 1 per cent rise in the
discount rate to be a reasonable potentiality for conducting sensitivity
analysis, assuming that all other factors utilised in calculating the
recoverable value for the carrying amount of goodwill and oil and gas assets
remain unaltered.
A 1 per cent increase in the discount rate would result in an additional
impairment of $113 million (2023: $24 million) to the oil and gas assets and
on goodwill $10 million (2023: $1 million), and a 1 per cent decrease in the
discount rate would have no impact on the impairment charge.
Intangible assets - exploration and evaluation assets
The energy transition has the potential to affect the future development or
viability of exploration and evaluation prospects. A significant portion of
the Group's exploration and evaluation assets relate to prospects that could
either be tied back to existing infrastructure or are in developing countries
with a growing future demand for energy which may reduce the climate change
impact from these pre-development assets and hence require less capital
investment as these assets are less exposed to the impacts of the energy
transition compared to large frontier developments. At each balance sheet
date, all exploration and evaluation prospects are reviewed against the
Group's financial framework to ensure that the continuation of activities is
planned and expected. There are no significant judgements and/or critical
estimation uncertainty related to climate factors.
See Judgements: Exploration and evaluation expenditure and note 11 to the
financial statements for further information.
Deferred tax assets
The potential impact of climate change and energy transition on balance sheet
items is uncertain and may lead to significant changes in the estimations of
parameters such as the useful life of assets and timing of cessation of
production together with their related deferred tax balances.
Deferred tax assets are recognised to the extent that their recovery is
considerable probable. In general, it is expected that sufficient forecasted
taxable profits will be available for the recovery of deferred tax assets
recognised at 31 December 2024 and expected to be recovered within the period
of production for each asset and after taking into account deferred tax
liabilities.
See note 8 Income Taxes for information on deferred tax balances.
Onerous contracts
Contracts may become onerous due to potential loss of revenue or heightened
costs stemming from changes in climate change and energy transition
regulations.
Management does not foresee any of its existing supply contracts becoming
onerous based on the current production level and estimated useful lives of
its assets.
Decommissioning cost and provisions
The energy transition may accelerate the decommissioning of assets which would
result in an increase in the carrying value of associated decommissioning
provisions. Whilst the Group currently expects to incur decommissioning costs
over the next 40 years, we anticipate the majority of costs will be incurred
between the next 10 to 20 years which will reduce the exposure to the impact
of the energy transition.
In the current year, the undiscounted provision for decommissioning and
restoration was $10.5 billion (2023: $6.6 billion), recognised on a discounted
basis in the consolidated balance sheet.
The discount and inflation rates applied have taken into consideration the
applicable rig rates and expected timing of cessation of production on each
field. Therefore, the timing of decommissioning expenditures has not been
materially brought forward and management do not consider that any reasonable
change in the timing of decommissioning expenditure will have a material
impact on the decommissioning provisions based on the production plans of
existing assets.
Decommissioning cost estimates are based on the current regulatory and
external environment. These cost estimates and recoverability of associated
deferred tax may change in the future, including as a result of the energy
transition. On the basis that all other assumptions in the calculation remain
the same, a 10 per cent increase in the cost estimates, and a 10 per cent
reduction in the applied discount rates used to assess the final
decommissioning obligation, would result in increases to the decommissioning
provision of approximately $852 million (2023: $456 million) and $286 million
($440 million), respectively. This change would be principally offset by a
change to the value of the associated asset unless the asset is fully
depreciated, in which case the change in estimate is recognised directly
within the income statement.
See Key sources of estimation uncertainty: Decommissioning costs for further
information.
Portfolio changes
Harbour expensed $75 million of costs in relation to CO2 emissions during 2024
(2023: $69 million) with the majority in relation to the UK Emissions Trading
Scheme quotas net of allocated free quotas. Quotas in relation to future
periods are recognised in intangible assets.
Harbour has investments in a number of CCS projects which are regarded as key
to assisting in the energy transition. Projects are recognised in intangible
assets once the projects are regarded as technically feasible and commercially
viable; prior to this, costs are expensed to the income statement. In 2024
Harbour spent $72 million on CCS activities, capitalising $33 million and
expensing $39 million.
Global oil and gas demand considerations
The transition to sustainable energy to mitigate climate change carries the
potential to adversely impact commodity prices due to a global decrease in the
demand for oil and gas, potentially leading to reduced revenue. Furthermore,
investment in clean energy via the adoption of clean energy technologies could
elevate production costs, thereby diminishing future profit margins.
Based on prevailing policies and regulatory frameworks, it is anticipated that
the growth in global oil demand will decrease, but the demand for oil and gas
is projected to continue as a crucial component of the energy mix for the
foreseeable future. Natural gas is widely known as a key transition fuel. In
the 2024 IEA World Energy Outlook report the demand for natural gas has been
revised upwards in all scenarios compared to the previous year, reflecting
stronger anticipated demand for gas to meet growth in electricity demand.
During the year, the Group produced 258 kboepd (2023: 186 kboepd), accounting
for less than 0.3 per cent of global production. Consequently, the Group does
not expect the ability to sell the volume of oil equivalent produced to be
directly impacted by shifts in global oil and gas demand. Management remains
committed to investing in a diversified oil and gas company.
Cost of carbon allowances
Harbour is part of the European and UK Emissions Trading Schemes (EU and UK
ETS) and purchases carbon allowances to meet its regulatory obligations under
the schemes. Harbour is entitled to receive a share of free allowances
according to UK and EU ETS regulations. Allowances owned in excess of
liabilities to date that are available to be used in future periods are
recorded in other intangible assets and measured at cost. The costs for
purchasing allowances are recorded in costs of operations matching emissions
for the period. Accruals that are required for allowances to be purchased are
measured at market price.
Segment reporting
The Group's activities consist of one class of business being the acquisition,
exploration, development and production of oil and gas reserves and related
activities and are split geographically and managed in nine Business Units:
namely Norway, the UK, Germany, Mexico, Argentina, North Africa, Southeast
Asia, CCS and Corporate.
Joint arrangements
A joint arrangement is one in which two or more parties have joint control.
Joint control is the contractually agreed sharing of control of an
arrangement, which exists only when decisions about the relevant activities
require the unanimous consent of the parties sharing control.
Exploration and production operations are usually conducted through joint
arrangements with other parties. The Group reviews all joint arrangements and
classifies them as either joint operations or joint ventures depending on the
rights and obligations of each party to the arrangement and whether the
arrangement is structured through a separate vehicle. The Group's interest in
joint operations, such as exploration and production arrangements, are
accounted for by recognising its:
§ 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.
During 2023, the Group did not have any interests in joint ventures. Note 33
describes the Group's interests in joint arrangements as at 31 December 2024.
Where the Group transacts with its joint operations, unrealised profits and
losses are eliminated to the extent of the Group's interest in the joint
operation.
Foreign currency translation
Each entity in the Group determines its own functional currency, being the
currency of the primary economic environment in which the entity operates, and
items included in the financial statements of each entity are measured using
that functional currency.
The consolidated financial statements are presented in US dollars, which is
also the parent company's functional currency.
Transactions recorded in foreign currencies are initially recorded in the
entity's functional currency by applying an average rate of exchange. Monetary
assets and liabilities denominated in foreign currencies are retranslated at
the functional currency rate of exchange ruling at the reporting date. All
differences are taken to the income statement.
Non-monetary assets and liabilities denominated in foreign currencies are
measured at historic cost based on exchange rates at the date of the initial
transaction and subsequently not retranslated.
On consolidation, the assets and liabilities of the Group's operations are
translated at exchange rates prevailing on the balance sheet date. Income and
expense items are translated at the average monthly exchange rates for the
year. Equity is held at historic cost and is not retranslated. The resulting
exchange differences are recognised as other comprehensive income and are
transferred to the Group's currency translation reserve.
When an overseas operation is disposed of, such translation differences
relating to it are recognised as income or expense.
Goodwill arising on the acquisition of a foreign operation and any fair value
adjustments to the carrying amounts of assets and liabilities arising on the
acquisition are treated as assets and liabilities of the foreign operation and
translated at the closing rate.
Goodwill
In the event of a business combination or acquisition of an interest in a
joint operation in which the activity constitutes a business, as defined in
IFRS 3 Business Combinations, the acquisition method of accounting is applied.
Goodwill represents the difference between the aggregate of the fair value of
purchase consideration transferred at the acquisition date and the fair value
of the identifiable assets, liabilities and contingent liabilities acquired,
less any non-controlling interest. If however, the fair value of the purchase
consideration transferred is lower than the fair value of the identifiable
assets and liabilities acquired, less non-controlling interest, the difference
is recognised in the income statement as negative goodwill. The Group's
goodwill is related to the requirement to recognise deferred tax for the
difference between the assigned fair values and the related tax base
('technical goodwill'). The fair value of the Group's licences are based on
post-tax cash flows or benchmarked multiples. In accordance with IAS 12
paragraphs 15 and 24, a provision is made for deferred tax corresponding to
the difference between the acquisition cost and the transferred tax
depreciation basis. The offsetting entry to this deferred tax is goodwill.
Hence, goodwill arises as a technical effect of deferred tax. Goodwill is
initially measured at cost. Following initial recognition, goodwill is
measured at cost less any accumulated impairment. Goodwill acquired in a
business combination is, from the acquisition date, allocated to each of the
Group's operating segments. This is subsequently tested for impairment at the
Group's operating segment level based on the aggregation of any headroom
arising from asset impairment tests. Goodwill is treated as an asset of the
relevant entity to which it relates, and accordingly non-US dollar goodwill is
translated into US dollars at the closing rate of exchange at each reporting
date.
Goodwill, as disclosed in note 10, is not amortised but is reviewed for
impairment at least annually by assessing the recoverable amount of the
operating segments to which the goodwill relates. Where the carrying amount of
the operating segment and related goodwill is higher than the recoverable
amount of the operating segment, an impairment loss is recognised in the
income statement. The recoverable amounts of the operating segments have been
determined on a fair value less costs to sell basis. Impairments are expected
to arise as the deferred tax that gave rise to the goodwill initially
naturally unwinds in the normal course of business. Impairment losses relating
to goodwill cannot be reversed in future periods.
Pre-licence costs
Pre-licence costs are expensed in the period in which they are incurred.
Licence and property acquisition costs
Licence and property acquisition costs paid in connection with a right to
explore in an existing exploration area are capitalised as exploration and
evaluation costs within intangible assets.
Licence and property acquisition costs are reviewed at each reporting date to
confirm that there is no indication that the carrying amount exceeds the
recoverable amount. If no future activity is planned or the related licence
has been relinquished or has expired, the carrying value of the property
acquisition costs is written off through the income statement. Upon
recognition of proved reserves and internal approval for development, the
relevant expenditure is transferred to oil and gas properties within
development and production assets.
Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated
with the exploration are capitalised as exploration and evaluation (E&E)
intangible non-current assets until the exploration is complete and the
results have been evaluated. If no potential commercial resources are
discovered, the exploration asset is written off.
All such capitalised costs are subject to technical, commercial and management
review, as well as review for indicators of impairment at least annually. This
is to confirm the continued intent to develop or otherwise extract value from
the discovery. When this is no longer the case, the costs are written off
through the income statement.
When proved reserves of oil or natural gas are identified and development is
sanctioned by management, the relevant capitalised expenditure is first
assessed for impairment and, if required, any impairment loss is recognised,
then the remaining balance is transferred to oil and gas properties within
development and production assets. No amortisation is charged during the
exploration and evaluation phase.
Farm-outs - in the exploration and evaluation phase
The Group does not record any expenditure made by the farmee on its account.
It also does not recognise any gain or loss on its exploration and evaluation
farm-out arrangements but re-designates any costs previously capitalised in
relation to the whole interest as relating to the partial interest retained.
Any cash consideration received directly from the farmee is credited against
costs previously capitalised in relation to the whole interest with any excess
accounted for by the farmor as a gain on disposal.
Property, plant and equipment - oil and gas assets
Oil and gas development and production assets are accumulated generally on a
field-by-field or cash-generating unit basis where infrastructure is shared.
This represents expenditure on the construction, installation or completion of
infrastructure facilities such as platforms, pipelines and the drilling of
development wells, including E&E expenditures incurred in finding
commercial reserves transferred from intangible E&E assets, as outlined in
the intangible asset policy above, which is capitalised as oil and gas
properties within development and production assets.
The initial cost of an asset comprises its purchase price or construction
cost, any costs directly attributable to bringing the asset into operation,
the initial estimate of the decommissioning obligation and, for qualifying
assets, where relevant, borrowing costs. The purchase price or construction
cost is the aggregate amount paid and the fair value of any other
consideration given to acquire the asset.
An item of development and production expenditure and any significant part
initially recognised is derecognised upon disposal or when no future economic
benefits are expected. Any gain or loss arising on derecognition of the asset
(calculated as the difference between the net disposal proceeds and the
carrying amount of the asset) is included in the income statement.
Expenditure on major maintenance includes refits, inspections or repairs
comprising the cost of replacement assets or parts of assets, inspection costs
and overhaul costs. Where an asset, or part of an asset, that was separately
depreciated and is now written off is replaced and it is probable that future
economic benefits associated with the item will flow to the Group, the
expenditure is capitalised. All other day-to-day repairs and maintenance costs
are expensed as incurred.
Depreciation, depletion and amortisation (DD&A) of oil and gas assets
All costs relating to a development are accumulated and not depreciated until
the commencement of production. Depreciation is provided generally on a
field-by-field or cash-generating unit basis where infrastructure is shared,
using the unit of production method by reference to the ratio of production in
the year and the related commercial proven and probable reserves of the field,
considering future development expenditures necessary to bring those reserves
into production.
When there is a change in the estimated total recoverable proven and probable
reserves of a field, that change is accounted for in the depreciation charge
over the revised remaining proven and probable reserves.
Acquisitions, asset purchases and disposals
Acquisitions of oil and gas properties are accounted for using the acquisition
method when the assets acquired, and liabilities assumed constitute a
business.
Transactions involving the purchase of an individual field interest, or a
group of field interests, which do not constitute a business, are treated as
asset purchases irrespective of whether the specific transactions involve the
transfer of the field interests directly or the transfer of an incorporated
entity. Accordingly, no goodwill and no deferred tax gross up arises, and the
consideration is allocated to the assets and liabilities purchased on an
appropriate basis.
Proceeds on disposal are applied to the carrying amount of the specific
intangible asset or oil and gas property disposed of and any surplus is
recorded as a gain on disposal in the income statement.
Decommissioning
A provision for decommissioning is recognised in full when the related
facilities are installed. The amount recognised is the present value of the
estimated future expenditure. A corresponding amount equivalent to the
provision is also recognised as part of the cost of the related oil and gas
property. This is subsequently depreciated as part of the capital costs of the
production facilities. Any change in the present value of the estimated
expenditure is dealt with from the start of the financial year as an
adjustment to the opening provision and the oil and gas property. The
unwinding of the discount is included as a finance cost.
Non-oil and gas assets
Property, plant and equipment - fixtures and fittings and office equipment
Fixtures and fittings and office equipment are stated at cost less accumulated
depreciation and impairment. Depreciation is provided for on a straight-line
basis at rates sufficient to write off the cost of the assets less any
residual value over their estimated useful economic lives. The depreciation
periods for the principal categories of assets are as follows:
§ Buildings Up to 50 years
§ Fixtures and fittings Up to 10 years
§ Office furniture and equipment Up to 5 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 and discontinued operations
The Group classifies non-current assets and disposal groups as assets held for
sale if their carrying amounts will be recovered principally through a sale
transaction rather than through continuing use. Non-current assets and
disposal groups classified as held for sale are measured at the lower of their
carrying amount and fair value less costs to sell. Costs to sell are the
incremental costs directly attributable to the disposal group, excluding
finance costs and income tax expense. The criteria for held for sale
classification is regarded as met only when the sale is highly probable, and
the asset or disposal group is available for immediate sale in its present
condition. Management must be committed to the plan to sell the asset and the
sale expected to be completed within one year from the date of the
classification. Actions required to complete the sale should indicate that it
is unlikely that significant changes to the sale will be made or that the
decision to sell will be withdrawn. Property, plant and equipment and
intangible assets are not depreciated or amortised once classified as assets
held for sale. Assets and liabilities classified as held for sale are
presented separately as current line items in the balance sheet.
Financial assets
The Group uses two criteria to determine the classification of financial
assets: the Group's business model and contractual cash flow characteristics
of the financial assets. Where appropriate the Group identifies three
categories of financial assets: amortised cost, fair value through profit or
loss (FVTPL), and fair value through other comprehensive income (FVOCI).
Financial assets held at amortised cost
Financial assets held at amortised cost are initially measured at fair value
plus transaction and subsequently measured using the effective interest (EIR)
method and are subject to impairment. The EIR amortisation is presented within
finance income in the income statement.
Cash and cash equivalents
Cash and cash equivalents comprise cash at bank and other short-term highly
liquid investments that are held for the purpose of meeting short-term cash
commitments, readily convertible to a known amount of cash and are subject to
an insignificant risk of changes in value.
Impairment of financial assets
The Group recognises an allowance for expected credit losses (ECLs) for all
debt instruments not held at FVTPL. ECLs are based on the difference between
the contractual cash flows due in accordance with the contract and all the
cash flows that the Group expects to receive, discounted at an approximation
of the original effective interest rate.
ECLs are recognised in two stages:
§ 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.
Provision rates are calculated based on estimates including the probability of
default by assessing counterparty credit ratings, as adjusted for
forward-looking factors specific to the debtors, the economic environment and
the Group's historical credit loss experience.
Credit impaired financial assets
At each reporting date, the Group assesses whether financial assets carried at
amortised cost and debt financial assets carried at FVOCI are credit impaired.
A financial asset is 'credit impaired' when one or more events that have a
detrimental impact on the estimated future cash flows of the financial asset
have occurred.
Evidence that a financial asset is credit impaired includes the following
observable data:
§ 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
Through the acquisition of the Wintershall Dea portfolio, the Group now holds
two series of subordinated resettable fixed rate notes (subordinated notes) in
the aggregate principal amount of €1,500 million, which were transferred to
Harbour on completion of the acquisition. The subordinated notes are callable
three months prior to the first reset date for the NC2026 series and six
months prior to the first reset date for the NC2029 series, and have no
maturity.
Based on their characteristics (mainly no mandatory repayment and no
obligation to pay a coupon except under certain circumstances specified into
the documentation of the subordinated notes) and in compliance with IAS 32:
Financial Instruments: Presentation, the subordinated notes are wholly
classified as equity. On completing the acquisition, the issued subordinated
notes are recognised at fair value, based on market rate as of the acquisition
date. Accrued interest payable to the subordinated notes investors increases
equity, whereas the distribution of interest payments reduces equity.
Derecognition
A financial liability is derecognised when the obligation under the liability
is discharged, cancelled, or expires. When an existing financial liability is
replaced by another from the same lender on substantially different terms, or
the terms of an existing liability are substantially modified, such an
exchange or modification is treated as the derecognition of the original
liability and the recognition of a new liability. The difference in the
respective carrying amounts is recognised in the income statement.
Derivative financial instruments
The Group uses derivative financial instruments such as forward currency
contracts, interest rate swaps, commodity option contracts and commodity swap
arrangements, to hedge its foreign currency risks, interest rate risks and
commodity price risks, respectively. Derivative financial instruments are
initially recognised and subsequently remeasured at fair value. Certain
derivative financial instruments are designated as cash flow hedges in line
with the Group's risk management policies. When derivatives do not qualify for
hedge accounting or are not designated as accounting hedges, changes in the
fair value of the instrument are recognised within the income statement.
A derivative with a positive fair value is recognised as a financial asset
whereas a derivative with a negative fair value is recognised as a financial
liability. Derivatives are not offset in the financial statements unless the
Group has both a legally enforceable right and intention to offset. A
derivative is presented as a non-current asset or a non-current liability if
the remaining maturity of the instrument is more than 12 months and it is not
due to be realised or settled within 12 months. Other derivatives maturing in
less than 12 months and expected to be realised or settled in less than 12
months are presented as current assets or current liabilities.
Cash flow hedges
The effective portion of gains and losses arising from the remeasurement of
derivative financial instruments designated as cash flow hedges are deferred
within other comprehensive income and subsequently transferred to the income
statement in the period the hedged transaction is recognised in the income
statement. When a hedging instrument is sold or expires, any cumulative gain
or loss previously recognised in other comprehensive income remains deferred
until the hedged item affects profit or loss or is no longer expected to
occur. Any gain or loss relating to the ineffective portion of a cash flow
hedge is immediately recognised in the income statement. Hedge ineffectiveness
could arise if volumes of the hedging instruments are greater than the hedged
item of production, or where the creditworthiness of the counterparty is
significant and may dominate the transaction and lead to losses.
Fair values
Fair value is defined as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market
participants at the measurement date. It is determined by reference to quoted
market prices adjusted for estimated transaction costs that would be incurred
in an actual transaction, or by the use of established estimation techniques
such as option pricing models and estimated discounted values of cash flows.
For financial instruments not traded in an active market, the fair value is
determined using appropriate valuation techniques.
Under IFRS 9 Financial Instruments, embedded derivatives are not separated
from a host financial asset, and are classified based on their contractual
terms and the Group's business model.
Equity
Share capital
Share capital includes the total net proceeds, both nominal and share premium,
on the issue of ordinary (voting and non-voting) and preference shares of the
company.
Merger reserve
On 31 March 2021, Harbour Energy plc (formerly Premier Oil plc) acquired
Chrysaor Holdings Limited as part of a reverse acquisition. Under the terms of
the merger, Premier legally acquired Chrysaor through the issuance of
consideration shares whilst Chrysaor was the acquirer for accounting purposes,
primarily as a result of its ability to appoint the Board of the enlarged
group. The merger reserve primarily represented Premier's opening balance on
the legal reserve plus the fair value of the assets and liabilities acquired
by Chrysaor. This was subsequently reduced following a capital restructuring
in 2022.
On 3 September 2024, the company acquisition of the Wintershall Dea assets met
the conditions to recognise the difference between the fair value and nominal
value of the shares issues as consideration as merger reserve.
Capital redemption reserve
The capital redemption reserve represents the nominal value of shares
transferred following the company's purchase of them.
Cash flow hedge reserve
The cash flow hedge and cost of hedging reserves represent gains and losses on
derivatives classified as effective cash flow hedges. Upon the designation of
option instruments as hedging instruments, the intrinsic and time value
components are separated, with only the intrinsic component being designated
as the hedging instrument and the time value component is deferred in other
comprehensive income as a 'cost of hedging'.
Currency translation reserve
This reserve comprises exchange differences arising on consolidation of the
Group's operations with a functional currency other than the US dollar.
Share-based payments
The Group has applied the requirements of IFRS 2 Share-Based Payment. The
Group has share-based awards that are equity and cash settled as defined by
IFRS 2. The fair value of the equity-settled awards has been determined at the
date of grant of the award allowing for the effect of any market-based
conditions. The fair value determined at the grant date of the equity-settled
share-based payments is expensed on a straight-line basis over the vesting
period, based on the Group's estimate of shares that will eventually vest and
adjusted for the effect of non-market based vesting conditions. For
cash-settled awards, a liability is recognised for the goods or service
acquired. This is measured initially at the fair value of the liability. The
fair value of the liability is subsequently remeasured at each balance sheet
date until the liability is settled, and at the date of settlement, with any
changes in fair value recognised in the income statement.
Inventories
All inventories, except for petroleum products, are stated at the lower of
cost and net realisable value. The cost of materials is the purchase cost,
determined on weighted average cost basis. Petroleum products and underlift
and overlift positions are measured at net realisable value using an
observable year-end oil or gas market price, and are included in other debtors
or creditors, respectively.
Leases
Leases are recognised as a right-of-use asset and a corresponding liability at
the date at which the leased asset is available for use by the Group.
Right-of-use assets are measured at cost, less any accumulated depreciation
and impairment losses, and adjusted for any remeasurement of lease
liabilities. The cost of right-of-use assets includes the amount of lease
liabilities recognised, initial direct costs incurred, and lease payments made
at or before the commencement date less any lease incentives received.
Right-of-use assets are depreciated on a straight-line basis over the shorter
of the lease term and the estimated useful lives of the assets which are no
more than ten years.
The Group recognises right-of-use assets and lease liabilities on a gross
basis and the recovery of lease costs from joint operations' partners is
recorded as other income.
Liabilities arising from a lease are initially measured on a present value
basis reflecting the net present value of the fixed lease payments and amounts
expected to be payable by the Group assuming leases run to full term. The
Group has applied judgement to determine the lease term for some lease
contracts in which it is a lessee that include renewal options. The assessment
of whether the Group is reasonably certain to exercise such options impacts
the lease term, which significantly impacts the amount of lease liabilities
and right-of-use assets recognised.
§ The lease payments are discounted at the lease commencement date using the
Group's incremental borrowing rates of between 1.2 per cent and 13.1 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 provision for the estimated CO(2) emissions costs when
actual emissions exceed the emission rights granted and still held. When
actual emissions exceed the amount of emission rights granted, a provision is
recognised for the exceeding emission rights based on the purchase price of
allowances concluded in forward contracts or market quotations at the
reporting date.
Group retirement benefits
The Group's various pension plans consist of both defined benefit and defined
contribution plans. Payments to defined contribution retirement benefit plans
are charged as an expense as they fall due. Payments made to state-managed
retirement benefit schemes are dealt with as payments to defined contribution
plans where the Group's obligations under the schemes are equivalent to those
arising in a defined contribution retirement benefit plan.
The Group operates a defined benefit pension scheme, which requires
contributions to be made to a separately administered fund. The cost of
providing benefits is determined using the projected unit credit method, with
actuarial valuations being carried out at each balance sheet date. Actuarial
gains and losses are recognised immediately in the statement of comprehensive
income.
The retirement benefit obligation recognised in the balance sheet represents
the present value of the defined benefit obligation as reduced by the fair
value of plan assets. Any asset resulting from this calculation is limited to
the present value of available refunds and reductions in future contributions
to the plan.
The Group participates in a legally independent multi-employer plan which is
financed by employer and employee contributions as well as the return on plan
assets. Since sufficient information is not available for this multi-employer
plan, the Group accounts for the plan as if it was a defined contribution
plan.
In the case of contribution-based defined benefit pension plans, the Group
makes contribution payments to special-purpose funds as well as to life
insurances. These contribution payments are recorded as expenses. Furthermore,
for some of the Group`s contribution-based defined benefit pension plans,
benefit obligations are recognised at the fair value of these funds, so far as
the assets exceed the guaranteed minimum benefit amount.
If the assets do not exceed the guaranteed minimum benefit amount, benefit
obligations for these contribution-based benefit plans are recognised in the
guaranteed minimum benefit amount.
The defined benefit plans are administered by a separate fund that is legally
separated from the acquired Wintershall Dea portfolio. The trustees of the
pension fund are required by law to act in the interest of the fund and of all
relevant stakeholders in the plans.
Trade payables
Initial recognition of trade payables is at fair value. Subsequently they are
stated at amortised cost.
Taxes
Current tax
Current tax assets and liabilities for the current and prior periods are
measured at the amount expected to be recovered from or paid to the taxation
authorities. The tax rates and laws used to compute the amount are those that
are enacted or substantively enacted at the reporting date in the countries
where the Group operates and generates taxable income.
Current income tax related to items recognised directly in other comprehensive
income or equity is recognised in other comprehensive income or directly in
equity, not in the income statement.
Management periodically evaluates positions taken in the tax returns with
respect to situations in which tax regulations are subject to interpretation
and establishes provisions where appropriate.
Deferred tax
Deferred taxation is recognised in respect of all temporary differences
arising between the tax bases of the assets and liabilities and their carrying
amounts in the financial statements with the following exceptions:
When the deferred tax liability arises from the initial recognition of
goodwill or an asset or liability in a transaction that is not a business
combination and, at the time of the transaction, affects neither the
accounting profit nor taxable profit or loss and does not give rise to equal
taxable and deductible temporary differences
§ 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 proved and probable reserves and
resources profile and forecast capital and operating expenditures.
Deferred income tax assets and liabilities are offset only if a legally
enforceable right exists to offset current assets against current tax
liabilities, the deferred income tax relates to the same tax authority and
that same tax authority permits the Group to make a single net payment.
Deferred tax is charged or credited in the income statement, except when it
relates to items charged or credited in other comprehensive income, in which
case the deferred tax is also dealt with in other comprehensive income.
Revenue from contracts with customers
Revenue from contracts with customers is recognised when the Group satisfies a
performance obligation by transferring a good or service to a customer. A good
or service is transferred when the customer obtains control of that good or
service. Revenue associated with the sale of crude oil, natural gas and
natural gas liquids (NGLs) is measured based on the consideration specified in
contracts with customers with reference to quoted market prices in active
markets, adjusted according to specific terms and conditions as applicable
according to the sales contracts. The transfer of control of oil, natural gas,
natural gas liquids and other items sold by the Group occurs when title passes
at the point the customer takes physical delivery. The Group principally
satisfies its performance obligations at a point in time and the amounts of
revenue recognised relating to performance obligations satisfied over time are
not significant.
Over/underlift
Differences between the production sold and the Group's share of production
result in an overlift or an underlift. Underlift positions are measured at net
realisable value using an observable year-end oil or gas market price.
Overlift positions are measured using the sales price that generated the
overlift. Underlift and overlift positions are included in receivables or
payables respectively. Movements during the accounting period are recognised
within cost of sales.
Interest income
Interest income is recognised on an accruals basis, by reference to the
principal outstanding and at the effective interest rate applicable.
Borrowing costs
Borrowing costs directly attributable to the acquisition, construction or
production of an asset that necessarily takes a substantial period of time to
get ready for its intended use or sale (a qualifying asset) are capitalised as
part of the cost of the respective assets. Where the funds used to finance a
project form part of general borrowings, the amount capitalised is calculated
using a weighted average of rates applicable to relevant general borrowings of
the Group during the period. All other borrowing costs are recognised in the
income statement in the period in which they are incurred.
New accounting standards and interpretations
The Group applied for the first-time certain standards and amendments, which
are effective for annual periods beginning on or after 1 January 2024 (unless
otherwise stated). The Group has not early adopted any other standard,
interpretation or amendment that has been issued but is not yet effective.
Management anticipates that all relevant pronouncements will be adopted for
the first period beginning on or after the effective date of the
pronouncement. New standards, amendments and interpretations not adopted in
the current year have not been disclosed as they are not expected to have a
material impact on the Group's consolidated financial statements.
Classification of Liabilities as Current or Non-current and Non-current
Liabilities with Covenants - Amendments to IAS 1
The amendments specify the requirements for classifying liabilities as current
or non-current. The amendments clarify:
§ What is meant by a right to defer settlement
§ That a right to defer must exist at the end of the reporting period
§ That classification is unaffected by the likelihood that an entity will
exercise its deferral right
§ That only if an embedded derivative in a convertible liability is itself an
equity instrument would the terms of a liability not impact its classification
In addition, a requirement has been added to disclose when a liability arising
from a loan agreement is classified as non-current and the entity's right to
defer settlement is contingent on compliance with future covenants within
twelve months.
The amendments had no impact on the Group's consolidated financial statements.
Lease Liability in a Sale and Leaseback - Amendments to IFRS 16
The amendments to IFRS 16 specify the requirements that a seller-lessee uses
in measuring the lease liability arising in a sale and leaseback transaction,
to ensure the seller-lessee does not recognise any amount of the gain or loss
that relates to the right of use it retains. The amendments had no impact on
the Group's consolidated financial statements.
Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7
The amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial
Instruments: Disclosures clarify the characteristics of supplier finance
arrangements and require additional disclosure of such arrangements. The
disclosure requirements in the amendments are intended to assist users of
financial statements in understanding the effects of supplier finance
arrangements on an entity's liabilities, cash flows and exposure to liquidity
risk.
The disclosure requirements in the amendments provide information about the
impact of supplier finance arrangements on liabilities and cash flows,
including terms and conditions of those arrangements, quantitative information
on liabilities related to those arrangements as at the beginning and end of
the reporting period and the type and effect of non-cash changes in the
carrying amounts of those arrangements.
The amendments had no impact on the Group's consolidated financial statements.
3. Segment information
The chief operating decision maker, who is responsible for allocating
resources and assessing performance of the Group's business segments, has been
identified as the Chief Executive Officer.
Prior to the acquisition of substantially all of Wintershall Dea's upstream
oil and gas assets, the Group's activities consist of one class of business
being the acquisition, exploration, development and production of oil and gas
reserves and related activities, and were split geographically and managed in
two regions, namely 'North Sea' and 'International'. The North Sea segment
included the UK and Norwegian continental shelves, and the 'International'
segment included Indonesia, Vietnam and Mexico.
The operating segments have been modified following the acquisition of the
Wintershall Dea portfolio and changes in the Group's structure effective from
September 2024. The operating segments are now divided geographically and
managed across nine business units: namely Norway, UK, Germany, Mexico,
Argentina, North Africa, Southeast Asia, CCS and Corporate. The CCS segment
includes Denmark.
Information on major customers can be found in note 4.
Year ended Norway UK Germany Mexico Argentina North Southeast Asia CCS Corporate Total segments Adjustments and eliminations Consolidated
Africa
31 December 2024 $ million $ million $ million $ million $ million
$ million $ million $ million $ million $ million $ million
$ million
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
- Other revenue 90 195 1 - 6 40 - - 12 344 - 344
Other 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)
Impairment of goodwill - - - - - - - - - - - -
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 837 714 (42) 17 18 52 49 (52) 61 1,654 (6) 1,648
profit/(loss)
Finance income 173
Finance expenses (602)
Income tax expense (1,312)
Loss for the year (93)
Total assets 9,434 7,306 3,042 2,420 4,488 917 919 18 1,777 30,321 - 30,321
Total liabilities (6,622) (6,936) (1,965) (482) (1,292) (165) (454) (108) (6,046) (24,070) - (24,070)
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
Year ended Norway UK Germany Mexico Argentina North Southeast Asia CCS Corporate Total segments Adjustments and eliminations Consolidated
Africa
31 December 2023 $ million $ million $ million $ million $ million
$ million $ million $ million $ million $ million $ million
$ million
Revenue and other income
External customers
- Crude oil sales - 1,980 - - - - 106 - - 2,086 - 2,086
- Gas sales - 1,272 - - - - 131 - 12 1,415 - 1,415
- Other revenue - 214 - - - - - - - 214 - 214
Other income - 35 - - - - - - 1 36 - 36
Inter-segment - 28 - - - - - - - 28 (28) -
Total revenue and - 3,529 - - - - 237 - 13 3,779 (28) 3,751
other income
Cost of operations - (2,255) - - - - (149) - - (2,404) 28 (2,376)
Impairment of property, plant and equipment - (172) - - - - - - (4) (176) - (176)
Impairment of right-of-use asset - - - - - - - - - - - -
Impairment of goodwill - - - - - - (25) - - (25) - (25)
Exploration and evaluation expenses and new ventures (6) (1) - - - - - (29) - (36) - (36)
Exploration costs written-off (27) (11) - (13) - - (6) - - (57) - (57)
General and administrative expenses 1 (46) - - - - (4) - (100) (149) - (149)
Segment operating (32) 1,044 - (13) - - 53 (29) (91) 932 - 932
profit/(loss)
Finance income 104
Finance expenses (420)
Income tax expense (571)
Profit for the year 45
Total assets 73 6,083 - 360 - - 905 - 2,495 9,916 - 9,916
Total liabilities (34) (5,818) - (49) - - (483) - (1,979) (8,363) - (8,363)
Total capital additions 24 575 - 44 - - 67 - 11 721 - 721
Total depreciation, depletion and amortisation 1 1,352 - - - - 80 - 16 1,449 - 1,449
4. Revenue from contracts with customers and other income
2024 2023
$ million $ million
Type of goods
Crude oil sales 2,878 2,086
Gas sales 2,936 1,415
Condensate sales 283 179
Total revenue from contracts with customers(1) 6,097 3,680
Tariff income 32 30
Other revenue 29 5
Revenue from production activities 6,158 3,715
Other income(2) 68 36
Total revenue and other income 6,226 3,751
(1) Revenues from contracts with customers of $6,115 million (2023: $4,591
million) include crude oil sales of $2,846 million (2023: $2,179 million) and
gas sales of $2,986 million (2023: $2,233 million). This was prior to realised
hedging gains in the year of $32 million (2023: $93 million, hedging loss) on
crude oil and realised hedging losses in the year of $50 million (2023: $818
million) on gas sales.
(2) Other income mainly represents partner recoveries related to lease
obligations and government subsidies in Argentina. Other income in 2023
includes a receipt related to the Viking CCS Development Agreement that was
signed in March 2023.
Approximately 54 per cent (2023: 88 per cent) of the revenues were
attributable to sales to energy trading companies of the Shell group.
5. Operating profit
Note 2024 2023
$ million As restated
$ million
Cost of operations
Production, insurance and transportation costs 1,612 1,171
Commodity purchases 28 12
Royalties 47 4
Impairment of receivables 21 -
Depreciation of oil and gas assets 12 1,516 1,206
Depreciation of right-of-use oil and gas assets 13 269 235
Capitalisation of IFRS 16 lease depreciation on oil and gas assets 13 (81) (27)
Movement in over/underlift balances and hydrocarbon inventories 201 (225)
Total cost of operations 3,613 2,376
Impairment expense of oil and gas property, plant and equipment 12 178 70
Net impairment loss due to increase in decommissioning provisions on oil and 12 174 106
gas tangible assets
Impairment of goodwill 10 - 25
Impairment of right of use asset 13 20 -
Exploration costs written-off(1) 11 173 57
Exploration and evaluation expenditure and new ventures(1) 68 36
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets 13 16 9
Depreciation of non-oil and gas assets 12 6 3
Amortisation of non-oil and gas intangible assets 11 19 23
Acquisition-related transaction costs 119 33
Other administrative costs(2) 192 81
Total general and administrative expenses(2,5) 352 149
Auditor's remuneration
Audit fees
Fees payable to the company's auditor for the company's Annual Report 6 3
Audit of the company's subsidiaries pursuant to legislation 1 1
Non-audit fees(3)
Other services pursuant to legislation - interim review - -
Other services(4) 2 1
(1) During the year, the Group expensed $241 million (2023: $93 million)
of exploration and appraisal activities. This covers exploration write-off
expense of $173 million (2023: $57 million) including write-off of costs
associated with projects in our UK business unit ($79 million) and licence
relinquishments in Norway ($64 million), and $40 million (2023: $29 million)
costs associated with energy transition projects.
(2) Other administrative costs in 2024 include consultancy and business
development costs of $119 million (2023: $33 million), 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
auditor which is aimed at ensuring their continued independence. This policy
is available on the Group's website. The use of the external auditor for
services relating to accounting systems 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 auditor's objectivity that cannot be
reduced to an acceptable level by applying safeguards.
(4) Other non-audit services in 2024 primarily relate to transaction
related activities including the Wintershall Dea acquisition.
(5) Expenses related to both short-term and low value lease arrangements
are considered to be immaterial for reporting purposes.
6. Staff costs
2024 2023
$ million $ million
Wages and salaries and other staff costs 428 325
Social security costs 46 25
Pension costs 35 29
Total staff costs 509 379
Average annual number of employees employed 2024 2023
by the Group worldwide was:
Number Number
Offshore based 545 534
Onshore and administration 1,614 1,271
Total staff 2,159 1,805
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 27.
The Group operates defined contribution and benefit pension schemes for which
further details are provided in note 28.
7. Finance income and finance expenses
Note 2024 2023
$ million $ million
Finance income
Bank interest 37 19
Other interest and finance gains 16 6
Lease finance income 1 2
Realised gains on foreign exchange forward contracts - 9
Unrealised gains on derivatives(1) - 68
Income from investments 1 -
Foreign exchange gains 118 -
Total finance income 173 104
Finance expenses
Interest payable on reserve based lending facility 1 15
Interest payable on revolving credit facility 10 -
Interest payable on bridge loan facility 8 -
Interest payable on bonds 59 27
Other interest and finance expenses 10 17
Lease interest 13 53 51
Unrealised losses on derivatives(1) 43 -
Realised losses on foreign exchange forward contracts 71 -
Finance expense on deferred revenue 20 5 4
Foreign exchange losses - 57
Bank and financing fees(2) 139 100
Unwinding of discount on decommissioning and other provisions 21 221 156
620 427
Finance costs capitalised during the year(3) (18) (7)
Total finance expense 602 420
(1) Losses on derivatives include mark to market losses on foreign
currency derivatives of $30 million (2023: $nil), derivative ineffectiveness
losses of $8 million (2023: $nil) and $5 million related to changes in the
fair value of an embedded derivative within one of the Group's gas contracts
(2023: $68 million gain).
(2) Bank and financing fees include an amount of $102 million (2023: $48
million) relating to the amortisation of arrangement fees and related costs
capitalised against the Group's long-term borrowings (note 22). This primarily
relates to the expensing of previously capitalised fees in respect of the
Group's reserve based lending (RBL) facility of $61 million at the end of 2023
which was replaced by the new revolving credit facility (RCF) facility as part
of the acquisition of the Wintershall Dea portfolio.
(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 4.5 per cent to the expenditures on the qualifying assets (2023: 6.0
per cent).
8. Income tax
The major components of income tax expense are:
2024 2023
$ million As restated
$ million
Current income tax expense:
Charge for the year 1,413 655
Adjustments in respect of prior years 2 22
Total current income tax expense 1,415 677
Deferred tax credit
Origination and reversal of temporary differences in current year (168) (86)
Impact of changes in tax rates(1) 77 -
Adjustments in respect of prior years (12) (20)
Total deferred tax credit (103) (106)
Total tax expense reported in the income statement 1,312 571
The tax (credit)/expense in the statement of comprehensive income is as
follows:
Tax (credit)/expense on cash flow hedges (379) 2,376
Tax credit on cash actuarial gains and losses (4) -
Total tax (credit)/expense reported in the statement of comprehensive income (383) 2,376
(1) The amounts for 2024 comprise the impact of the increase in Energy
Profits Levy in the UK business unit 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:
2024 2023
$ million As restated
$ million
Profit before income tax 1,219 616
At the Group's statutory tax rate of 78 per cent (2023: 75 per cent) 951 462
Effects of:
Expenses not deductible for tax purposes 59 103
Adjustments in respect of prior years (10) 2
Remeasurement of deferred tax 53 13
Deferred Energy Profits Levy change in rate 77 -
Impact of different tax rates 282 73
Allowances and other tax uplifts (113) (82)
Future dividends from investments in subsidiaries, branches and associates (11) -
Other 24 -
Total tax expense reported in the consolidated income statement at the 1,312 571
effective tax rate of 108 per cent (2023: 93 per cent, restated)
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. In 2023, the tax expense was prepared based on the
statutory rate of taxation of 75 per cent applying to UK oil and gas
production because the majority of the Group's profit was generated in the UK
Continental Shelf.
The effective tax rate for the year is 108 per cent, compared to 93 per cent
for 2023 (restated).
The effective tax rate of 108 per cent is significantly higher than the
statutory rate of 78 per cent for the Group, mainly due to several UK-specific
exceptional items impacting the UK tax expense. These items, resulting from
the application of Energy Profits Levy (EPL), create tax rate differences
reflected in the income statement. Notably, the increase in the UK asset
retirement obligation raised the effective tax rate by 15 per cent as there is
no tax relief available against EPL for expenditure on abandonment.
Additionally, exploration write-offs and impairments of tangible assets in the
UK, which carried blended deferred tax liabilities up to the enacted EPL
sunset clause date of 31 March 2028, increased the effective tax rate by
another 4 per cent. Finally, the EPL rate change from 35 per cent to 38 per
cent added 6 per cent to the effective tax rate. Overall, these EPL-related
adjustments resulted in an additional 25 per cent increase in the Group's
effective tax rate.
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.
Deferred tax
The principal components of deferred tax are set out in the following tables:
Note 2024 2023
$ million As restated
$ million
Deferred tax assets 130 7
Deferred tax liabilities (6,240) (1,297)
(6,110) (1,290)
Reclassification of deferred tax liabilities directly associated with assets 18 19 -
held for sale
Total deferred tax (6,091) (1,290)
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 Decom-missioning Losses Fair Other(1) Overseas Total
value of derivatives
allowances $ million $ million
$ million $ million $ million
$ million
$ million
As at 1 January 2023 (3,396) 1,565 569 2,452 (3) (178) 1,009
Deferred tax credit/(expense) 546 (25) (388) (61) 22 18 112
Comprehensive income - - - (2,376) 1 - (2,375)
Foreign exchange (51) 34 - (9) 1 (5) (30)
As at 31 December 2023 (2,901) 1,574 181 6 21 (165) (1,284)
Restated - - - - - (6) (6)
As at 31 December 2023 as restated (2,901) 1,574 181 6 21 (171) (1,290)
Deferred tax (expense)/credit (44) 257 (114) (38) 42 - 103
Comprehensive income - - - 380 4 - 384
Other reserves(2) - - - - (1) - (1)
Additions from business combinations (6,509) 971 201 (14) (2) - (5,353)
Reclassifications(3,4) (221) 7 28 15 171 -
Foreign exchange 75 (18) (8) 2 (4) - 47
As at 31 December 2024 (9,600) 2,791 288 336 75 - (6,110)
(1) Includes deferred tax movements related to investment allowances,
share-based payments and pensions.
(2) Movement in other reserves relates to the element of deferred tax on
UK share-based payments taken to profit and loss reserves.
(3) Items classified as overseas balances in 2023 have been reclassified
into specific deferred tax categories.
(4) Balances related to UK investment allowances ($12 million) have been
reclassified from accelerated capital allowances to other
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 UK
decommissioning deferred tax asset is additionally supported by the ability to
carry back decommissioning tax losses and set these against ring fence taxable
profits of prior periods.
In October 2024, the UK Government announced changes to the EPL, including an
increase in the rate from 35 per cent to 38 per cent, the removal of the main
EPL investment allowance and an extension of the EPL to 31 March 2030. The
three per cent increase in the rate and the removal of the main EPL investment
allowance were substantively enacted at the balance sheet date and have effect
from 1 November 2024. As a result, the current accounting period reflects an
additional deferred tax expense of $77 million, based on the currently enacted
expiration date of the EPL of 31 March 2028 and the remeasurement of temporary
differences expected to reverse within this period. The extension of the EPL
to 31 March 2030 was substantively enacted on 3 March 2025 and is therefore
not reflected in the financial statements as at 31 December 2024. This impact
will be included in the financial statements for the following period. If the
extension had been in place at the balance sheet date, an additional deferred
tax expense of $306 million would have been recognised in the current
financial statements.
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 deferred tax liability for the period is
$6,110 million (2023: $1,290 million), of which $877 million (2023: $1,014
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 $50 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 $2,743 million (2023: $1,290 million). These other deductible
temporary differences include unclaimed tax depreciation, unrealised losses on
non-commodity derivatives and decommissioning related provisions.
2024 2023
$ million $ million
Tax losses by expiry date
Expiring within 5 years 477 24
Expiring within 6-10 years 240 13
No expiration 1,621 1,115
2,338 1,152
Other deductible temporary differences and allowances 405 138
Total unrecognised tax losses and allowances 2,743 1,290
No deferred tax liabilities were recognised for temporary differences
associated with investments in subsidiaries, branches and associates of
approximately $293 million (2023: $nil) 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 does not expect a material exposure to Pillar Two income taxes in any
jurisdictions.
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 2023, an uncertain tax position was identified in certain UK subsidiaries
relating to the timing of the taxation of fair value movements and realised
gains and losses on hedges entered into to manage commodity price risk. On the
strength of independent advice, management considers that there is no
expectation of a net additional outflow of funds. As such no additional
liability has been recognised in the consolidated financial statements as at
31 December 2024. However, a contingent liability exists as the UK tax
authorities could take an alternative view on whether the fair value movements
on the hedged instruments are disregarded for tax purposes. While not
considered a likely outcome, if the UK tax authorities were to disagree and
successfully challenge the position, a possible liability currently estimated
not to exceed $130 million could arise because of the differences in tax rates
across the periods in question.
9. (Loss)/earnings per share (EPS)
Basic EPS is calculated by dividing the profit after tax attributable to
ordinary shareholders of the Group by the weighted average number of ordinary
shares in issue during the year.
Diluted EPS is calculated by dividing the profit after tax attributable to
ordinary shareholders by the weighted average number of ordinary share in
issue during the year plus the weighted average number of ordinary shares that
would be issued on conversion of all the dilutive potential ordinary shares
into ordinary shares.
The following table reflects the income and share data used in the basic and
diluted EPS calculations:
2024 2023
As restated
(Loss)/earnings for the year ($ millions)
Earnings for the purpose of basic earnings per share (108) 45
Effect of dilutive potential ordinary shares - -
(Loss)/earnings for the purpose of diluted earnings per share (108) 45
Number of ordinary shares (millions)
Weighted average number of ordinary shares (voting) for the purpose of basic 990 804
earnings per share
Weighted average number of ordinary shares (non-voting) for the purpose of 93 -
basic earnings per share
Weighted average number of ordinary shares (voting) for the purpose of diluted 990 806
earnings per share(1)
Weighted average number of ordinary shares (non-voting) for the purpose of 93 -
diluted earnings per share
(Loss)/earnings per share ($ cents)
Basic:
Ordinary shares voting (10) 6
Ordinary shares non-voting (11) -
Diluted:
Ordinary shares voting (10) 6
Ordinary shares non-voting (11) -
(1) 2023 excludes certain share options outstanding at 31 December 2023 as
their option price was greater than market price.
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.
Note 2024 2023
$ million $ million
Cost and net book value
At 1 January 1,302 1,327
Additions from business combinations 14 3,845 -
Impairment charge - (25)
At 31 December 5,147 1,302
Goodwill is allocated as follows to the operating segments:
2024 2023
$ million $ million
Cost and net book value
Norway 2,651 -
UK 1,278 1,278
Germany 401 -
Mexico 199 -
Argentina 594 -
Southeast Asia 24 24
At 31 December 5,147 1,302
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.
At the year-end, the Group tested for impairment in accordance with the
accounting policy and no goodwill impairment was recognised (2023: $25
million). 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 cash flows have been modelled on a post-tax and post-decommissioning
basis, inflated at 2.5 per cent per annum from 1 January 2028, and discounted
at the Group's post-tax discount rate of between 8.75 per cent and 14.5 per
cent (2023: 9.0 - 12.4 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 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
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 the market 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
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 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 2028, are derived
from the Group's business plan.
Discount rates
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 $81 million goodwill impairment. A 1 per cent increase in the
discount rate would result in an impairment to goodwill of $10 million.
11. Other intangible assets
Note Oil and gas Non-oil and gas assets(1) Carbon allowances Total
$ million
assets $ million $ million
$ million
Cost
At 1 January 2023 817 137 - 954
Additions during the year 210 20 - 230
Transfers from property, plant and equipment 12 - 7 - 7
Reclassification from trade and other receivables - - 86 86
Increase in decommissioning asset 21 4 - - 4
Exploration write-off (57) - - (57)
Currency translation adjustment 42 8 - 50
At 31 December 2023 1,016 172 86 1,274
Additions during the year 398 51 36 485
Additions from business combinations and joint arrangements 4,407 2 - 4,409
Transfers from property, plant and equipment 12 (39) 1 - (38)
Increase in decommissioning asset 21 12 - - 12
Exploration write-off(2) (173) - - (173)
Utilised - - (54) (54)
Disposals - (42) - (42)
Currency translation adjustment (76) (3) (3) (82)
At 31 December 2024 5,545 181 65 5,791
Amortisation
At 1 January 2023 - 74 - 74
Charge for the year - 23 - 23
Currency translation adjustment - 5 - 5
At 31 December 2023 - 102 - 102
Charge for the year - 19 - 19
Disposals - (42) - (42)
Currency translation adjustment - (2) - (2)
At 31 December 2024 - 77 - 77
Net book value
At 31 December 2023 1,016 70 86 1,172
At 31 December 2024 5,545 104 65 5,714
(1) Non-oil and gas assets relate to Group IT software of $71 million and
carbon capture and storage activities, mainly related to the Viking CCS
project of $33 million.
(2) The exploration write-off of $173 million (2023: $57 million) includes
the write off of costs associated with projects in the UK ($79 million) and
licence relinquishments in Norway ($64 million).
12. Property, plant and equipment
Note Oil and gas Fixtures and fittings & office equipment Land and Total
$ million
assets $ million buildings(1)
$ million $ million
Cost
At 1 January 2023 11,436 38 - 11,474
Additions 482 9 - 491
Transfers to intangible assets 11 - (7) - (7)
Reclassification of asset held for sale (198) - - (198)
Decrease in decommissioning asset 21 (22) - - (22)
Currency translation adjustment 159 2 - 161
At 31 December 2023 11,857 42 - 11,899
Restated 198 - - 198
At 31 December 20223 as restated 12,055 42 - 12,097
Additions(2) 1,037 21 1 1,059
Additions from business combinations and joint arrangements 14 9,951 20 40 10,011
Transfers from intangible assets 11 39 - (1) 38
Reclassification of asset held for sale 18 (198) - - (198)
Increase in decommissioning asset(3) 21 760 - - 760
Disposals (1) (24) - (25)
Currency translation adjustment (258) (2) (2) (262)
At 31 December 2024 23,385 57 38 23,480
Accumulated depreciation
At 1 January 2023 5,760 24 - 5,784
Charge for the year 1,192 3 - 1,195
Impairment charge 214 - - 214
Reclassification of asset held for sale (103) - - (103)
Currency translation adjustment 91 1 - 92
At 31 December 2023 7,154 28 - 7,182
Restated 79 - - 79
At 31 December 2023 as restated 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 18 (124) - - (124)
Disposals (1) (24) - (25)
Currency translation adjustment (49) - - (49)
At 31 December 2024 8,927 9 1 8,937
Net book value:
At 31 December 2023 as restated 4,822 14 - 4,836
At 31 December 2024 14,458 48 37 14,543
(1) Land and buildings include investment property of $2.6 million (2023:
$nil).
(2) Included within property, plant and equipment additions of $1,059
million (2023: $491 million) are associated cash flows of $884 million (2023:
$496 million) and non-cash flow movements of $175 million (2023: $5 million)
represented by a $93 million increase in capital accruals (2023: $30 million
decrease), $64 million of capitalised lease depreciation (2023: $18 million)
and $18 million of capitalised interest (2023: $7 million).
(3) An increase in the decommissioning assets of $760 million (2023: $22
million) was made during the year as a result of both an update to the
decommissioning estimates and new obligations (note 21).Impairment assessments
During the year, the Group recognised a pre-tax impairment charge of $352
million (post-tax $185 million) (2023: $176 million; post-tax $83 million).
This comprised a pre-tax impairment charge representing a write-down of
property, plant and equipment assets of $163 million (2023: $70 million)
across three fields in the UK, 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. A
pre-tax impairment charge of $174 million (2023: $106 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 2023, a net pre-tax impairment charge of $176 million was recognised as a
result of impairments on two UK CGUs of $70 million, one driven by a reduction
in the gas price forward curve and the other by a revised decommissioning cost
profile, and a pre-tax impairment charge of $106 million in respect of
revisions to decommissioning estimates on the Group's non-producing assets
with no remaining net book value.
Key assumptions used in calculations
Assumptions used in impairment measurement include estimates of commercial
reserves and production volumes, future oil and gas prices, discount rates and
the level and timing of expenditures, all of which are inherently uncertain.
Commodity and carbon prices
The Group uses the fair value less cost of disposal method (FVLCD) to
calculate the recoverable amount of the cash-generating units (CGU) consistent
with a level 3 fair value measurement (see note 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. The long-term commodity prices used were
$78 per barrel for Brent crude, 80 pence per therm for UK NBP gas and the
European gas price at 2 per cent higher than UK NBP.
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 or increases in the long-term oil and gas prices of 10 per cent are
considered to be reasonably possible changes for the purpose of sensitivity
analysis. As shown in note 2 of the financial statements, the decreases to the
long-term oil and gas prices from 2028 specified above would result in a
further pre-tax impairment of $330 million (post-tax $99 million) and
increases to the long-term oil and gas prices would result in a no material
change to the impairment charge.
Considering the discount rates, the Group believes a one per cent increase in
the post-tax discount rate is considered to be a reasonable possibility for
the purpose of sensitivity analysis. A one per cent increase in the post-tax
discount rate would lead to a further pre-tax impairment of $113 million
(post-tax $33 million) on oil and gas assets and $10 million on goodwill, and
a one per cent decrease in the post-tax discount rate would lead to a lower
pre-tax impairment charge of $129 million (post-tax $41 million).
13. Leases
This note provides information for leases where the Group is a lessee.
Balance sheet
Right-of-use assets Note Land and buildings Drilling FPSO Offshore facilities Equipment Total
rigs
$ million
$ million
$ million $ million $ million
$ million
Cost
At 1 January 2023 88 169 562 334 20 1,173
Additions during the year 25 - - - 1 26
Cost revisions/remeasurements 1 48 63 (6) 4 110
Reclassification of asset held for sale 2 (5) - (71) - - (76)
Disposals (4) (19) - - - (23)
Currency translation adjustment 4 10 - - 1 15
At 31 December 2023 109 208 554 328 26 1,225
Restated 5 - 71 - - 76
At 31 December 2023 as restated 114 208 625 328 26 1,301
Additions during the year(1) 27 166 - - - 193
Additions from business combinations and joint arrangements(1) 55 4 - - 47 106
Cost revisions/remeasurements 6 38 3 32 (11) 68
Reclassification of asset held for sale 18 - - (71) - (2) (73)
Disposals (5) - - - - (5)
Currency translation adjustment (3) (5) - - (1) (9)
At 31 December 2024 194 411 557 360 59 1,581
Accumulated depreciation
At 1 January 2023 26 129 209 61 13 438
Charge for the year 9 42 94 89 5 239
Reclassification of asset held for sale 2 (2) - (23) - - (25)
Disposals (4) (19) - - - (23)
Currency translation adjustment 1 7 - - 1 9
At 31 December 2023 30 159 280 150 19 638
Restated 2 - 29 - - 31
As 31 December 2023 as restated 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 18 - - (40) - - (40)
Disposals (5) - - - - (5)
Currency translation adjustment (1) (3) - - - (4)
At 31 December 2024 62 255 352 226 30 925
Net book value
At 31 December 2023 as restated 82 49 316 178 7 632
At 31 December 2024 132 156 205 134 29 656
(1) Additions of $299 million including $106 million related to business
combinations (note 14) were made to the right-of-use assets during the year
(2023: total additions of $26 million related to new land and buildings).
(2) The impairment charge of $20 million relates to one of the Group's
office buildings in the UK.
Lease liabilities Note 2024 2023
$ million As restated
$ million
At 1 January as restated 768 825
Additions 193 28
Additions from business combinations and joint arrangements 14 118 -
Remeasurement 67 110
Finance costs charged to income statement 7 53 51
Finance costs charged to decommissioning provision 21 1 1
Reclassification of liabilities as held for sale 18 (78) -
Lease payments (319) (262)
Currency translation adjustment (11) 15
At 31 December 792 768
Classified as:
Current 241 216
Non-current 551 552
Total lease liabilities 792 768
The significant portion of the Group's lease liabilities represent lease
arrangements for an FPSO vessel on the Catcher asset, and offshore facilities
on the Tolmount asset oil and gas infrastructure assets 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
Depreciation charge of right-of-use assets Note 2024 2023
$ million $ million
Land and buildings - non-oil and gas assets(1) 35 8
Land and buildings - oil and gas assets 1 1
Drilling rigs 99 42
FPSO 83 99
Offshore facilities 77 89
Equipment - non-oil and gas assets 1 1
Equipment - oil and gas assets 9 4
305 244
Capitalisation of IFRS 16 lease depreciation(2)
Drilling rigs (77) (25)
Equipment (4) (2)
Depreciation charge included within consolidated income statement 224 217
Lease interest 7 53 51
(1) Includes impairment charge of $20 million related to one of the
Group's office building in the UK.
(2) Of the $81 million (2023: $27 million) capitalised IFRS 16 lease
depreciation, $64 million (2023: $18 million) has been capitalised within
property, plant and equipment and $17 million (2023: $9 million) within
provisions (note 21).
The total cash outflow for leases in 2024 was $319 million (2023: $259
million).
14. Business combinations
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 increases
production capacity and provides geographic diversification, adding high
quality assets with material positions in Norway, Germany, Argentina, North
Africa and Mexico. It also strengthens 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, are provisional and will be
finalised in Harbour's full year 2025 financial statements. The provisional
fair values of the net identifiable assets as at the date of acquisition are
as follows:
Note Fair value recognised on acquisition
$ million
Non-current assets
Other intangible assets 11 4,409
Property, plant and equipment 12 10,011
Right-of-use assets 13 106
Deferred tax assets 8 147
Other receivables 16 56
Other financial assets 23 52
Current assets
Inventories 15 213
Trade and other receivables 16 1,305
Other financial assets 23 188
Cash and cash equivalents 17 748
Total assets 17,235
Non-current liabilities
Borrowings 22 3,038
Provisions 21,28 2,616
Deferred tax 8 5,500
Trade and other payables 20 25
Lease creditor 13 86
Other financial liabilities 23 99
Current liabilities
Trade and other payables 20 1,134
Borrowings 22 41
Lease creditor 13 32
Provisions 21,28 324
Current tax liabilities 8 1,128
Other financial liabilities 23 218
Total liabilities 14,241
Fair value of identifiable net assets acquired 2,994
Subordinated notes measured at fair value(1) 26 (1,548)
Goodwill arising on acquisition 10 3,845
Purchase consideration transferred 5,291
(1) Subordinated notes accounted for within equity, see note 26.
The fair values of the oil and gas assets and intangible assets acquired have
been determined using valuation techniques based on discounted cash flows
using forward curve commodity prices and estimates of long-term prices
consistent with those applied by management when testing assets for
impairment, a discount rate based on market observable data and cost and
production profiles generally consistent with the 2P and a component of 2C
reserves, if applicable, acquired with each asset. Where applicable, other
observable market information has also been used.
The decommissioning provisions recognised have been estimated based on
Harbour's internal estimates with reference to observable market data,
including rig rates.
The equity consideration settled in ordinary shares of $2,513 million has been
calculated based on 669,714,027 BASF consideration shares being issued by the
company at a 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.
The equity consideration settled in non-voting shares of $944 million has been
calculated based on 251,488,211 non-voting shares being issued at their fair
value, measured in accordance with IFRS 13 Fair Value Measurement. A binomial
lattice valuation methodology has been utilised to determine the fair value of
the non-voting shares based on the value of ordinary shares with inputs that
reflect the different features of these shares. Key assumptions input into the
fair value model include: timing and quantum of future dividend payments;
estimates of the timing of lifting of relevant sanctions on the minority
ultimate beneficial owners of LetterOne; estimated date of conversion to
ordinary shares under certain conditions; expected volatility of ordinary
shares; appropriate discount rate; and discount for lack of marketability. The
resultant fair value of a non-voting share has been determined to closely
approximate that of an ordinary share, £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.
The acquisition date fair value of the trade receivables amounts to $936
million. The gross amount of trade receivables is $1,015 million, which is
expected to be collected within contractual terms.
The fair value of the subordinated notes has been determined by reference to
quoted market prices in Euros translated to US dollars at the exchange rate
prevailing on the date of acquisition.
The goodwill of $3,845 million 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.
From the date of acquisition, the Wintershall Dea assets contributed $2,021
million of revenue and $867 million to profit before tax from continuing
operations of the Group. If the combination had taken place at the beginning
of the year, revenue from continuing operations would have been $10,516
million and profit before tax from continuing operations for the Group would
have been $3,017 million.
$ million
Purchase consideration
Shares issued, at fair value 3,457
Cash paid 1,782
Contingent consideration 52
Total consideration 5,291
Analysis of cash flows on acquisition:
Transaction costs of the acquisition (included in cash flows from operating (118)
activities)
Net cash acquired with the subsidiaries (included in cash flows from investing 748
activities)
Transaction costs attributable to issuance of shares (included in cash flows (1)
from financing activities, net of tax)
Net cash flow on acquisition 629
It should be noted that, at the date of completion, a cash payment of $1,792
million was made to the former owners of Wintershall Dea. This payment is
reflected in the consolidated statement of cash flows. Subsequently, and as
contemplated by the business combination agreement, a reduction in cash
consideration payable of $10 million was identified, reducing the cash
consideration to $1,782 million. This is reflected in the fair value of
consideration above. As the review period is ongoing, and further adjustments
may be identified, this $10 million has not yet been repaid to the company.
Transaction costs of $119 million (2023: $33 million) were expensed and are
included in administrative expenses.
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).
15. Inventories
2024 2023
$ million As restated
$ million
Hydrocarbons 56 49
Consumables and subsea supplies 312 168
Total inventories 368 217
Inventories of consumables and subsea supplies include a provision of $39
million (2023: $28 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 2024
amounted to $7 million (2023: $1 million). These expenses are included within
production costs.
16. Trade and other receivables
2024 2023
$ million As restated
$ million
Trade receivables 1,203 372
Underlift position 175 146
Other debtors 249 86
Prepayments and accrued income 631 223
Corporation tax receivable 58 46
Total trade and other receivables 2,316 873
Trade receivables are non-interest bearing and are generally on 20-to-30-day
terms. As at 31 December 2024, there were $433 million of trade receivables
that were past due (2023: $nil), primarily relating to operations in the
Mexico and North Africa segments.
Prepayments and accrued income mainly comprise amounts due, but not yet
invoiced, for the sale of oil and gas.
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 2024 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 2024.
Other long-term receivables
2024 2023
$ million As restated
$ million
Net investment in sublease - 37
Decommissioning funding asset(1) 59 56
Other receivables(2) 107 216
Prepayments and accrued income 10 -
Total other long-term receivables 176 309
(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 2024, a long-term
decommissioning funding asset of $59 million (2023: $56 million) has been
recognised.
(2) Other receivables includes $44 million in cash held in escrow accounts
for expected future decommissioning expenditure in Indonesia (2023: $39
million). Other receivables at December 2023 also included $21 million held as
security for the Mexican letters of credit, and $42 million related to the
non-current element of the unamortised portion of issue costs and bank fees
related to the RBL (see note 22).
17. Cash and cash equivalents
2024 2023
$ million As restated
$ million
Cash at banks and in hand 805 286
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 2024 were amounts in
Argentina totalling $173 million (2023: $nil) subject to currency controls or
other legal restrictions. In addition, the cash and cash equivalents balance
includes an amount of $43 million (2023: $nil) required to cover initial
margin on trading exchanges, counterparty margining on outstanding commodity
trades and all other balances subject to restriction.
18. Assets held for sale
In December 2024, the Group entered into an exclusivity agreement to sell its
business in Vietnam, which holds 53.125 per cent interest in the Chim Sáo and
Dua producing fields, to EnQuest for a consideration of $84 million. The
transaction has an effective date of 1 January 2024. The assets and
liabilities of Vietnam have been classified as assets held for sale in the
balance sheet as at 31 December 2024, as completion is expected to be achieved
by the second quarter of 2025.
The Group's Vietnam operations are included in the Southeast Asia segment,
previously International, however are not considered a major geographical area
or line of business and therefore the disposal has not been classified as
discontinued operations.
In the prior period, the Vietnam business had also been classified as held for
sale based on a prior agreement. In August 2023, the Group had entered into a
Sale and Purchase Agreement to sell its business in Vietnam to Big Energy
Joint Stock Company, however this was terminated in May 2024. As a result the
Vietnam business was declassified as assets held for sale. Therefore, the
relevant amounts presented as assets held for sale in 31 December 2023 have
been reclassified to reflect this.
The major classes of assets and liabilities of the Group as held for sale as
at 31 December 2024 are as follows:
Note 2024
$ million
Current
Assets
Property, plant and equipment 12 74
Right-of-use-assets 13 33
Other receivables and working capital 170
Assets held for sale 277
Liabilities
Provisions 21 90
Lease creditor 13 78
Trade and other payables 46
Deferred tax 8 19
Liabilities directly associated with assets held for sale 233
Net assets directly associated with disposal group 44
Impairment loss recorded 10
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 2024, a post-tax impairment of $10 million was recognised as the fair
value less cost to sell, being the expected consideration adjusted for items
agreed under the SPA, was below the carrying amount of the disposal group.
Following the impairment charge the net assets directly associated with the
disposal group held on the consolidated balance sheet was $44 million.
19. Commitments
Capital commitments
As at 31 December 2024, the Group had commitments for future capital
expenditure amounting to $1,690 million (2023: $389 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
2024 2023
$ million As restated
$ million
Current
Trade payables 1,365 680
Overlift position 207 33
Other payables 132 144
Matured financial instruments 27 48
Deferred income(1) 24 10
1,755 915
Non-current
Other payables 19 13
Deferred income(1) 11 -
30 13
(1) Deferred income includes $19 million (2023: $nil) relating to payments
for oil not yet delivered and $5 million (2023: $10 million) in relation to
the closing year-end fair value payable to FlowStream who historically
provided funding for the Solan asset in the UK in return for a share in
production.
21. Provisions
Decom--missioning provision Pension provision Employee obligation provision Onerous contract provision Other provisions Total
$ million $ million $ million $ million $ million $ million
At 1 January 2023 4,141 - 24 - - 4,165
Additions 40 - - - - 40
Changes in estimates - decrease to oil and gas tangible decommissioning assets (203) - - - - (203)
Changes in estimates on oil and gas tangible assets - debit to income 141 - - - - 141
statement
Changes in estimate on oil and gas intangible assets - debit to income 4 - - - - 4
statement
Changes in estimate - debit to income statement - - 3 - - 3
Amounts used (248) - - - - (248)
Reclassification of liabilities directly associated with assets held for sale (87) - - - - (87)
Interest on decommissioning lease (1) - - - - (1)
Depreciation, depletion and amortisation on decommissioning right-of-use (9) - - - - (9)
leased asset
Unwinding of discount 156 - - - - 156
Currency translation adjustment 87 - - - - 87
At 31 December 2023 4,021 - 27 - - 4,048
Restated 87 - - - - 87
At 31 December 2023 as restated 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)
At 31 December 2024 7,114 46 68 35 258 7,521
Classified within Non-current liabilities Current liabilities Total
$ million $ million $ million
At 31 December 2023 3,905 230 4,135
At 31 December 2024 7,024 497 7,521
All of the $36 million decommissioning provision additions relate to oil and
gas tangible assets (2023: $40 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 (2023: 2.5 per cent per annum) and discounted at a
risk-free rate of between 2.2 per cent and 6.6 per cent (2023: 4.3 per cent
and 5.2 per cent) reflecting a 6-month (2023: six-month) rolling average of
market rates over the varying lives of the assets to calculate the present
value of the decommissioning liabilities. The unwinding of the discount is
presented within finance costs.
These provisions have been created based on internal and third-party
estimates. Assumptions based on the current economic environment have been
made, which management believe are a reasonable basis upon which to estimate
the future liability. These estimates are reviewed regularly to consider any
material changes to the assumptions. However, actual decommissioning costs
will ultimately depend upon market prices for the necessary decommissioning
work required, which will reflect market conditions at the relevant time. In
addition, the timing of decommissioning liabilities will depend upon the dates
when the fields become economically unviable, which in itself will depend on
future commodity prices and climate change, which are inherently uncertain.
Pension provision
Please refer to note 28 for pension provisions.
Employee obligation provisions
Employee obligation provisions of $68 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 $26 million (2023: $27 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 $35 million (2023: $nil) relates to working
programmes in Libya due to force majeure conditions in-country.
Other provisions
Other provisions mainly includes a $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 $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:
2024 2023
$ million $ million
Reserves-based lending (RBL) facility 5,011 493
Bond 218 -
Other loans - 16
Total borrowings 5,229 509
Classified within:
Current liabilities 4,215 493
Non-current liabilities 1,014 16
Total provisions 5,229 509
Bonds
31 December 2024
% Maturity Currency Nominal value €/$ million Fair value Carrying value
$ million
$ million
Bond ISIN: XS2054209833 0.8 2025 EUR 1,000 1,019 1,014
Bond ISIN: US411618AB75/ USG4289TAA19 5.5 2026 USD 500 499 496
Bond ISIN: XS2054210252 1.3 2028 EUR 1,000 962 954
Bond ISIN: XS2908093805 3.8 2029 EUR 700 729 720
Bond ISIN: XS2055079904 1.8 2031 EUR 1,000 905 901
Bond ISIN: XS2908095172 4.4 2032 EUR 900 940 926
In October 2021, Harbour Energy Finance Limited, a subsidiary of Harbour,
issued a $500 million bond under Rule 144A and with a tenor of five years to
maturity. The coupon was set at 5.50 per cent and interest is payable
semi-annually.
Under the terms of the business combination entered into between the company,
BASF and LetterOne, three existing Wintershall Dea bonds were ported to
Harbour Energy on completion of the acquisition.
As at 31 December 2024, the fair value of these bonds, which is determined
using quoted market prices in an active market, amounts to $2,886 million. The
repayment obligation remains at €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. 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.
The previous reserves based lending (RBL) facility was replaced upon
completion of the acquisition by the new bridge and revolving credit facility
(RCF).
At the balance sheet date, the outstanding RCF balance, excluding incremental
arrangement fees, related costs and letters of credit, was $250 million (2023:
RBL $nil). As at 31 December 2024, $1,854 million remained available for
drawdown under the RCF (2023: $1,972 million under the RBL).
The Group has facilities to issue up to $1,750 million of letters of credit
(2023: $1,750 million), of which $871 million (2023: $1,186 million) was in
issue as at 31 December 2024, mainly in respect of future decommissioning
liabilities.
Arrangement fees and related costs of $276 million were capitalised when the
three existing Wintershall Dea bonds were ported to Harbour Energy on
completion of the acquisition. In addition, $34 million of arrangement fees
and related costs in relation to the RCF, $13 million in relation to the
bridge facility and $11 million related to the €700 million and €900
million senior notes, were capitalised during the year. $102 million of
arrangement fees and related costs were amortised during the year and are
included within financing costs, including $66 million related to the RBL
facility and $13 million related to the bridge facility, upon termination of
those facilities.
At 31 December 2024, $284 million of arrangement fees and related costs remain
capitalised (2023: $68 million). $32 million of these arrangement fees relate
to the RCF, and a further $252 million (2023: $7 million) relate to the bond
facilities.
Interest of $34 million on the bonds and RCF facilities (Dec 2023: $6 million
related to the $500 million bond interest) had accrued by the balance sheet
date and has been classified within accruals.
Other loans at 31 December 2023 represent a commercial financing arrangement
with Baker Hughes (formerly BHGE) was repaid in full in December 2024.
The table below details the change in the carrying amount of the Group's
borrowings arising from financing cash flows:
$ million
Total borrowings as at 1 January 2023 1,238
Proceeds from drawdown of borrowing facilities 660
Repayment of RBL (1,435)
Repayment of financing arrangement (21)
Repayment of exploration finance facility loan (11)
Arrangement fees and related costs capitalised (34)
Financing arrangement interest payable 3
Amortisation of arrangement fees and related costs 48
Reclassification of RBL arrangement fees and related costs to current and 61
non-current assets
Total borrowings as at 31 December 2023 509
Reclassification of capitalised RBL arrangement fees and related costs as (61)
borrowings
Proceeds from RBL facility 178
Repayment of RBL facility (178)
Proceeds from issue of bridge facility 1,500
Repayment of bridge facility (1,500)
Bond debt arising on business combination (net of arrangement fees and related 3,038
costs)
Proceeds from issue of new bonds 1,728
Proceeds from issue of revolving credit facility 2,225
Repayment of revolving credit facility (1,975)
Arrangement fees and related costs capitalised (58)
Amortisation of arrangement fees and related costs 102
Repayment of financing arrangement (17)
Financing arrangement interest payable 1
Currency translation adjustment on Euro bonds (263)
Total borrowings as at 31 December 2024 5,229
23. Other financial assets and liabilities
The Group held the following financial instruments at fair value at 31
December 2024. The fair values of all derivative financial instruments are
classified in accordance with the hierarchy described in IFRS 13.
31 December 2024 31 December 2023
Current Assets Liabilities Assets Liabilities
$ million
$ million $ million $ million
Measured at fair value through profit and loss
Foreign exchange derivatives - (25) 6 -
Commodity derivatives 26 (14) - -
Short term investments 25 - - -
Fair value of embedded derivative within gas contract 5 - 10 -
56 (39) 16 -
Measured at fair value through other comprehensive income
Commodity derivatives 89 (396) 154 (197)
Foreign exchange derivatives - (27) - -
89 (423) 154 (197)
Total current 145 (462) 170 (197)
Non-current
Measured at fair value through profit and loss
Commodity derivatives 1 (2) - -
Contingent consideration(1) - (52) - -
Other financial assets-investments 7 - - -
8 (54) - -
Measured at fair value through other comprehensive income
Commodity derivatives 36 (215) 112 (87)
Foreign exchange derivatives - (146) - -
36 (361) 112 (87)
Total non-current 44 (415) 112 (87)
Total current and non-current 189 (877) 282 (284)
(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
As at 31 December 2024 Level 1 Level 2 Level 3 Level 2 Level 3
$ million $ million $ million $ million $ million
Fair value of embedded derivative within gas contract - 5 - - -
Commodity derivatives - 152 - (627) -
Argentinian bonds 25 - - - -
Foreign exchange derivatives - - - (198) -
Investments - - 7 - -
Contingent consideration - - - - (52)
Total fair value 25 157 7 (825) (52)
Financial assets Financial liabilities
As at 31 December 2023 Level 1 Level 2 Level 3 Level 2 Level 3
$ million $ million $ million $ million $ million
Fair value of embedded derivative within gas contract - 10 - - -
Commodity derivatives - 266 - (284) -
Foreign exchange derivatives - 6 - - -
Total fair value - 282 - (284) -
There were no transfers between fair value levels in 2023 or 2024.
Fair value movements recognised in the income statement on financial
instruments are shown below:
Finance income 2024 2023
$ million $ million
Change in fair value of embedded derivative within gas contract - 68
Commodity derivatives 5 -
Argentinian bonds 7 -
Interest rate derivatives - (43)
12 25
Finance expenses 2024 2023
$ million $ million
Change in fair value of embedded derivative within gas contract 5 -
Foreign exchange derivatives 30 -
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.
2024 2023
As at 31 December 2024 Book value Book value Book value Book value
$ million $ million $ million $ million
USD bond (496) (499) (493) (487)
EUR bonds (4,515) (4,555) - -
Total (5,011) (5,054) (493) (487)
The fair value of the bond is within level 2 of the fair value hierarchy and
has been estimated by discounting future cash flows by the relevant market
yield curve at the balance sheet date. The fair values of other financial
instruments not measured at fair value including cash and short-term deposits,
trade receivables, trade payables and floating rate borrowings equate
approximately to their carrying amounts.
Cash flow hedge accounting
The Group uses a combination of fixed price physical sales contracts and
cash-settled fixed price commodity swaps and options to manage the price risk
associated with its underlying oil and gas revenues. As at 31 December 2024,
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 2024 2025 2026 2027
Oil
Total oil volume hedged (thousand bbls) 16,162 12,881 -
- of which swaps 15,598 12,881 -
- of which zero cost collars 564 - -
Weighted average fixed price ($/bbl) 76.47 72.88 -
Weighted average collar floor and cap ($/bbl) 60.00-86.78 - -
Natural gas
Gas volume hedged (thousand boe) 33,509 19,924 2,056
- of which swaps/fixed price forward sales 26,912 16,817 2,056
- of which zero cost collars 6,597 3,106 -
Weighted average fixed price ($/mscf) 12.91 10.79 11.29
Weighted average collar floor and cap ($/mscf) 11.46-22.50 9.04-16.71 -
As at 31 December 2024, the fair value of net commodity derivatives designated
as cash flow hedges, all executed under ISDA agreements with no margining
requirements, was a net payable of $513 million (2023: $66 million payable)
and net unrealised pre-tax losses of $487 million (2023: $16 million) were
deferred in other comprehensive income in respect of the effective portion of
the hedge relationships.
Amounts deferred in other comprehensive income will be released to the income
statement as the underlying hedged transactions occur. As at 31 December 2024,
net deferred pre-tax losses of $307 million (2023: $51 million) are expected
to be released to the income statement within one year.
Hedge ineffectiveness
The following table summarises the hedge ineffectiveness as at 31 December:
2024 2023
$ million $ million
Commodity derivatives - -
Foreign exchange derivatives 8 -
8 -
24. 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 2024 and 31 December 2023.
The sensitivity analyses have been prepared on the basis that the number of
financial instruments are all 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. Current target is to hedge
circa 50 per cent of year 1 and up to 30 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.
As at 31 December 2024 Market movement Effect on profit before tax Effect on equity
$ million $ million
Brent oil price $10 /bbl increase - (91)
Brent oil price $10 /bbl decrease - 91
NBP gas price £0.1 /therm increase - (36)
NBP gas price £0.1 /therm decrease - 36
TTF $1.5 / MMBtu increase 15 (14)
TTF $1.5 / MMBtu decrease (15) 14
THE $1.5 / MMBtu increase (15) (46)
THE $1.5 / MMBtu decrease 15 46
As at 31 December 2023 Market movement Effect on profit before tax Effect on equity
$ million $ million
Brent oil price $10 /bbl increase - (28)
Brent oil price $10 /bbl decrease - 28
NBP gas price £0.1 /therm increase - (28)
NBP gas price £0.1 /therm decrease - 28
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. The Group's exposure to the risk of changes in market interest rates
relates primarily to the Group's long-term debt obligation with floating
interest rates.
At 31 December 2024, floating rate borrowings comprise loans under the RCF
which incurs 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 comprise a $500 million high yield bond which incurs interest at
5.5 per cent per annum and bonds of €4.6 billion which incur interest at
between 0.84 per cent and 4.357 per cent per annum (see note 22). As at 31
December 2023, fixed rate borrowings comprised a bond incurring interest at
5.5 per cent per annum, and no floating rate borrowings. Floating rate
financial assets comprise cash and cash equivalents which earn interest at the
relevant market rate. Prior to settlement of the RBL, the Group monitored 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 financial instruments in place at the balance sheet date are
shown below:
Derivative Currency pair Notional amount Period of hedge Terms
31 December 2024 Cross-currency interest rate swaps USD:EUR €363 million <1 year $1.1015:€1
€1,403 million 2-5 years $1.1017-$1.1209:€1
€650 million >5 years $1.1209:€1
31 December 2023 Cross-currency interest rate swaps N/A $nil N/A N/A
The cross-currency interest rate swaps relating to the Euro bonds have been
designated as cash flow hedges where €2.4 billion was hedged at a forward
rate of between 1.1015 and 1.1209.
The interest rate and currency profile of the Group's interest-bearing
financial assets and liabilities are shown below:
As at 31 December 2024 Cash at bank Fixed rate borrowings Floating rate borrowings Total
$ 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)
As at 31 December 2023 Cash at bank Fixed rate borrowings Floating rate borrowings Total
As restated $ million $ million $ million $ million
US dollar 244 (493) - (249)
Pound sterling 28 - - 28
Norwegian krone 13 - - 13
Other 1 - - 1
286 (493) - (207)
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 at the balance sheet date.
Market movement Effect on profit before tax Effect on equity
$ million $ million
31 December 2024
US dollar interest rates +100 basis points 1 -
31 December 2023
US dollar interest rates +100 basis points 2 -
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 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 2024, the Group had:
§ £212.5 million hedged at a forward rate of between $1.2482 and $1.2774:£1
for January 2025
§ NOK 9.6 billion hedged at forward rates of between NOK 10.9805 and NOK
11.3963:£1 for the period January 2025 to May 2025
As at 31 December 2023, the Group had £212 million hedged at a forward rate
of between $1.2182 and $1.2742:£1 for the period from January 2024 to October
2024.
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 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
31 December 2023
Pound sterling 78 (78)
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 arise 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 one customer exceeds 54 per cent
(2023: 88 per cent) of the Group's consolidated revenue.
With regard to Harbour's own credit risk management it has own corporate
credit ratings from the credit rating agencies:
§ S&P Global at BBB-
§ Fitch at BBB-
§ Moody's at Baa2
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 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.
As at 1 January 2024 Additions from business combinations & joint arrangements Additions Reversals Reclass between categories Disposals FX At 31 December 2024
$ million $ million $ million $ million $ million $ million $million $ million
Trade receivables
Of which stage 2(1) - - 22 (1) - - (1) 20
Of which stage 3(2) - - - - - - - -
- - 22 (1) - - (1) 20
Other receivables
Of which stage 2(1) - - - - - - - -
Of which stage 3(2) - - 2 - - - - 2
- - 2 - - - - 2
Financial receivables
and bank balances
Of which stage 1(3) - - - - - - - -
Of which stage 2(1) - - - - - - - -
Of which stage 3(2) - - - - - - - -
- - - - - - - -
Total - - 24 (1) - - (1) 22
(1) The credit risk has increased significantly since initial recognition,
the loss allowance for the financial assets is measured at an amount equal to
the lifetime expected credit losses.
(2) The financial asset is credit impaired.
(3) The loss allowance for financial assets is measured at an amount equal
to a 12-month expected credit loss.
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:
As at 31 December 2024 Within one year 1 to 2 years 2 to 5 years Over 5 years Total
$ 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
As at 31 December 2023 Within one year 1 to 2 years 2 to 5 years Over 5 years Total
As restated $ million $ million $ million $ million $ million
Non-derivative financial liabilities
Bond 28 28 528 - 584
Other loans 16 - - - 16
Trade and other payables 854 13 - - 867
Lease obligations 250 186 340 121 897
Total non-derivative financial liabilities 1,147 227 868 121 2,364
Derivative financial liabilities
Net-settled commodity derivatives 197 87 - - 284
Net-settled foreign exchange derivatives - - - - -
1,345 314 868 121 2,648
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.
As at 31 December 2024 Gross amounts of recognised financial assets/(liabilities) Amounts set off Net amounts presented on the balance sheet
$ million $ million $ million
Commodity derivative assets 748 (596) 152
Commodity derivative liabilities (1,223) 596 (627)
As at 31 December 2023
Commodity derivative assets 303 (37) 266
Commodity derivative liabilities (321) 37 (284)
Derivatives are offset in the financial statements where the Group has a
legally enforceable right and intention to offset.
25. Share capital
2024 2023
Issued and fully paid Number $ million Number $ million
Ordinary shares of 0.002p each 1,440,109,512 0 770,370,830 0
Ordinary non-voting shares of 0.002p each 251,488,211 0 - -
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 von-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 placees, 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% 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 921,226,893 ordinary shares at a nominal
value of 0.002 pence per share. This primarily consisted of 669,714,027 voting
shares issued to BASF and 251,488,211 non-voting shares issued to LetterOne on
completion of the acquisition. The company also issued 24,655 (2023: 5,092)
ordinary shares at a nominal value of 0.002 pence per share in relation to the
exercise of SAYE awards.
The issue of the ordinary shares to BASF and LetterOne resulted in an amount
of $3,457 million that has been 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. For further
information see note 14.
Purchase and cancellation of own shares
During 2024, none of the company's ordinary shares were repurchased or
cancelled as the share buyback programme had been completed by the end of the
prior year. During 2023, the company repurchased 76,803,058 ordinary shares
for a total consideration, including transaction costs of $249 million
(recognised in retained earnings), as part of the share purchase programmes
announced on 3 November 2022 and 9 March 2023, which concluded on 28 September
2023. All shares purchased had been cancelled.
Own shares 2024 2023
$ million $ million
At 1 January 24 21
Purchase of ESOP trust shares 25 16
Release of shares (13) (13)
At 31 December 36 24
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 2024, the number of
ordinary shares of 0.002 pence each held by the trust was 9,223,652 (2023:
6,079,705).
26. 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 Wintershall Dea
acquisition transaction, at which point these bonds were ported to 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:
% Reset date Currency Nominal €million Nominal value Carrying value
$ million
$ million
Bond ISIN: XS2286041517 2.5% 2026 EUR 650 718 690
Bond ISIN: XS2286041947 3.0% 2029 EUR 850 939 873
Total 1,500 1,657 1,563
2024
$ million
Fair value on acquisition 1,548
Accrued interest in the period to 31 December 15
Nominal value on acquisition 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.
27. 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 an Expatriate SIP for expatriate employees only.
For the year ended 31 December 2024, the total cost recognised by the company
for share-based payment transactions was $51 million (2023: $46 million). A
credit of $51 million (2023: $46 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 the
time-writing system which allocates cost, based on time spent by individuals,
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:
2017 Long-term Incentive Plan (2017 LTIP)
Discretionary share awards are granted to employees under the company's
Long-Term Incentive Plan (LTIP).
The following types of award have been granted under the 2017 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 and aligns to longer-term strategic
objectives
§ 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
All LTIP awards are granted in the form of nil-cost options or conditional
share awards and therefore there is no exercise price payable on the exercise
of these awards.
The following table shows the movement in the number of LTIP awards:
2024 2023
million shares million shares
Outstanding at 1 January 33.7 27.8
Granted 15.7 15.1
Vested (2.6) (8.7)
Forfeited (9.3) (0.5)
Outstanding at 31 December(1) 37.5 33.7
(1) This includes 0.7 million cash settled awards at 31 December 2024
(2023: 0.6 million), which are revalued using the year-end share price.
LTIP awards totalling 2.6 million shares were vested during the period (2023:
8.7 million). The weighted average remaining contractual life of the LTIP
awards at 31 December 2024 was 1.33 years (2023: 2.2 years).
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:
2024 2023
Share price at date of grant £2.39-£3.22 £2.44 - £2.90
Dividend yield 0% 0%
Expected term 3 years 2.9 - 3.0 years
Risk free rate 4.1%-4.3% 3.3%-4.2%
Share price volatility of the company 47.0%-47.5% 49.2%-50.2%
The weighted average fair value of the PSA awards granted in 2024 was $1.64
(2023: $2.86).
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.
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 2024, 0.6
million matching shares were awarded to employees (2023: 0.3 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 2024, 1 million SAYE
options were granted (2023: 3.1 million).
The SAYE options outstanding at 31 December 2024 had exercise prices ranging
from £2.32 to £2.72 (2023: £2.21 to £4.12) and a weighted average
remaining contractual life of 2.25 years (2023: 2.8 years).
28. 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 are 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 participate in a capital
market-oriented defined benefit pension scheme. This scheme applies to all new
employees joining Harbour Energy and is financed by employer and employee
contributions and the performance of the investment. Typically, Harbour Energy
guarantees at least the sum of all employer and employee contributions paid
and usually covers these pension obligations with plan assets as part of an
additional contractual trust arrangement (CTA). The option of building up
employee-financed retirement provisions through deferred compensation is also
available to all employees of Harbour Energy companies in Germany as part of
the capital market-oriented defined benefit pension scheme. All other pension
plans (including deferred compensation plans) have been closed to new
employees.
The defined benefit plan of BASF Pensionskasse VVaG was closed in 2004.
Some Harbour Energy companies in Germany only participate in the BASF group's
pension plans for periods of service already rendered (past service). Some of
the past service benefits financed via BASF Pensionskasse VVaG are subject to
adjustments that must be borne by its member companies to the extent that
these cannot be borne by BASF Pensionskasse VVaG due to the regulations
imposed by the German supervisory authority. In addition to the former basic
level of BASF Pensionskasse VVaG benefits, there are still defined pension
schemes, which are financed via pension provisions at the German Group
companies. The benefits are largely based on modular plans. Only employees
who already participated in various existing deferred compensation plans
before 2022 can continue to participate in these plans.
BASF SE does not provide sufficient plan information from BASF Pensionskasse
regarding the allocation of assets to Harbour Energy for year-end closing. As
a result, the former participation in BASF Pensionskasse is accounted for as a
multi-employer defined benefit plan with insufficient information about the
asset allocation and, therefore, as a defined contribution plan in accordance
with IAS 19.36.
For further existing pension plans in Germany that are self-managed by Harbour
Energy, assets were transferred to Willis Towers Watson Treuhand GmbH within
the framework of CTAs and to Willis Towers Watson Pensionsfonds AG as
insolvency insurance. 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). Insofar as a
regulatory deficit occurs in the pension fund, supplementary payments are
requested from the employer. Irrespective of the rules, 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 plans that are recognised as pension provisions mainly
include pension promises and are hence subject to longevity risk.
Norway
The Harbour Energy Norge AS (formerly Wintershall Dea Norge) 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 (formerly Wintershall Dea 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 2024
Key assumptions (%) Germany Norway
Discount rate 3.4 3.1
Pension growth 2.3 1.8
The assumptions used to determine the present value of the entitlements as at
31 December 2024 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 2024.
Actuarial mortality tables as at 31 December 2024
Germany Heubeck Richttafeln 2018 G
Norway K2013
Provision for pensions
Defined benefit obligations Plan assets Total
$ million $ million $ million
On acquisition
Current service costs 3 - 3
Interest expense/(income) 5 (5) -
8 (5) 3
Remeasurement
Return on plan assets, excluding amounts already recognised in interest income - - -
Actuarial gains/losses
- of which effect of changes in financial assumptions 10 - 10
- of which effect of experience adjustments (3) - (3)
7 - 7
Currency effect (31) 28 (3)
Employer contribution to the funded plans - (1) (1)
Benefit payments (9) 9 -
Change of scope 493 (453) 40
As at 31 December 2024 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, $98
million relate to benefit obligations in Germany, $320 million to benefit
obligations in Corporate and $49 million to benefit obligations in Norway.
Domestic company pensions are subject to an obligation to review for
adjustments every three years pursuant to Section 16 of the German
Occupational Pension 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 20 years in
Germany, 10 years for Corporate and 15 years in Norway.
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 2024 31 December 2023
$ million $ million
Discount rate Germany Norway
Increase of 0.5 percentage points 3.4 3.1
Reduction of 0.5 percentage points
Pension growth
Increase of 0.5 percentage points
Reduction of 0.5 percentage points 2.3 1.8
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 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 -
29. Notes to the statement of cash flows
Net cash flows from operating activities consist of:
2024 2023
$ million As restated
$ million
Profit before taxation 1,219 616
Adjustments to reconcile profit before tax to net cash flows
Finance cost, excluding foreign exchange 602 363
Finance income, excluding foreign exchange (55) (104)
Depreciation, depletion and amortisation 1,745 1,449
Net impairment of property, plant and equipment 352 176
Impairment of goodwill - 25
Impairment of right-of-use asset 20 -
Share based payments 51 20
Decommissioning payments (284) (268)
Fair value movements on derivatives (68) -
Changes in provisions (31) -
Exploration costs written-off 173 57
Movement in realised cash flow hedges not yet settled (31) (207)
Unrealised foreign exchange (gain)/loss (116) 49
Working-capital adjustments
Decrease)/(increase) in inventories 39 (52)
(Increase)/decrease in trade and other receivables (32) 525
Decrease in trade and other payables (470) (61)
Net tax payments (1,499) (438)
Net cash inflow from operating activities 1,615 2,150
Reconciliation of net cash flow to movement in net borrowings
2024 2023
$ million As restated
$ million
Proceeds from drawdown of RBL facility (178) (660)
Proceeds from Euro bonds (1,728) -
Proceeds from RCF (2,225) -
Proceeds from bridge facility (1,500) -
Repayment of RBL facility 178 1,435
Repayment of bridge facility 1,500 -
Repayment of RCF 1,975 -
Repayment of EFF loan - 11
Repayment of financing arrangement 17 21
Bond debt arising on business combination(1) (3,038) -
Financing arrangement interest payable (1) (3)
Arrangement fees and related costs on RBL capitalised - 34
Arrangement fees and related costs on bonds capitalised 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 (102) (48)
Currency translation adjustment on Euro bonds 263 -
Movement in total borrowings (4,781) 790
Cash acquired on business combination 748 -
Movement in cash and cash equivalents (229) (214)
(Increase)/decrease in net borrowings in the year (4,262) 576
Opening net borrowings (162) (738)
Closing net borrowings (4,424) (162)
(1) Net of capitalised arrangement fees and related costs of $276 million.
Analysis of net borrowings
2024 2023
$ million As restated
$ million
Cash and cash equivalents 805 286
RCF (218) -
Bonds (5,011) (493)
Net debt (4,424) (207)
Financing arrangement - (16)
Closing net borrowings (4,424) (223)
Non-current assets(1) - 42
Current assets(1) - 19
Closing net borrowings before unamortised fees(1) (4,424) (162)
(1) At 31 December 2023, $61 million of fees associated with the RBL
facility were recognised in debtors.
The carrying values on the balance sheet are stated net of the unamortised
portion of issue costs and bank fees of $284 million of which $32 million
relates to the RCF and $252 million is netted against the bonds (Dec 2023: $68
million of which $61 million related to the RBL, which was recognised in
assets and $7 million related to the bond, which was netted off against the
borrowings).
30. 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 holding 669.7 million of voting ordinary shares and
251.5 million of non-voting ordinary shares, respectively. The BASF
shareholding represents 46.5 per cent of voting ordinary shares.
BASF is entitled to dividends as per note 31 which, whilst denominated in
pound sterling will, specifically for BASF, will 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:
2024 2023
$ million $ million
Salaries and short-term employee benefits 16 13
Payments made in lieu of pension contributions 1 1
Termination benefits 1 -
Pension benefits - -
18 14
31. Distributions made and proposed
A final dividend of 13 cents per ordinary share in relation to the year ended
31 December 2023 was paid on 22 May 2024 pursuant to shareholder approval
received on 9 May 2024.
An interim dividend of 13 cents per ordinary share in relation to the half
year ended 30 June 2024 was paid on 25 September 2024.
2024 2023
$ million $ million
Cash dividends on ordinary shares declared and paid
Final dividend for 2023: 13 cents per share (2022: 12 cents per share) 100 99
Interim dividend for 2024: 13 cents per share (2023: 12 cents per share) 99 91
199 190
Proposed dividends on ordinary shares
Final dividend for 2024: 13.19 cents per share (2023: 13 cents per share) 227.5 100
Proposed dividends on ordinary shares are subject to approval at the annual
general meeting and are not recognised as a liability as at 31 December.
32. Events after the reporting period
On 23 January 2025 Harbour announced it had signed a Sale and Purchase
Agreement to sell its Vietnam business, which includes the 53.125 per cent
equity interest in the Chim Sáo and Dua production fields, to EnQuest for $84
million. The effective date is 1 January 2024 with completion targeted during
2025. This agreement resulted in the Vietnam business unit being classed as
asset held for sale as at 31 December 2024.
On 3 March 2025, the Finance Act 2025 was substantively enacted following its
third reading in the UK Parliament. While the substantive enactment has no
implications for the current accounting period, it confirms that the extension
of the Energy Profits Levy to 31 March 2030 will be reflected in the Group's
results for the interim period to 30 June 2025. If the Finance Act 2025 had
been substantively enacted at the balance sheet date, the deferred tax
liability at the end of the period would have increased by $306 million
(further details are provided in note 8).
33. Group information
Subsidiary undertakings of the company which were all wholly owned at 31
December 2024 were:
Name of Company Area of operation Country of incorporation Main activity
Chrysaor (U.K.) Alpha Limited(17) UK UK Exploration, production, and development
Chrysaor (U.K.) Beta Limited(17) UK UK Decommissioning activities
Chrysaor (U.K.) Sigma Limited(17) UK UK Exploration, production, and development
Chrysaor (U.K.) Theta Limited(17) UK UK Exploration, production, and development
Chrysaor CNS Limited(17) UK UK Exploration, production, and development
Chrysaor Developments Limited(17) UK UK Decommissioning activities
Chrysaor E&P Limited(17) UK UK Intermediate holding company
Chrysaor Holdings Limited(7) UK Cayman Islands Intermediate holding company
Chrysaor Limited(17) UK UK Exploration, production, and development
Harbour Energy Marketing Limited(17) UK UK Gas trading
Chrysaor North Sea Limited(17) UK UK Exploration, production, and development
Chrysaor Petroleum Company U.K. Limited(17) UK UK Exploration, production, and development
Chrysaor Petroleum Limited(17) UK UK Decommissioning activities
Chrysaor Production (U.K.) Limited(17) UK UK Exploration, production, and development
Chrysaor Production Holdings Limited(17) UK UK Intermediate holding company
Chrysaor Resources (Irish Sea) Limited(17) UK UK Exploration, production, and development
DEA Cyrenaica GmbH(8) Libya Germany Exploration, production, and development
DEA E&P GmbH(8) Germany Germany Exploration, production, and development
DEA North Africa/Middle East GmbH(8) North Africa Germany Exploration, production, and development
DEM México Erdoel, S.A.P.I. de C.V.(14) Mexico Mexico Intermediate holding company
E&A Internationale Explorations-und Produktions GmbH(20) Germany Germany Exploration, production, and development
Ebury Gate Limited(9) Guernsey Guernsey Risk mitigation services
EnCore Oil Limited(17) UK UK Intermediate holding company
FP Mauritania A BV(11) Mauritania Netherlands Decommissioning activities
FP Mauritania B BV(11) Mauritania Netherlands Decommissioning activities
Harbour Energy Bloque 7, S.A. de C.V. (formerly Premier Oil Exploration and Mexico Mexico Exploration, production, and development
Production Mexico S.A.de C.V.)(15)
Harbour Energy DH GmbH(21) Germany Germany Intermediate holding company
Harbour Energy Finance Limited(17) UK UK Financing company
Harbour Energy Netherlands Holdings BV(11) Netherlands Netherlands Intermediate holding company
Harbour Energy Norge AS (formerly Wintershall Dea Norge AS)(12,22) Norway Norway Exploration, production, and development
Harbour Energy Services Limited(17) UK UK Service company
Harbour Energy Unidad Zama, S. de R.L. de C.V (formerly Sierra O&G Mexico Mexico Exploration, production, and development
Exploration y Produccion, S. de R.L de C.V.)(14)
Izta Energia, S. de R.L. de C.V.(14) Mexico Mexico Intermediate holding company
Premier Oil (Vietnam) Limited(4) Vietnam British Virgin Islands Exploration, production, and development
Premier Oil Aberdeen Services Limited(17) UK UK Service company
Premier Oil and Gas Services Limited(17) UK UK Service company
Premier Oil Andaman I Limited(17) Indonesia UK Exploration, production, and development
Premier Oil Andaman Limited(17) Indonesia UK Exploration, production, and development
Premier Oil Barakuda Limited(17) Indonesia UK Exploration, production, and development
Premier Oil E&P Holdings Limited(17) UK UK Intermediate holding company
Premier Oil E&P UK EU Limited(17) UK UK Exploration, production, and development
Premier Oil E&P UK Limited(17) UK UK Exploration, production, and development
Premier Oil Exploration (Mauritania) Limited(13) Mauritania Jersey Decommissioning activities
Premier Oil Group Holdings Limited(1,17) UK UK Intermediate holding company
Premier Oil Group Limited(19) UK UK Intermediate holding company
Premier Oil Holdings Limited(17) UK UK Intermediate holding company
Premier Oil Mauritania B Limited(13) Mauritania Jersey Decommissioning activities
Premier Oil Mexico Holdings Limited(17) UK UK Intermediate holding company
Premier Oil Mexico Investments Limited(17) UK UK Intermediate holding company
Premier Oil Mexico Recursos S.A. de C.V.(15) Mexico Mexico Exploration, production, and development
Premier Oil Natuna Sea BV(11) Indonesia Netherlands Exploration, production, and development
Premier Oil Overseas BV(11) Netherlands Netherlands Intermediate holding company
Premier Oil South Andaman Limited(17) Indonesia UK Exploration, production, and development
Premier Oil Tuna BV(11) Indonesia Netherlands Exploration, production, and development
Premier Oil UK Limited(19) UK UK Exploration, production, and development
Premier Oil Vietnam Offshore BV(11) Vietnam Netherlands Exploration, production, and development
Servicios Unidad PWTH S. De R.L. de C.V(14) Mexico Mexico Service company
Sierra Blanca P&D, S. de R.L de C.V.(14) Mexico Mexico Exploration, production, and development
Sierra Coronado E&P, S. de R.L de C.V. (14) Mexico Mexico Exploration, production, and development
Sierra Nevada E&P, S. de R.L de C.V. (14) Mexico Mexico Exploration, production, and development
Sierra Offshore Exploration, S. de R.L de C.V. (14) Mexico Mexico Exploration, production, and development
Sierra Oil & Gas Holdings, L.P(6) Mexico Canada Intermediate holding company
Sierra Oil & Gas S.de R.L. de C.V(14) Mexico Mexico Exploration, production, and development
Sierra Perote E&P, S. de R.L de C.V.(14) Mexico Mexico Exploration, production, and development
Wintershall Dea Algeria GmbH(8) Algeria Germany Exploration, production, and development
Wintershall Dea Argentina S.A(2) Argentina Argentina Exploration, production, and development
Wintershall Dea Deutschland GmbH(8) Germany Germany Exploration, production, and development
Wintershall Dea Finance 2 BV (1)(11) Netherlands Netherlands Financing company
Wintershall Dea Finance BV (1)(11) Netherlands Netherlands Financing company
Wintershall Dea Global Holding GmbH(8) Germany Germany Exploration, production, and development
Wintershall Dea Global Support(11) Netherlands Netherlands Service company
Wintershall Dea Holding GmbH(8) Germany Germany Exploration, production, and development
Wintershall Dea Insurance Limited(10) Guernsey Guernsey Risk mitigation services
Wintershall Dea International GmbH(8) Germany Germany Exploration, production, and development
Wintershall Dea Marketing Services GmbH(20) Germany Germany Distribution, transportation and trade
Wintershall Dea Mexico Holding BV(11) Mexico Netherlands Intermediate holding company
Wintershall DEA Mexico Holdings GP Ltd(5) Mexico Canada Intermediate holding company
Wintershall DEA México, S. de R.L. de C.V.(14) Mexico Mexico Exploration, production, and development
Wintershall Dea Middle East GmbH(20) United Arab Emirates Germany Exploration, production, and development
Wintershall Dea Nederland BV(11) Netherlands Netherlands Servicing and financing company
Wintershall Dea Nile GmbH(8) Egypt Germany Exploration, production, and development
Wintershall Dea South East Asia GmbH(20) Germany Germany Exploration, production, and development
Wintershall Dea Suez GmbH(8) Egypt Germany Exploration, production, and development
Wintershall Dea Technology Ventures GmbH(20) Germany Germany Investment company
Wintershall Dea TSC GmbH & Co.KG(8) Germany Germany Research and development
Wintershall Dea TSC Management GmbH(20) Germany Germany Research and development
Wintershall Dea Vermögensverwaltungs gesellschaft mbH(20) Germany Germany Intermediate holding company
Wintershall Dea WND GmbH(8) Egypt Germany Exploration, production, and development
Wintershall Petroleum (E&P) BV(11) Netherlands Netherlands Exploration, production, and development
Chrysaor (U.K.) Britannia Limited(17) - UK Dormant company
Chrysaor (U.K.) Lambda Limited(16) - Ireland Dormant company
DEA Trinidad & Tobago GmbH(8) - Germany Non-trading
EnCore (NNS) Limited(17) - UK Non-trading
Harbour Energy Argentina Limited(17) - UK Dormant company
Harbour Energy Central Andaman Limited (formerly Premier Oil B Limited)(17) - UK Dormant company
Harbour Energy Developments Limited(17) - UK Dormant company
Harbour Energy Production Limited(17) - UK Dormant company
Harbour Energy Secretaries Limited(17) - UK Dormant company
Premier Oil (EnCore Petroleum) Limited(17) - UK Non-trading
Premier Oil ANS Limited(17) - UK Non-trading
Premier Oil do Brasil Petroleo e Gas Ltda(3) - Brazil Dormant company
Premier Oil Exploration Limited(19) - UK Non-trading
Premier Oil Far East Limited(17) - UK Non-trading
Premier Oil ONS Limited(17) - UK Dormant company
Premier Oil Pakistan Offshore BV(11) - Netherlands Dormant company
Premier Oil Vietnam 121 Limited(17) - UK Non-trading
Viking CCS Limited(17) - UK Dormant company
Chrysaor (U.K.) Delta Limited(17) - UK Liquidation
Chrysaor (U.K.) Eta Limited(17) - UK Liquidation
Chrysaor (U.K.) Zeta Limited(17) - UK Liquidation
Chrysaor Production Limited(18) - UK Liquidation
Chrysaor Resources (UK) Holdings Limited(17) - UK Liquidation
Premier Oil ANS Holdings Limited(18) - UK Liquidation
Premier Oil Congo (Marine IX) Limited(13) - Jersey Liquidation
Premier Oil Exploration ONS Limited(18) - UK Liquidation
Premier Oil Finance (Jersey) Limited(1,13) - Jersey Liquidation
Note:
(1) Held directly by the company. All other companies are held through a
subsidiary undertaking.
(2) Registered office - Ingeniero Della Paolera 265 Piso 14 Ciudad de
Buenos Aires, C1001ADA Argentina.
(3) Registered office - Rua Lauro Müller, 116 - Sala 2006, Torre Rio Sul,
Shopping, 20º andar, Botafogo, Rio de Janeiro - RJ - CEP: 22.290-906, Brazil.
(4) Registered office - Commerce House, Wickhams Cay 1, Road Town,
Tortola, VG1110.
(5) Registered office - 181 Bay Street, Suite 2100, Toronto, ON M5J 2T3,
Canada.
(6) Registered office - 44 Chipman Hill, Suite 1000, Saint John, NB E2L
2A9, Canada.
(7) Registered office - Cricket Square, Hutchins Drive, PO Box 2681, Grand
Cayman, KY1-1111.
(8) Registered office - Hamburg, Germany, business address: Am Lohsepark
8, 20457 Hamburg.
(9) Registered office - Level 5, Mill Court, La Charroterie, St Peter
Port, Guernsey, GY1 1EJ.
(10) Registered office - Level 3,Mill Court, La Charroterie, St Peter Port,
Guernsey, GY1 4ET.
(11) Registered office - Lange Kleiweg 56H, 2288 GK, Rijswijk, Netherlands.
(12) Jåttåflaten 27, 4020 Stavanger, Norway.
(13) 2nd Floor, Lime Grove House, Green Street, St. Helier, JE2 4UB, Jersey.
(14) Registered office - Campos Eliseos 345, floor 12, Polanco V Seccion,
Mexico City, CP 11560, Mexico.
(15) Registered office - Presidente Masaryk 111, Piso 1, Polanco V Seccion,
Mexico City, CP 11560, Mexico.
(16) Registered office - Riverside One, Sir John Rogerson's Quay, Dublin 2,
Ireland.
(17) 151 Buckingham Palace Road, London, SW1W 9SZ, United Kingdom.
(18) C/O Teneo Financial Advisory Limited The Colmore Building, 20 Colmore
Circus Queensway, Birmingham, B4 6AT, United Kingdom.
(19) Registered office - 4th Floor, Saltire Court, 20 Castle Terrace,
Edinburgh, EH1 2EN, United Kingdom.
(20) Registered office - Kassel, Germany, business address: Am Lohsepark 8,
20457 Hamburg, Germany.
(21) Registered office - Frankfurt am Main, Germany, business address: Am
Lohsepark 8, 20457 Hamburg, Germany.
(22) The companies Harbour Energy Norge AS and Wintershall Dea Norge AS
merged in December 2024.
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
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
Earth Science Analytics AS 13.5 Strandveien 37, 1366, Lysaker, Norway
Gasoducto Cruz del Sur S.A. 10 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.
Group reserves and resources
Oil and gas 2P reserves and 2C resources(1
)
2P reserves 2P reserves(5) (entitle-ment) 2C resources (working interest)
(working interest)
1 January 2024 mmboe Acquisi-tions(3) mmboe Revisions(4) Produc-tion 31 Dec 2024 mmboe 31 Dec 2024 mmboe 31 Dec 2024 mmboe
mmboe
mmboe
Norway Oil and NGLs - 179 - (7) 172 172 150
Gas(2) - 297 - (12) 285 285 158
Total - 477 - (19) 458 458 308
UK Oil and NGLs 183 - (3) (27) 153 153 91
Gas(2) 161 - 9 (28) 142 142 52
Total 343 - 6 (55) 295 295 143
Argentina Oil and NGLs - 21 - (1) 20 20 91
Gas(2) - 243 - (7) 236 236 680
Total - 264 - (8) 256 256 770
Germany Oil and NGLs - 95 - (2) 92 92 16
Gas(2) - 35 - (1) 34 34 27
Total - 130 - (4) 126 126 43
North Africa Oil and NGLs - 9 - (1) 8 6 5
Gas(2) - 48 - (4) 44 30 25
Total - 57 - (4) 52 36 30
Mexico Oil and NGLs - 40 - (1) 39 25 386
Gas(2) - 8 - (0) 8 7 18
Total - 48 - (1) 47 31 405
Southeast Asia Oil and NGLs 7 - 0 (2) 6 4 44
Gas(2) 10 - 0 (2) 8 6 167
Total 18 - 1 (4) 14 10 211
Total Oil and NGLs 190 343 (2) (40) 491 472 783
Gas(2) 171 632 9 (55) 758 740 1,127
Total 361 976 7 (94) 1,249 1,212 1,910
(1) The volumes in the above table reflect internal estimates. DeGolyer
and MacNaughton (D&M) audited by means of independent assessment a
substantial proportion of the asset base, covering 90 per cent of working
interest 2P reserves and over 70 per cent of working interest 2C resources.
D&M 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 be 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 be 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 per
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 acquisition of Wintershall Dea assets that
completed on 3 September 2024.
(4) 2P reserves revisions include both changes from re-estimation and
additions. The overall revision predominantly reflects additions made for
activity in the Elgin and AELE hubs, in the UK, obtaining approvals in 2024.
Revisions based on re-estimates account for less the one percent change to the
reserves volume for the UK and Southeast Asia.
(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(2)
million tonnes million tonnes
31 December 2024 31 December 2024
Norway 0.4 220.8
UK - 390.9
Denmark - 25.4
Total(3) 0.4 659.1
(1) All numbers are representative of Harbour's working interest.
(2 ) Total includes resources associated with two area in the Netherlands,
where there is currently no storage licence in place. Harbour has a
cooperation agreement to evaluate CCS storage on Q1-B and P6-AB which are
subject to production licences. The nature of licencing for CCS in the
Netherlands means that storage licences are not required for exploration stage
CCS evaluation where there is a producing licence.
(3) The volumes in the above table reflect internal estimates. AGR Energy
Services AS (AGR) have provided a competent persons report over the Havstjerne
and Luna 2C resources in Norway. ERCE Equipoise Ltd (EQR) have provided a
competent persons report over the Viking 2C resources in the UK. The resources
that have been independently assessed amount to c.70% of the total Harbour
storage resources, the independent assessment of these resources is not
materially different in the aggregate volume to the internal Harbour estimates
for these assets (<5%).
Non-IFRS measures
Harbour uses certain measures of performance that are not specifically defined
under IFRS or other generally accepted accounting principles (GAAP). These
non-IFRS measures, which are presented within the Financial review, are
defined below:
Capital investment: Depicts how much the Group has spent on purchasing fixed
assets in order to further its business goals and objectives. It is a useful
indicator of the Group's organic expenditure on oil and gas assets, and
exploration and appraisal assets, incurred during a period.
DD&A per barrel: Depreciation and amortisation of oil and gas properties
for the period divided by working interest production. This is a useful
indicator of ongoing rates of depreciation and amortisation of the Group's
producing assets.
EBITDAX: Earnings before tax, interest, depreciation and amortisation,
impairments, remeasurements, onerous contracts and exploration expenditure.
This is a useful indicator of underlying business performance.
Free cash flow: Operating cash flow less cash flow from investing activities
(exclusive of net expenditure on business combinations) less interest and
lease payments (principal and interest).
Leverage ratio: Net debt/ last twelve months EBITDAX.
Liquidity: The sum of cash and cash equivalents on the balance sheet and the
undrawn amounts available to the Group on our principal facilities. This is a
key measure of the Group's financial flexibility and ability to fund
day-to-day operations.
Net debt: Total 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.
Operating cost per barrel: Direct operating costs (excluding over/underlift)
for the period, including tariff expense, insurance costs and mark to market
movements on emissions hedges, less tariff income, divided by working interest
production. This is a useful indicator of ongoing operating costs from the
Group's producing assets.
Shareholder returns paid: Dividends plus share buybacks completed in the
period are included in this metric which shows the overall value returned to
stakeholders in the period.
Total capital expenditure: Capital investment 'additions' per notes 11 and 12
plus decommissioning expenditure 'amounts used' per note 21.
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
(1) See Glossary for the definition of non-IFRS measures used in this section.
2 (#_ftnref2) Difference to the final dividend value declared of $100
million is due to foreign exchange adjustments on sterling denominated shares
at the date of payment.
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